As filed with the Securities and Exchange Commission on
April 1, 2010
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION
STATEMENT
UNDER
THE SECURITIES ACT OF
1933
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ECA Marcellus Trust I
(Exact name of co-registrant
as specified in its charter)
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Energy Corporation of America
(Exact name of co-registrant
as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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West Virginia
(State or other jurisdiction
of incorporation or organization)
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1311
(Primary Standard Industrial
Classification Code Number)
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1311
(Primary Standard Industrial
Classification Code Number)
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27-6522024
(I.R.S. Employer
Identification No.)
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84-1235822
(I.R.S. Employer
Identification No.)
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1209 Orange Street
Wilmington, Delaware 19801
(303) 694-2667
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4643 South Ulster Street
Suite 1100
Denver, Colorado 80237
(303) 694-2667
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(Address, including zip code,
and telephone number,
including area code, of agent of service)
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(Address, including zip code,
and telephone number,
including area code, of agent of service)
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Michael S. Fletcher
4643 South Ulster Street
Suite 1100
Denver, Colorado 80237
(303) 694-2667
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Donald C. Supcoe
4643 South Ulster Street
Suite 1100
Denver, Colorado 80237
(303) 694-2667
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(Name, address, including zip
code, and telephone number,
including area code, of agent for service)
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(Name, address, including zip
code, and telephone number,
including area code, of agent for service)
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Approximate date of commencement of proposed sale to the
public:
As soon as practicable after this Registration Statement becomes
effective.
Copies to:
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David P. Oelman
Vinson & Elkins L.L.P.
First City Tower
1001 Fannin Street, Suite 2500
Houston, Texas
77002-6760
(713) 758-2222
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Thomas R. Goodwin
Tammy J. Owen
Goodwin & Goodwin, LLP
300 Summers Street
Suite 1500
Charleston, West Virginia 25301
(304) 346-7000
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Joshua Davidson
Baker Botts L.L.P.
One Shell Plaza
910 Louisiana St.
Houston, Texas 77002
(713) 229-1234
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If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box.
o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering.
o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2
of the
Exchange Act. (Check one):
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Large accelerated
filer
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Accelerated
filer
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Non-accelerated
filer
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Smaller reporting
company
o
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(Do not check if a smaller reporting company)
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CALCULATION
OF REGISTRATION FEE
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Proposed Maximum
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Amount of
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Title of Each Class of
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Aggregate
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Registration
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Securities to be Registered
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Offering Price (1)(2)
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Fee
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Units of Beneficial Interest in ECA Marcellus Trust I
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$217,350,000
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$15,498
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(1)
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Includes common units issuable upon
exercise of the underwriters over-allotment option.
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(2)
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Estimated solely for the purpose of
calculating the registration fee pursuant to Rule 457(o).
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The Registrants hereby amend this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrants shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act, or until this Registration Statement
shall become effective on such date as the Securities and
Exchange Commission (or the SEC), acting pursuant to
said Section 8(a), may determine.
The information in
this preliminary prospectus is not complete and may be changed.
These securities may not be sold until the registration
statement filed with the Securities and Exchange Commission is
effective. This preliminary prospectus is not an offer to sell
these securities, and we are not soliciting an offer to buy
these securities, in any jurisdiction where the offer or sale is
not permitted.
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Subject to Completion dated
April 1, 2010
PRELIMINARY PROSPECTUS
ECA
Marcellus Trust I
9,000,000 Common
Units
This is an initial public offering of common units representing
beneficial interests in ECA Marcellus Trust I. The trust is
selling all of the units offered hereby. Energy Corporation of
America (ECA) has formed the trust and will convey
certain royalty interests and natural gas hedging contracts to
the trust in exchange for a distribution from the net proceeds
of this offering as well as common and subordinated units
representing a 50% beneficial interest in the trust.
Prior to this offering, there has been no public market for the
common units. ECA expects that the public offering price will be
between $ and
$ per common unit. The trust
intends to apply to have the common units approved for listing
on the New York Stock Exchange under the symbol ECT.
The Trust Units.
Trust units, consisting of the
common and subordinated units, are units of beneficial interest
in the trust and represent undivided interests in the trust.
They do not represent any interest in ECA.
The Trust.
The trust will own term and perpetual royalty
interests in natural gas properties owned by ECA in the
Marcellus Shale formation in Greene County, Pennsylvania. These
royalty interests will entitle the trust to receive 90% of the
proceeds attributable to ECAs interest in the sale of
production from 14 producing horizontal Marcellus Shale natural
gas wells located in Greene County, Pennsylvania and 50% of the
proceeds attributable to ECAs interest in the sale of
production from 52 horizontal Marcellus Shale natural gas
development wells to be drilled on drill sites included within
approximately 9,300 net acres held by ECA in Greene County,
Pennsylvania. The trust will be treated as a partnership for
federal income tax purposes.
The Trust Unitholders.
As a trust unitholder, you
will receive quarterly distributions of cash from the proceeds
that the trust receives from ECAs sale of natural gas
subject to the royalty interests held by the trust.
Investing in the common units involves a high degree of risk.
Before buying any common units, you should read the discussion
of material risks of investing in the common units in Risk
factors beginning on page 16 of this prospectus.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
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Per Common Unit
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Total
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Price to the public
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$
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$
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Underwriting discounts and commissions
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$
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$
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Proceeds to the trust (before expenses)
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$
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$
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The underwriters may also purchase up to an additional
1,350,000 common units at the initial public offering price,
less underwriting discounts and commissions, to cover
over-allotments, if any, within 30 days of the date of this
prospectus. If the underwriters exercise this option in full,
the total underwriting discounts and commissions will be
$ , and the trusts total
proceeds, after deducting underwriting discounts and commissions
and before expenses, will be $ .
The net proceeds of any exercise of the underwriters
over-allotment option will be used to redeem an equal number of
common units held by ECA.
The underwriters are offering the common units as set forth
under Underwriting. Delivery of the common units
will be made on or
about ,
2010.
Joint Bookrunning Managers
, 2010
TABLE OF
CONTENTS
Important
Notice About Information in This Prospectus
You should rely only on the information contained in this
prospectus.
Until ,
2010 (25 days after the date of this prospectus), federal
securities laws may require all dealers that effect transactions
in the common units, whether or not participating in this
offering, to deliver a prospectus. This is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
ECA and the trust have not, and the underwriters have not,
authorized anyone to provide you with additional or different
information. If anyone provides you with additional, different
or inconsistent information, you should not rely on it. This
prospectus is not an offer to sell or a solicitation of an offer
to buy the common units in any jurisdiction where such offer and
sale would be unlawful. You should not assume that the
information contained in this prospectus is accurate as of any
date other than the date on the front of this document. The
trusts business, financial condition, results of
operations and prospects may have changed since such dates or in
any free writing prospectus we may authorize to be delivered to
you.
i
SUMMARY
This summary provides a brief overview of information
contained elsewhere in this prospectus. To understand this
offering fully, you should read the entire prospectus carefully,
including the risk factors and the financial statements and
notes to those statements. Definitions for terms relating to the
natural gas business can be found in Glossary of certain
oil and natural gas terms and terms related to the trust.
Ryder Scott Company, L.P., an independent engineering firm,
provided the estimates of proved natural gas reserves as of
March 31, 2010 included in this prospectus. These estimates
are contained in a summary prepared by Ryder Scott of its
reserve report as of March 31, 2010 for the Underlying
Properties held by ECA described below and for the royalty
interests in the Underlying Properties held by the trust, which
royalty interests are referred to herein as the trust
properties. This summary is located at the back of this
prospectus as Annex A and is referred to in this prospectus
as the reserve report. References to Energy
Corporation of America or ECA in this
prospectus are to Energy Corporation of America and its
subsidiaries and, when discussing unit ownership and historical
ownership of the royalty interests, includes the private
investors listed in Certain Transactions (such
private investors being referred to herein as the Private
Investors). Unless otherwise indicated, all information in
this prospectus assumes an initial public offering price of
$ per common unit and no exercise of the
underwriters over-allotment option.
ECA
Marcellus Trust I
ECA Marcellus Trust I is a Delaware statutory trust formed
in March 2010 by Energy Corporation of America to own royalty
interests in 14 producing horizontal natural gas wells producing
from the Marcellus Shale formation and located in Greene County,
Pennsylvania (the Producing Wells) and royalty
interests in 52 horizontal natural gas development wells to be
drilled to the Marcellus Shale formation (the PUD
Wells) within the Area of Mutual Interest, or
AMI, comprised of 9,300 net acres held by ECA
in Greene County, Pennsylvania. The royalty interests will be
conveyed from ECAs working interest in the Producing Wells
and the PUD Wells limited to the Marcellus Shale formation (the
Underlying Properties). The royalty interest in the
Producing Wells (the PDP Royalty Interest) entitles
the trust to receive 90% of the proceeds (after deducting
post-production costs and any applicable taxes) from the sale of
production of natural gas attributable to ECAs interest in
the Producing Wells. The royalty interest in the PUD Wells (the
PUD Royalty Interest) entitles the trust to receive
50% of the proceeds (after deducting post-production costs and
any applicable taxes) from the sale of production of natural gas
attributable to ECAs interest in the PUD Wells.
Approximately 50% of the estimated natural gas production
attributable to the trusts royalty interests will be
hedged from April 1, 2010 to March 31, 2014. These
hedging contracts will be transferred to the trust by ECA, and
ECA will be entitled to recoup the costs of establishing the
hedging contracts to the extent cash available for distribution
by the trust exceeds certain levels. Please see Target
Distributions and Subordination and Incentive Thresholds.
ECA is obligated to use commercially reasonable efforts to drill
all of the PUD Wells by March 31, 2013. In the event of
delays, ECA will have until March 31, 2014 to fulfill its
drilling obligation. ECA will grant to the trust a lien on
ECAs retained interest in the AMI in order to secure the
estimated amount of the drilling costs for the trusts
interests in the PUD Wells (the Drilling Support
Lien). The amount obtained by the trust pursuant to the
Drilling Support Lien may not exceed $91 million, and this
amount will be proportionately reduced as ECA fulfills its
drilling obligation over time. The Drilling Support Lien is
nonrecourse to ECA.
The trust will not be responsible for any costs related to the
drilling of development wells or any other development or
operating costs. The trusts cash receipts in respect of
the royalties will be determined after deducting post-production
costs and any applicable taxes associated with the
1
PDP and PUD Royalty Interests, and the trusts cash
available for distribution will include cash receipts from its
hedging contracts and will be reduced by trust administrative
expenses and expenses incurred as a result of being a publicly
traded entity. Post-production costs will generally consist of
costs incurred to gather, compress, transport, process, treat,
dehydrate and market the natural gas produced. Any charge
payable to ECA for such
post-production
costs on its Greene County Gathering System will be limited to
$0.52 per MMBtu gathered until ECA has fulfilled its drilling
obligation (the Post-Production Services Fee);
thereafter, ECA may increase the
Post-Production
Services Fee to the extent necessary to recover certain capital
expenditures in the Greene County Gathering System.
As of March 31, 2010 and after giving effect to the
conveyance of the PDP Royalty Interest and the PUD Royalty
Interest, the total gas reserves estimated to be attributable to
the trust interests were 104.6 Bcf. This amount includes
72.4 Bcf attributable to the PUD Royalty Interest and
32.2 Bcf attributable to the PDP Royalty Interest.
ECAs retained interest in the Underlying Properties
entitles it to 10% of the proceeds from the sale of natural gas
from the Producing Wells as well as 50% of the proceeds from the
sale of future production from the PUD Wells. After giving
effect to the trusts royalty interests that burden
ECAs working interests in the Underlying Properties and
taking into account the ownership by ECA of 43% of the trust
units, ECA and its affiliates will retain an approximate 66%
average economic interest in the Underlying Properties. ECA
operates all of the Producing Wells and will agree to operate
not less than 90% of the PUD Wells during the subordination
period as defined below. In addition, ECA has agreed to operate
the gas properties to which the PDP Royalty Interest and the PUD
Royalty Interest relate and to cause to be marketed natural gas
produced from these properties in the same manner it would if
such properties were not burdened by the trusts royalty
interests.
The trust will make quarterly cash distributions of
substantially all of its cash receipts, after deducting trust
administrative expenses and the costs incurred as a result of
being a publicly traded entity, on or about 60 days
following the completion of each quarter through (and including)
the quarter ending March 31, 2030 (the Termination
Date). The first quarterly distribution is expected to be
made on or about August 31, 2010 to record unitholders as
of August 15, 2010. The trust will begin to liquidate on
the Termination Date and will soon thereafter wind up its
affairs and terminate. At the Termination Date, 50% of each of
the PDP Royalty Interest and the PUD Royalty Interest will
revert automatically to ECA. The remaining 50% of each of the
PDP Royalty Interest and the PUD Royalty Interest will be sold,
and the net proceeds therefrom will be distributed pro rata to
the unitholders soon after the Termination Date. ECA will have a
first right of refusal to purchase the remaining 50% of the
royalty interests at the Termination Date. Because payments to
the trust will be generated by depleting assets and the trust
has a finite life with the production from the Underlying
Properties diminishing over time, a portion of each distribution
will represent a return of your original investment.
The business and affairs of the trust will be managed by the
trustee. Although ECA will operate all of the Producing Wells
and substantially all of the PUD Wells, ECA has no ability to
manage or influence the management of the trust.
TARGET
DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE
THRESHOLDS
Subordination
and Incentive Thresholds
ECA has calculated quarterly target levels of cash distributions
for the life of the trust as set forth on Annex B to this
prospectus. The amount of the quarterly distributions may
fluctuate from quarter to quarter, depending on the proceeds
received by the trust, among other factors.
2
Annex B reflects that while target distributions increase
as ECA completes its drilling obligations and production
attributable to the trust increases, over time these target
distributions decline as a result of the depletion of the
reserves in the Underlying Properties. These target
distributions do not represent the actual distributions
you should expect to receive with respect to your common units.
Rather, the trust has established the target distributions in
part to calculate the subordination and incentive thresholds
described in more detail below. The target distributions were
derived by assuming that natural gas production from the trust
properties will equal the volumes reflected in the reserve
report attached as Annex A to this prospectus and the
prices received for such production will equal NYMEX forward
pricing as of March 11, 2010 for the thirty-six month
period ending March 31, 2013 and increased thereafter by a
2.5% annual escalator (as adjusted for a basis differential of
$0.15 per MMBtu), capped at $9.00 per MMBtu starting in 2025.
The target distributions also give effect to post-production
expenses projected in the reserve reports and projected trust
administrative expenses, including the expenses incurred as a
result of being a publicly traded entity. For more information
on subordination and incentive thresholds, please read
Target Distributions below.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,500,000 of the trust
units it will retain following this offering, which will
constitute 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust if and to the extent there is
sufficient cash to provide a cash distribution on the common
units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated in order to make a distribution, to the extent
possible, of up to the subordination threshold amount on the
common units. Each applicable quarterly subordination threshold
is equal to 80% of the target distribution level for the
corresponding quarter as reflected on Annex B (each, a
subordination threshold). In exchange for agreeing
to subordinate these trust units, and in order to provide
additional financial incentive to ECA to perform its drilling
obligation and operations on the Underlying Properties in an
efficient and cost-effective manner, ECA will be entitled to
receive incentive distributions (the incentive
distributions) equal to 50% of the amount by which the
cash available for distribution on all of the trust units in any
quarter exceeds 150% of the subordination threshold for such
quarter (which is 120% of the target distribution for such
quarter) (each, an incentive threshold). ECAs
right to receive this incentive distribution will terminate upon
the expiration of the subordination period.
ECA has incurred costs of approximately $5 million in
securing the hedging contracts to be transferred to the trust.
ECA will be entitled to reimbursement for these expenditures
only if and to the extent distributions to trust unitholders
would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to the trust unitholders. ECAs right to
receive the remaining 50% of such cash in the form of incentive
distributions would not be affected.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it is transferring to
the trust. The trust currently expects that ECA will complete
its drilling obligation on or before March 31, 2013 and
that, accordingly, the subordinated units will convert into
common units on or before March 31, 2014. In the event of
delays, ECA will have until March 31, 2014 to drill all the
PUD Wells, in which event the subordinated units would convert
into common units on or before March 31, 2015. The period
during which the subordinated units are outstanding is referred
to as the subordination period.
3
The table below sets forth the target distributions and
subordination and incentive thresholds for each calendar quarter
during the full potential subordination period. The effective
date of the trust is April 1, 2010, meaning it will receive
the proceeds of production attributable to the PDP Royalty
Interest from that date even though the PDP Royalty Interest
will not be conveyed to the trust until the closing of this
offering.
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Subordination
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Target
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Incentive
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Period
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Threshold
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Distribution
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Threshold
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(per unit)
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2010:
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Second Quarter
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$
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0.217
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$
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0.271
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$
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0.326
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Third Quarter
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0.298
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0.372
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0.447
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Fourth Quarter
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0.426
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0.532
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0.639
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2011:
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First Quarter
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0.413
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0.516
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0.619
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Second Quarter
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0.418
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0.523
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0.627
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Third Quarter
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0.520
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0.650
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0.780
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Fourth Quarter
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0.544
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0.680
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0.815
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2012:
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First Quarter
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0.562
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0.702
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0.843
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Second Quarter
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0.595
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0.744
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0.893
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Third Quarter
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0.607
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0.759
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0.911
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Fourth Quarter
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0.688
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0.859
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1.031
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2013:
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First Quarter
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$
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0.773
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$
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0.967
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$
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1.160
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Second Quarter
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0.771
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0.964
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1.157
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Third Quarter
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0.717
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0.896
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1.075
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Fourth Quarter
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0.674
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0.842
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1.010
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2014:
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First Quarter
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0.623
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0.779
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0.935
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Second Quarter
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0.601
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0.751
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0.902
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Third Quarter
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0.583
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0.728
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0.874
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Fourth Quarter
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0.561
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0.701
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0.841
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2015:
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First Quarter
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0.530
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0.663
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0.795
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For additional information with respect to the subordination and
incentive thresholds, please see Target Distributions and
Subordination and Incentive Thresholds and
Description of the Royalty Interests.
4
Target
Distributions
The table below presents the calculation of the target
distributions for each quarter through and including the quarter
ending June 30, 2011. The target distributions were
prepared by ECA on an accrual basis based on production volumes,
pricing and other assumptions. As used herein, accrual basis
means ECA will pay to the trust each quarter an amount equal to
the estimated proceeds of production from the trust properties
during the calendar quarter most recently ended before the
distribution (after deducting post-production costs and any
applicable taxes), regardless of whether such amounts have
actually been received by ECA from the purchaser of the natural
gas produced. Any difference between the payment made by ECA to
the trust with respect to a calendar quarter and the actual cash
production payments relative to the trust properties received by
ECA will be netted against future payments by ECA to the trust.
Actual cash distributions to the trust unitholders will
fluctuate quarterly based on the quantity of natural gas
produced from the Underlying Properties, the prices received for
natural gas production and other factors. Please read
Target Distributions and Subordination and Incentive
Thresholds Significant Assumptions Used to Prepare
the Target Distributions.
ECA does not as a matter of course make public projections as to
future sales, earnings or other results. However, the management
of ECA has prepared the projected operational and financial
information set forth below in order to present the target
distributions attributable to the natural gas sales volumes
reflected in Ryder Scotts reserve report attached hereto
as Annex A.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Number of wells producing at quarter end
|
|
|
8
|
|
|
|
17
|
|
|
|
22
|
|
|
|
25
|
|
|
|
31
|
|
Estimated Production from Trust Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas PDP Sales Volumes (MMcf)
|
|
|
879
|
|
|
|
1,190
|
|
|
|
1,265
|
|
|
|
1,066
|
|
|
|
962
|
|
Natural Gas PUD Sales Volumes (MMcf)
|
|
|
|
|
|
|
81
|
|
|
|
514
|
|
|
|
553
|
|
|
|
769
|
|
Total Sales Volumes (MMcf)
|
|
|
879
|
|
|
|
1,271
|
|
|
|
1,779
|
|
|
|
1,619
|
|
|
|
1,731
|
|
Daily Sales Volumes (Mcf/d)
|
|
|
9,664
|
|
|
|
13,814
|
|
|
|
19,336
|
|
|
|
17,988
|
|
|
|
19,020
|
|
Commodity Prices and Hedging Positions (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed NYMEX Price ($/MMBtu) (2)
|
|
$
|
4.58
|
|
|
$
|
4.75
|
|
|
$
|
5.27
|
|
|
$
|
5.81
|
|
|
$
|
5.34
|
|
Assumed Price ($/Mcf) (2)
|
|
|
4.72
|
|
|
|
4.89
|
|
|
|
5.42
|
|
|
|
5.98
|
|
|
|
5.50
|
|
Realized Unhedged Price after Basis Differential ($/Mcf)
|
|
|
4.88
|
|
|
|
5.04
|
|
|
|
5.58
|
|
|
|
6.13
|
|
|
|
5.65
|
|
Daily Hedged Volumes (MMcf/d) (3)
|
|
|
7.3
|
|
|
|
7.3
|
|
|
|
9.7
|
|
|
|
9.0
|
|
|
|
9.5
|
|
Percent of Total Volumes Swapped
|
|
|
75
|
%
|
|
|
53
|
%
|
|
|
38
|
%
|
|
|
40
|
%
|
|
|
38
|
%
|
Swap Price ($/MMBtu)
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
Percent of Total Volumes Floored
|
|
|
|
|
|
|
|
|
|
|
12
|
%
|
|
|
10
|
%
|
|
|
12
|
%
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Floor Price ($/MMBtu)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
Realized Hedged Weighted Average Price ($/Mcf) (3)
|
|
$
|
6.55
|
|
|
$
|
6.13
|
|
|
$
|
6.15
|
|
|
$
|
6.53
|
|
|
$
|
6.21
|
|
Cash available for distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
$
|
4,288
|
|
|
$
|
6,408
|
|
|
$
|
9,923
|
|
|
$
|
9,932
|
|
|
$
|
9,786
|
|
Swap and Floor Hedge Revenues
|
|
|
1,476
|
|
|
|
1,381
|
|
|
|
1,021
|
|
|
|
635
|
|
|
|
960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
5,764
|
|
|
$
|
7,788
|
|
|
$
|
10,944
|
|
|
$
|
10,566
|
|
|
$
|
10,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Production Services Fee (4)
|
|
$
|
471
|
|
|
$
|
681
|
|
|
$
|
953
|
|
|
$
|
867
|
|
|
$
|
927
|
|
Trust Expenses
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
201
|
|
Franchise Taxes
|
|
|
207
|
|
|
|
207
|
|
|
|
211
|
|
|
|
211
|
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
|
|
$
|
4,885
|
|
|
$
|
6,701
|
|
|
$
|
9,581
|
|
|
$
|
9,288
|
|
|
$
|
9,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Units Outstanding
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
Target Distribution Per Trust Unit
|
|
$
|
0.271
|
|
|
$
|
0.372
|
|
|
$
|
0.532
|
|
|
$
|
0.516
|
|
|
$
|
0.523
|
|
Subordination Threshold Per Trust Unit
|
|
$
|
0.217
|
|
|
$
|
0.298
|
|
|
$
|
0.426
|
|
|
$
|
0.413
|
|
|
$
|
0.418
|
|
Incentive Threshold Per Trust Unit
|
|
$
|
0.326
|
|
|
$
|
0.447
|
|
|
$
|
0.639
|
|
|
$
|
0.619
|
|
|
$
|
0.627
|
|
|
|
|
(1)
|
|
For a more detailed description of
the natural gas hedging contracts established for the benefit of
the trust, please see Description of the Royalty
Interests.
|
|
(2)
|
|
Based on NYMEX forward pricing as
of March 11, 2010. Assumed price per Mcf calculated based
on an assumed conversion rate of
1.03
MMBtu
per Mcf.
|
|
(3)
|
|
Adjusted for an assumed basis
differential of $0.15 per MMBtu.
|
|
(4)
|
|
Consists of a fee of $0.52 per
MMBtu.
|
ENERGY
CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the
exploration, development, production, gathering, aggregation and
sale of natural gas and oil, primarily in the Appalachian Basin,
Gulf Coast and Rocky Mountain regions in the United States and
in New Zealand. ECA or its predecessors have owned and operated
natural gas properties in the Appalachian Basin for more than
45 years, and ECA is one of the largest natural gas
operators in the Appalachian Basin. As of December 31,
2009, ECA operated approximately 5,100 wells in the
Appalachian Basin and had an aggregate net leasehold position of
approximately one million acres, with 85% of this acreage held
by production. ECA sells gas from its own wells as well as
third-party wells to local gas distribution companies,
industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered
into interstate pipelines. ECA owns and operates approximately
5,000 miles of gathering lines and intrastate pipelines
that are used in connection with its gas aggregation activities.
During the fiscal year ended June 30, 2009, ECA aggregated
and sold 22.5 Bcf of gas for an average of 62 MMcf of
gas per day, of which 20.7 Bcf, or 57 MMcf per day,
represented sales of gas produced from wells operated by ECA.
6
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger
with ECAs predecessor in June 1995. ECAs predecessor
began operating in the Appalachian Basin in 1963. ECAs
principal offices are located at 4643 South Ulster Street,
Suite 1100, Denver, Colorado 80237, and its telephone
number is
(303) 694-2667.
For additional information concerning ECA, see Information
about Energy Corporation of America beginning on
page ECA-1
of this prospectus. ECA will be required to deliver to the
trustee a statement of the computation of the proceeds for each
computation period, as well as quarterly drilling and production
results. ECA will not be a reporting company following this
offering and will not file periodic reports with the SEC.
Therefore, as a trust unitholder, you will not have access to
financial information of ECA.
The trust
units do not represent interests in or obligations of
ECA.
FORMATION
TRANSACTIONS
At or prior to the closing of this offering, the following
transactions, which are referred to as the formation
transactions, will occur:
|
|
|
|
|
ECA will convey to a wholly owned subsidiary a term royalty
interest entitling the holder of the interest to receive 45% of
the proceeds from the sale of production of natural gas
attributable to ECAs interest in the Producing Wells
(after deducting post-production costs and any applicable taxes)
for a period of 20 years commencing on April 1, 2010
(the Term PDP Royalty) and a term royalty interest
entitling such holder of the interest to receive 25% of the
proceeds from the sale of the production of natural gas
attributable to ECAs interest in the PUD Wells (after
deducting
post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PUD
Royalty) in exchange for a demand note in the principal
amount of $ million. The Term
PDP Royalty and the Term PUD Royalty are collectively referred
to as the Term Royalties.
|
|
|
|
ECA and the Private Investors will convey to the trust perpetual
royalty interests entitling the trust to receive, in the
aggregate, 45% of the proceeds from the sale of production of
natural gas attributable to the interests of ECA in the
Producing Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PDP Royalty) and
ECA will convey to the trust a perpetual royalty interest
entitling the trust to receive an additional 25% of the proceeds
from the sale of production of natural gas attributable to
ECAs interest in the PUD Wells (after deducting
post-production
costs and any applicable taxes) (the Perpetual PUD
Royalty) in exchange for, in the case of ECA,
3,186,117 common units constituting 17.7% of the trust
units outstanding and 4,500,000 subordinated units
constituting 25% of the trust units outstanding and, in the case
of the Private Investors, 1,313,883 common units
constituting 7.3% of the trust units outstanding. The Perpetual
PDP Royalty and the Perpetual PUD Royalty are collectively
referred to as the Perpetual Royalties.
|
|
|
|
The trust will sell the 9,000,000 common units offered
hereby to the public, representing a 50% interest in the trust.
|
|
|
|
ECA will convey to the trust the natural gas hedging contracts.
|
|
|
|
ECAs subsidiary will convey the Term Royalties to the
trust in exchange for a distribution from the net proceeds of
this offering and will use the net proceeds to repay the demand
note to ECA.
|
7
|
|
|
|
|
ECA will purchase 209,316 common units from the Private
Investors at the initial offering price.
|
|
|
|
ECA and the trust will enter into an Administrative and Drilling
Services Agreement outlining the provision of administrative
services to the trust and its compensation therefor and
ECAs drilling obligation to the trust with respect to the
PUD Wells. Please see The Trust Administrative
and Drilling Services Agreement.
|
|
|
|
ECA will grant to the trust the Drilling Support Lien which is
nonrecourse to ECA.
|
|
|
|
ECA will grant to the trust a lien, which is nonrecourse to ECA,
on the PDP Royalty Interest and the PUD Royalty Interest (the
Royalty Interest Lien) to provide protection to the
trust, in the event of a bankruptcy of ECA, against the risk
that the PDP Royalty Interest or PUD Royalty Interest were not
considered a real property interest.
|
STRUCTURE
OF THE TRUST
The following chart shows the relationship of ECA, the trust and
the public unitholders.
KEY
INVESTMENT CONSIDERATIONS
The following are some key investment considerations related to
the Underlying Properties, the royalty interests, and the common
units:
|
|
|
|
|
Royalty interests not burdened by operating or capital
costs.
The trust will not be responsible for any
operating or capital costs associated with the Underlying
Properties, including the costs to drill the PUD Wells. As a
result, the trusts burden to pay costs associated with any
particular well will not arise until such well is producing
natural gas attributable to the trusts interest. The
principal costs the trust will bear are the Post-Production
Services Fee; property, ad valorem, production, severance,
excise,
|
8
|
|
|
|
|
franchise and similar taxes, if any; and trust administrative
expenses including costs incurred as a result of being a
publicly traded entity. In addition, the trust will be obligated
to reimburse ECA for approximately $5 million incurred in
establishing the hedging contracts to be transferred to the
trust if and to the extent cash available for distribution by
the trust exceeds certain levels.
|
|
|
|
|
|
Downside protection against natural gas price volatility
through natural gas hedging contracts for 50% of estimated
production through March 31, 2014.
ECA will
transfer to the trust hedging contracts covering approximately
50% of the expected production volumes attributable to the trust
from April 1, 2010 through March 31, 2014. These
hedging contracts will consist of swap contracts and floor price
hedging contracts. The swap contracts will relate to
approximately 7,500 MMBtu per day at an average price of
$6.78 per MMBtu for the period from April 1, 2010 through
June 2012. The floor price of any floor price hedging contract
will be $5.00 per MMBtu. These hedging contracts should
reduce commodity price risks inherent in holding interests in
natural gas through the end of March 31, 2014.
|
|
|
|
Alignment of interests between ECA and the trust
unitholders.
ECA is significantly incentivized to
complete its drilling obligation, to increase production from
the Underlying Properties and to obtain the best prices for the
natural gas production from the Underlying Properties as a
result of the following factors:
|
|
|
|
|
-
|
ECA will retain an approximate average of 66% total economic
interest in the Underlying Properties through its retained
interest in the Underlying Properties and its ownership of
approximately 43% of the trust units.
|
|
|
-
|
A portion of the trust units that ECA will own, constituting 25%
of the outstanding trust units, will be subordinated units that
will not be entitled to receive distributions unless there is
sufficient cash to pay the subordination threshold to the common
units. These subordinated units will only convert into common
units upon completion of the subordination period.
|
|
|
-
|
To the extent that the trust has cash available for distribution
in excess of the incentive thresholds during the subordination
period, ECA will be entitled to receive 50% of such cash as
incentive distributions and 50% of such cash as recoupment of
its costs for establishing the hedge contracts until it has
recouped approximately $5 million.
|
|
|
|
|
-
|
ECA will not be permitted to drill and complete any development
wells in the Marcellus Shale formation on the lease acreage
within the AMI for its own account or sell the Underlying
Properties until it has satisfied its drilling obligation.
|
|
|
|
|
|
Potential for initial depletion to be offset by results of
development drilling.
ECA is obligated to drill the PUD
Wells by March 31, 2014. Furthermore, ECA is incentivized
to increase production in the near term in order to receive
incentive distributions. While production from the trust
properties will decline in the long term, production from the
PUD Wells will offset depletion of the Producing Wells in the
near term.
|
|
|
|
ECAs experience and position as Marcellus Shale
operator.
Since January 1, 2006, ECA has drilled
over 160 Marcellus Shale wells throughout the Appalachian Basin
and operates Marcellus Shale wells in New York, Pennsylvania and
West Virginia. ECA was one of the earliest operators in the
Marcellus Shale region, having drilled test wells in this play
in the late 1970s in partnership with the U.S. Department
of Energy, and on April 18, 2008, it drilled and completed
the Consol USX-13 well, which was one of the
|
9
|
|
|
|
|
first horizontal Marcellus Shale wells in Greene County,
Pennsylvania. ECA has drilled 141 gross vertical
development wells and 21 gross horizontal wells in the
Marcellus Shale formation, and it has successfully completed
100% of these wells. ECA is currently the operator of all of the
Producing Wells and will agree to operate not less than 90% of
the PUD Wells during the subordination period, allowing ECA to
control the timing and amount of discretionary expenditures for
operational and development activities with respect to
substantially all of the PUD Wells. ECAs senior managers
possess an average of 27.5 years of industry experience
with an extensive focus on operations in the Appalachian Basin
and Marcellus Shale.
|
|
|
|
|
|
ECAs prior experience sponsoring a royalty
trust.
In 1993, ECA sponsored the formation of the
Eastern American Natural Gas Trust (NYSE: NGT), a publicly
traded Delaware trust (NGT), to which it contributed
term net profits interests in Appalachian Basin natural gas
properties. In connection with the formation of this trust, ECA
agreed to drill 65 development wells over five years from which
NGT would be entitled to a specified percentage of the proceeds
from the natural gas production. ECA completed its obligation
within the stipulated period. The historical results of
operations and performance of NGT should not be relied on as an
indicator of how the trust will perform.
|
In mid-2005, ECA entered into a term royalty transaction with a
private investor. ECA conveyed to the private investor a 90%
royalty interest in 312 producing gas wells located in the
Appalachian Basin in West Virginia, Pennsylvania and Kentucky,
as well as a 50% royalty interest in 180 development wells that
were subsequently drilled by ECA in Kentucky and West Virginia.
Although the parties originally contemplated that ECA would
drill relatively shallow wells, 105 of the 180 development wells
were completed to the deeper Marcellus Shale formation.
|
|
|
|
|
Experience of ECA marketing natural gas
production.
As the operator of all of the Producing
Wells and substantially all the PUD Wells, ECA will have the
responsibility to market or cause to be marketed the natural gas
production related to the Underlying Properties. During the
fiscal year ended June 30, 2009, ECA and its affiliates
aggregated and sold domestically an average of 62 MMcf of
gas per day, of which 57 MMcf per day represented sales of
natural gas produced from wells operated by ECA.
|
|
|
|
Proximity of the Appalachian Basin to major
markets.
The Appalachian Basin is located close to a
substantial number of large commercial and industrial gas
markets, including natural gas powered electricity plants, and
major residential markets in the northeastern United States.
This proximity, together with the stable nature of Appalachian
Basin production and the availability of transportation
facilities, has resulted in generally higher realized prices for
Appalachian Basin natural gas (including Marcellus Shale
formation natural gas) than realized prices available in other
regions of the United States.
|
The average realized sales prices for gas gathered and sold on
ECAs Greene County Gathering System (prior to any
deduction for post-production costs) for each year in the three
year period ended June 30, 2009 and the average NYMEX price
for the same period are detailed in the table below:
|
|
|
|
|
|
|
|
|
|
|
Average Greene County
|
|
Average NYMEX
|
Year
|
|
Gathering Price/MMBtu
|
|
Price/MMBtu
|
|
2007
|
|
$
|
7.17
|
|
|
$
|
6.86
|
|
2008
|
|
|
8.46
|
|
|
|
8.02
|
|
2009
|
|
|
6.85
|
|
|
|
6.39
|
|
10
During this three year period, ECAs Greene County
Gathering System received an average price that was $0.40 per
MMBtu higher than the average NYMEX price for the same period.
In establishing the subordination and incentive thresholds, ECA
has assumed a basis differential of $0.15 per MMBtu.
RISK
FACTORS
An investment in the common units involves risks associated
with, among other things, energy commodity prices, the operation
of the Underlying Properties, measurement of reserves,
post-production expenses and any applicable taxes payable by the
trust, the ability of ECA to drill the PUD Wells, the financial
condition of ECA, certain regulatory and legal matters, the
structure of the trust and the characteristics of the trust
units. Please read carefully these risks and other risks
described under Risk Factors on page 16.
PROVED
RESERVES
Proved reserves of Underlying Properties and royalty
interests.
The following table, effective as of
March 31, 2010, sets forth certain estimated proved
reserves, estimated future net revenues and the discounted
present value thereof attributable to the Underlying Properties,
the PDP Royalty Interest and the PUD Royalty Interest, in each
case derived from the reserve report. The reserve report was
prepared by Ryder Scott in accordance with criteria established
by the Securities and Exchange Commission, or SEC.
In accordance with the SECs new rules, the reserves
presented below were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from April 1, 2009 through
March 1, 2010, without giving effect to the derivative
transactions, and were held constant for the life of the
properties. This yielded a price for natural gas of $3.984 per
MMBtu. Proved reserve quantities attributable to the royalty
interests are calculated by multiplying the gross reserves for
each property by the royalty interest assigned to the trust in
each property. The net revenues attributable to the trusts
reserves are net of the trusts obligation to reimburse ECA
for post-production costs. The reserves related to the
Underlying Properties include all proved reserves expected to be
economically produced from the Marcellus Shale formation during
the life of the properties. The reserves and revenues
attributable to the trusts interests include only the
reserves attributable to the Underlying Properties that are
expected to be produced within the 20-year period in which the
trust owns the royalty interest as well as the 50% residual
interest in the reserves that the trust will own on the
Termination Date. A summary of the reserve report is included as
Annex A to this prospectus.
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Proved Gas
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Discounted
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Reserves
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Estimated Future
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Estimated Future
|
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Proved Reserves
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(Bcfe)
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|
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Net Revenues
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|
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Net Revenues (1)
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|
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(Dollars in thousands)
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Underlying Properties
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193.8
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|
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$
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507,289
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|
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$
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168,687
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|
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|
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|
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Royalty Interests:
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|
|
|
|
|
|
|
|
|
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PDP Royalty Interest (90%) (2)
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|
32.2
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$
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119,757
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$
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67,161
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PUD Royalty Interest (50%)
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|
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72.4
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|
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$
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269,175
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$
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133,109
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|
|
|
|
|
|
|
|
|
|
|
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Total
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|
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104.6
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|
|
$
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388,932
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|
|
$
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200,270
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(1)
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The present values of future net
revenues for the Underlying Properties and the royalty interests
were determined using a discount rate of 10% per annum.
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(2)
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Includes reserves currently behind
pipe in existing wells which are in the process of being
completed.
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11
Annual production attributable to royalty
interests.
The following bar graph shows estimated
annual production from the Underlying Properties attributable to
the royalty interests based on the pricing and other assumptions
set forth in the reserve report. The production estimates
include the impact of additional production that is expected as
a result of the drilling of the PUD Wells. The net production
for 2010 only includes the nine months from April 1, 2010.
12
THE
OFFERING
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Common units offered to public
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9,000,000 common units
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10,350,000 common units, if the underwriters exercise their
over-allotment option in full
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Trust units owned by ECA after the offering
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3,395,433 common units and 4,500,000 subordinated units
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2,045,433 common units and 4,500,000 subordinated
units, if the underwriters exercise their over-allotment option
in full
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Common units owned by the Private Investors
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1,104,567 common units. For more information on the common units
owned by the Private Investors, please read Certain
Transactions.
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Total units outstanding after the offering
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13,500,000 common units and 4,500,000 subordinated
units
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Use of proceeds
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The trust is offering the common units to be sold in this
offering. Assuming no exercise of the underwriters
over-allotment option and an initial public offering price of
$ per common unit, the
estimated net proceeds of this offering will be approximately
$ million, after deducting
underwriting discounts and commissions and offering expenses.
The trust will use the net proceeds to pay a wholly-owned
subsidiary of ECA for the conveyance of the Term Royalties. In
turn, such subsidiary will use such amount to repay a
$ million demand note payable
to ECA to be issued as consideration for the transfer of the
Term Royalties thereto.
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The trust will use the net proceeds from any exercise of the
underwriters over-allotment option to repurchase an equal
number of common units from ECA at the initial public offering
price, after deducting underwriting discounts and commissions.
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ECA will use the proceeds received both from the repayment of
the demand note by ECAs subsidiary and from any exercise
of the underwriters over-allotment option for general
corporate purposes, including for the drilling of PUD Wells.
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Proposed NYSE symbol
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ECT
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Quarterly cash distributions
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Actual cash distributions to the trust unitholders will
fluctuate quarterly based on the quantity of natural gas
produced from the Underlying Properties, the prices received for
natural gas production and other factors.
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13
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Because payments to the trust will be generated by depleting
assets and the trust has a finite life with the production from
the Underlying Properties initially increasing and subsequently
diminishing over time, a portion of each distribution will
represent a return of your original investment and the target
distributions will decline over time. Production declines are
expected to be offset in the near term by production realized
from the drilling and successful completion of the PUD Wells.
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It is expected that quarterly cash distributions during the term
of the trust will be made by the trustee on or about the 60th
day following the end of each calendar quarter to the trust
unitholders of record on or about the 45th day following each
calendar quarter. The first distribution from the trust to the
trust unitholders will be made on or about August 31, 2010.
The first distribution to the trust unitholders will be based
upon amounts to be received from ECA for estimated production
attributable to the royalty interests and proceeds attributable
to the hedging contracts for the period commencing on
April 1, 2010 and ending on June 30, 2010, regardless
or whether such amounts have actually been received by ECA from
the purchaser of the natural gas produced.
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Termination of the trust
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The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds thereof will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a first right
of refusal to purchase the Perpetual Royalties at the
Termination Date.
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Summary of income tax considerations
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The trust will be treated as a partnership for federal income
tax purposes. Consequently, the trust will not incur any federal
income tax liability. Instead, trust unitholders will be
allocated an amount of the trusts income, gain, loss, or
deductions corresponding to their interest in the trust, which
amounts may differ in timing or amount from actual
distributions. The Term PDP Royalty will and the Term PUD
Royalty should be treated as debt instruments for federal income
tax purposes, and the trust will be required to treat a portion
of each payment it receives with respect to each such royalty
interest as interest income in accordance with the
noncontingent bond method under the original issue
discount rules contained in the Internal Revenue Code of 1986,
as amended, and the corresponding regulations. The Perpetual PDP
Royalty will and the Perpetual PUD Royalty should be treated as
mineral royalty interests for federal income tax purposes, which
generates
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14
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ordinary income subject to depletion. Please read Federal
income tax considerations.
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Estimated ratio of taxable income to distributions
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The trust estimates that if you own the units you purchase in
this offering through the record date for distributions for the
period ending December 31, 2012, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be % or less of
the cash distributed to you with respect to that period. For
example, if you receive an annual distribution of
$ per unit, the trust estimates
that your average allocable federal taxable income per year will
be no more than approximately $
per unit. Please read Federal income tax
considerations.
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15
RISK
FACTORS
Drilling and completion of the development wells on the
underlying PUD properties are high risk activities with many
uncertainties that could delay ECAs anticipated drilling
schedule and adversely affect future production from the
Underlying Properties. Any such delays or reductions in
production could decrease future revenues that are available for
distribution to unitholders.
The drilling and completion of the development wells on the
underlying PUD properties are subject to numerous risks beyond
ECAs and the trusts control, including risks that
could delay ECAs current drilling schedule for the PUD
Wells and the risk that drilling will not result in commercially
viable natural gas production. ECAs decisions to develop
or otherwise exploit certain areas within the AMI will depend in
part on the evaluation of data obtained through geophysical and
geological analyses, production data and engineering studies,
the results of which are often inconclusive or subject to
varying interpretations. ECAs costs of drilling,
completing and operating wells are often uncertain before
drilling commences. Overruns in budgeted expenditures are common
risks that can make a particular project uneconomical. Further,
ECAs future business, financial condition, results of
operations, liquidity or ability to finance planned capital
expenditures could be materially and adversely affected by any
factor that may curtail, delay or cancel drilling, including the
following:
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delays imposed by or resulting from compliance with regulatory
requirements including permitting;
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unusual or unexpected geological formations;
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shortages of or delays in obtaining equipment and qualified
personnel;
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equipment malfunctions, failures or accidents;
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lack of available gathering facilities or delays in construction
of gathering facilities;
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lack of available capacity on interconnecting transmission
pipelines;
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unexpected operational events and drilling conditions;
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pipe or cement failures;
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casing collapses;
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lost or damaged drilling and service tools;
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loss of drilling fluid circulation;
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uncontrollable flows of natural gas and fluids;
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fires and natural disasters;
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environmental hazards, such as natural gas leaks, pipeline
ruptures and discharges of toxic gases;
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adverse weather conditions;
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16
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reductions in natural gas prices;
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natural gas property title problems; and
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market limitations for natural gas.
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In the event that drilling of development wells is delayed or
development wells have lower than anticipated production due to
one of the factors above or for any other reason, estimated
future distributions to unitholders may be reduced.
Natural gas prices fluctuate due to a number of factors
that are beyond the control of the trust and ECA, and lower
prices could reduce proceeds to the trust and cash distributions
to unitholders.
The trusts reserves and quarterly cash distributions are
highly dependent upon the prices realized from the sale of
natural gas. Natural gas prices can fluctuate widely on a
month-to-month
basis in response to a variety of factors that are beyond the
control of the trust and ECA. These factors include, among
others:
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weather conditions and seasonal trends;
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regional, domestic and foreign supply and perceptions of supply
of natural gas;
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availability of imported liquefied natural gas, or LNG;
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the level of demand and perceptions of demand for natural gas;
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anticipated future prices of natural gas, LNG and other
commodities;
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technological advances affecting energy consumption and energy
supply;
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U.S. and worldwide political and economic conditions;
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the price and availability of alternative fuels;
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the proximity, capacity, cost and availability of gathering and
transportation facilities;
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the volatility and uncertainty of regional pricing differentials;
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acts of force majeure;
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governmental regulations and taxation; and
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energy conservation and environmental measures.
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From 2006 through 2009 the highest monthly NYMEX settled price
was $13.11 per MMBtu and the lowest was $2.84 per MMBtu. In
addition, the market price of natural gas is generally higher in
the winter months than during other months of the year due to
increased demand for natural gas for heating purposes during the
winter season.
Lower natural gas prices will reduce proceeds to which the trust
is entitled and may ultimately reduce the amount of natural gas
that is economic to produce from the Underlying Properties. As a
result, the operator of any of the Underlying Properties could
determine during
17
periods of low gas prices to shut in or curtail production from
wells on the Underlying Properties. In addition, the operator of
the Underlying Properties could determine during periods of low
gas prices to plug and abandon marginal wells that otherwise may
have been allowed to continue to produce for a longer period
under conditions of higher prices. Specifically, ECA may abandon
any well or property if it reasonably believes that the well or
property can no longer produce natural gas in commercially
economic quantities. This could result in termination of the
portion of the royalty interest relating to the abandoned well
or property, and ECA would have no obligation to drill a
replacement well. In making such decisions, ECA is required
under the applicable conveyance to act as a reasonably prudent
operator in the AMI under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. As a result, the volatility
of natural gas prices also reduces the accuracy of estimates of
future cash distributions to trust unitholders.
Actual reserves and future production may be less than
current estimates, which could reduce cash distributions by the
trust and the value of the trust units.
The value of the trust units and the amount of future cash
distributions to the trust unitholders will depend upon, among
other things, the accuracy of the reserves estimated to be
attributable to the trusts royalty interests. The
trusts reserve quantities and revenues are based on
estimates of reserve quantities and revenues for the Underlying
Properties. See The Underlying Properties
Natural gas reserves for a discussion of the method of
allocating proved reserves to the trust. It is not possible to
measure underground accumulations of natural gas in an exact
way, and estimating reserves is inherently uncertain.
Ultimately, actual production and revenues for the Underlying
Properties could vary negatively and in material amounts from
estimates and those variations could be material. Petroleum
engineers are required to make subjective estimates of
underground accumulations of natural gas based on factors and
assumptions that include:
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historical production from the area compared with production
rates from other producing areas;
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natural gas prices, production levels, Btu content, production
expenses, transportation costs, severance and excise taxes and
capital expenditures; and
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the assumed effect of governmental regulation.
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Changes in these assumptions or actual production costs incurred
and results of actual development and production costs could
materially decrease reserve estimates.
In particular, reserve estimates for fields that do not have a
lengthy production history are less reliable than estimates for
fields with lengthy production histories. A lack of production
history may contribute to inaccuracy in estimates of proved
reserves, future production rates and the timing of development
expenditures. The Producing Wells have been operational for less
than one year. Additionally, the use of horizontal drilling
methods on the Underlying Properties is a recent development in
the Marcellus Shale, with ECA commencing the drilling of its
first horizontal well in the Marcellus Shale in 2007. The lack
of operational history for horizontal wells in the Marcellus
Shale formation may also contribute to the inaccuracy of
estimates of proved reserves. A material and adverse variance of
actual production, revenues and expenditures from those
underlying reserve estimates, including variances attributable
to a lack of production history within the Marcellus Shale
formation, would have a material adverse effect on the financial
condition, results of operations and cash flows of the trust and
would reduce cash distributions to trust unitholders.
18
Recently proposed severance taxes in Pennsylvania could
materially increase the post-production costs that are borne by
the trust.
While Pennsylvania has historically not imposed a severance tax
on the production of natural gas, legislation known as Senate
Bill No. 1254 was introduced in the Pennsylvania Senate
Finance Committee on March 4, 2010 and House Bill 1489
was introduced in the House Energy and Environmental Resources
Committee on May 13, 2009. These bills, if enacted, would
provide for a severance tax of 5% of the value of the natural
gas at the wellhead plus $0.047 per thousand cubic feet of
natural gas severed. Additionally, a severance tax, with tax
rates equal to those of Senate Bill No. 1254 and House
Bill 1489, is included in the governors proposed
2010-2011
budget, dated February 9, 2010. If adopted, any such
severance tax would be a post-production cost that would be
borne by the trust and may materially reduce distributions to
unitholders.
The generation of proceeds for distribution by the trust
depends in part on gathering, transportation and processing
facilities owned by ECA and others. Any limitation in the
availability of those facilities could interfere with sales of
natural gas production from the Underlying Properties.
The amount of natural gas that may be produced and sold from any
well to which the Underlying Properties relate is subject to
curtailment in certain circumstances, such as by reason of
weather conditions, pipeline interruptions due to scheduled and
unscheduled maintenance, failure of tendered gas to meet quality
specifications of gathering lines or downstream transporters,
excessive line pressure which prevents delivery of gas, physical
damage to the gathering system or transportation system or lack
of contracted capacity on such systems. The curtailments may
vary from a few days to several months. In many cases, ECA is
provided limited notice, if any, as to when production will be
curtailed and the duration of such curtailments. If ECA is
forced to reduce production due to such a curtailment, the
revenues of the trust and the amount of cash distributions to
the trust unitholders would similarly be reduced due to the
reduction of proceeds from the sale of production.
Some of the wells on the underlying PUD properties will be
drilled in locations that currently are not serviced by
gathering and transportation pipelines or locations in which
existing gathering and transportation pipelines do not have
sufficient capacity to transport additional production. As a
result, ECA may not be able to sell the natural gas production
from certain PUD Wells until the necessary gathering systems
and/or
transportation pipelines are constructed or until the necessary
transportation capacity on an interstate pipeline is obtained.
Any delay in the construction or expansion of these gathering
systems beyond the currently estimated construction schedules,
or a delay in the procurement of additional transportation
capacity would delay the receipt of any proceeds that may be
associated with natural gas production from the PUD Wells. If
transportation capacity is not available, either directly from a
pipeline or pipelines or in the secondary capacity market, ECA
would be required to request that the pipeline or pipelines
construct additional facilities or expand their existing
facilities to provide additional transportation capacity. The
pipelines are not required to undertake such construction or
expansion. If the pipeline refuses to construct additional
transportation capacity or expand its existing transportation
capacity, ECA may not be able to receive proceeds that may be
associated with natural gas production from wells on the
underlying PUD properties. Any delay in the construction or
expansion of pipeline transportation facilities will delay the
receipt of any proceeds that may be associated with natural gas
production from wells on the underlying PUD properties.
19
The generation of proceeds for distribution by the trust
depends in part on the ability of ECA and/or its customers to
obtain service on transportation facilities owned by third party
pipelines; any limitation in the availability of those
facilities and any increase in the cost of service on those
facilities could interfere with sales of natural gas production
from the Underlying Properties.
Natural gas that is gathered on Greene County Gathering System,
including natural gas produced from the Underlying Properties,
is currently shipped on two interstate natural gas
transportation pipelines. ECAs purchasers have contracted
with those pipelines for firm or interruptible transportation
service. The rates for service on the transportation pipelines
are regulated by the Federal Energy Regulatory Commission
(FERC) and are subject to increase if the pipeline
demonstrates that the existing rates are unjust and unreasonable.
ECA may, in the future, seek to obtain firm transportation
capacity, but there can be no assurance that capacity will be
available. In addition, to the extent ECAs customers or
ECA became dependent on interruptible service, and to the extent
that either pipeline receives requests for service that exceed
the capacity of the pipeline, the pipeline will honor requests
by its firm customers first, and will then allocate remaining
capacity, if any, to interruptible shippers. As a result, ECA or
its customers may be unable to obtain all or a part of any
requested interruptible capacity service on the transportation
pipelines. Any inability of ECA or its customers to procure
sufficient capacity to transport the natural gas gathered on its
Greene County Gathering System will decrease
and/or
delay
the receipt of any proceeds that may be associated with natural
gas production from wells on the Underlying Properties. In
addition, any increase in transportation rates paid by ECA for
production attributable to the trusts interests will
decrease the proceeds received by the trust.
Shortages or increases in costs of equipment, services and
qualified personnel could delay the drilling of the PUD Wells
and result in a reduction in the amount of cash available for
distribution.
The demand for qualified and experienced personnel to conduct
field operations, geologists, geophysicists, engineers and other
professionals in the natural gas industry can fluctuate
significantly, often in correlation with oil and natural gas
prices, causing periodic shortages. Historically, there have
been shortages of drilling rigs and other equipment as demand
for rigs and equipment has increased along with the number of
wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher
natural gas prices generally stimulate demand and result in
increased prices for drilling rigs, crews and associated
supplies, equipment and services. Shortages of field personnel
and equipment or price increases could significantly hinder
ECAs ability to perform the drilling obligations and delay
completion of the development wells, which would reduce future
distributions to trust unitholders.
Due to the trusts lack of industry and geographic
diversification, adverse developments in the trusts
existing area of operation could adversely impact its financial
condition, results of operations and cash flows and reduce its
ability to make distributions to the unitholders.
The Underlying Properties will be operated for natural gas
production only and are focused exclusively in the Marcellus
Shale formation in Greene County, Pennsylvania. In particular,
the concentration of the Underlying Properties in the Marcellus
Shale formation in Greene County, Pennsylvania could
disproportionately expose the trusts interests to
operational and regulatory risk in that area. Due to the lack of
diversification in industry type and location of the
trusts interests, adverse developments in the natural gas
market or the area of the Underlying Properties
20
could have a significantly greater impact on the trusts
financial condition, results of operations and cash flows than
if the trusts royalty interests were more diversified.
The trust units may lose value as a result of title
deficiencies with respect to the Underlying Properties.
The existence of a material title deficiency with respect to the
Underlying Properties can reduce the value or render a property
worthless, thus adversely affecting the distributions to
unitholders. ECA does not obtain title insurance covering
mineral leaseholds. Additionally, undeveloped acreage has
greater risk of title defects than developed acreage.
Consistent with industry practice, ECA has not obtained a
preliminary title review on the PUD Wells. Prior to the drilling
of a PUD Well, ECA intends to obtain a preliminary title review
to ensure there are no obvious defects in title to the
leasehold. Frequently, as a result of such examinations, certain
curative work must be done to correct defects in the
marketability of the title, and such curative work entails
expense. ECAs failure to cure any title defects may render
some locations undrillable and cause ECA to lose its rights to
production from the Underlying Properties. In the event of such
a material title problem, proceeds available for distribution to
unitholders and the value of the trust units may be reduced.
The trust is passive in nature and will have no
stockholder voting rights in ECA, managerial, contractual or
other ability to influence ECA, or control over the field
operations of, sale of natural gas from, or development of, the
Underlying Properties.
Trust unitholders have no voting rights with respect to ECA and
therefore will have no managerial, contractual or other ability
to influence ECAs activities or operations of the gas
properties. In addition, pursuant to the Administrative and
Drilling Services Agreement, up to 10% of the PUD Wells may be
operated by third parties unrelated to ECA until completion of
ECAs drilling obligation, after which ECA may transfer
operations of any or all of the trust properties. Such third
party operators may not have the operational expertise of ECA
within the AMI. Gas properties are typically managed pursuant to
an operating agreement among the working interest owners in the
properties. The typical operating agreement contains procedures
whereby the owners of the working interests in the property
designate one of the interest owners to be the operator of the
property. Under these arrangements, the operator is typically
responsible for making all decisions relating to drilling
activities, sale of production, compliance with regulatory
requirements and other matters that affect the property. Neither
the trustee nor the trust unitholders has any contractual
ability to influence or control the field operations of, sale of
natural gas from, or future development of, the Underlying
Properties. The trust units are a passive investment that
entitle the trust unitholder to only receive cash distributions
from the royalty interests and natural gas hedging contracts
that will be transferred to the trust at closing.
ECA may transfer all or a portion of the Underlying
Properties after satisfying its drilling obligations to the
trust, subject to specified limitations; any transferee could
have a weaker financial position and/or be less experienced in
natural gas development and production than ECA.
ECA may at any time transfer all or part of the Underlying
Properties, subject to its obligation not to sell any of the
underlying PUD properties prior to satisfying its obligation to
drill the PUD Wells. You will not be entitled to vote on any
transfer of the Underlying Properties, and the trust will not
receive any proceeds from any such transfer. Following any
material sale or transfer of any of the Underlying Properties,
the Underlying Properties will continue to be subject to the PDP
and PUD Royalty Interests. The transferee would be responsible
for all of ECAs obligations relating to the royalty
interests on the portion of the Underlying Properties
transferred, and ECA
21
would have no continuing obligation to the trust for those
properties. Additionally, ECA may enter into farmout or joint
venture arrangements with respect to the wells burdened by the
trusts royalty interest. Any transferee, farmout
counterparty or joint venture partner could have a weaker
financial position
and/or
be
less experienced in natural gas development and production than
ECA.
The natural gas reserves estimated to be attributable to
the Underlying Properties of the trust are depleting assets and
production from those reserves will diminish over time.
Furthermore, the trust is precluded from acquiring other oil and
gas properties or royalty interests to replace the depleting
assets and production.
The proceeds payable to the trust from the royalty interests are
derived from the sale of the production of natural gas from the
Underlying Properties. The natural gas reserves attributable to
the Underlying Properties are depleting assets, which means that
the reserves of natural gas attributable to the Underlying
Properties will decline over time. As a result, the quantity of
natural gas produced from the Underlying Properties will decline
over time. Based on the estimated production volumes in the
reserve report, the gas production from proved producing
reserves attributable to the PDP Royalty Interest is projected
to decline at an average rate of approximately 9.7% per year
over the life of the trust. As a PUD Well is drilled and placed
on production, its reserves are expected to decline
approximately 37.5% during the first year of production,
approximately 14.7% during the next three to five years of
production and approximately 8.0% per year for the remainder of
the economically productive life of the well. These production
characteristics are generally consistent with other development
wells in the AMI. The anticipated rate of decline is an estimate
and actual decline rates may vary from those estimated.
Future maintenance may affect the quantity of proved reserves
that can be economically produced from the Underlying Properties
to which the wells relate. The timing and size of these projects
will depend on, among other factors, the market prices of
natural gas. With the exception of ECAs commitment to
drill the PUD Wells, ECA has no contractual obligation to make
capital expenditures on the Underlying Properties in the future.
Furthermore, for properties on which ECA is not designated as
the operator, ECA has no control over the timing or amount of
those capital expenditures. ECA also has the right to
non-consent and not participate in the capital expenditures on
properties for which it is not the operator, in which case ECA
and the trust will not receive the production resulting from
such capital expenditures. If ECA or other operators of the
wells to which the Underlying Properties relate do not implement
maintenance projects when warranted, the future rate of
production decline of proved reserves may be higher than the
rate currently expected by ECA or estimated in the reserve
report.
The trust agreement will provide that the trusts business
activities will be limited to owning the royalty interests and
any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyances
related to the royalty interests. As a result, the trust will
not be permitted to acquire other oil and gas properties or
royalty interests to replace the depleting assets and production
attributable to the trust.
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The amount of cash available for distribution by the trust
will be reduced by the amount of
post-production
costs, applicable taxes associated with the trusts
interest, trust expenses, incentive distributions and
reimbursement obligations payable to ECA.
The royalty interests and this trust will bear certain costs and
expenses that will reduce the amount of cash received by or
available for distribution by the trust to the holders of the
trust units. These costs and expenses include those described
below.
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Substantially all of the production from the Producing Wells and
the PUD Wells will utilize ECAs Greene Country Gathering
System. The trust will pay the initial Post-Production Services
Fee to ECA for use of such system, which includes ECAs
costs to gather, compress, transport, process, treat, dehydrate
and market the gas. This fee is fixed until ECAs
obligation to drill the PUD Wells is satisfied; thereafter, ECA
may increase this fee to the extent necessary to recover certain
capital expenditures on the Greene County Gathering System,
provided the resulting charge does not exceed the prevailing
charges in the area for similar services. Additionally, the
trust will be charged for the cost of fuel used in the
compression process or equivalent electricity charges when
electric compressors are used.
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There currently are no third party post-production costs;
however, any third party post-production costs incurred in the
future and associated with the trusts interests will
reduce cash received by or available for distribution, including
any amounts paid by ECA for transportation on downstream
interstate pipelines.
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Taxes allocated to or imposed on the trust will include
Pennsylvania franchise tax and any applicable property, ad
valorem, production, severance, excise and other similar taxes.
Currently, there are no taxes in Pennsylvania related to the
production or severance of oil and natural gas in Pennsylvania,
but there are currently proposals pending in both the
Pennsylvania Senate Finance and the House Energy and
Environmental Resources Committees to enact a severance tax, and
lawmakers may propose other taxes in the future. If adopted,
such taxes would be a post-production cost that is borne by the
trust.
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The trust will bear 100% of trust administrative expenses,
including fees paid to the trustee and the Delaware trustee and
an annual administrative services fee of $60,000 payable to ECA.
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The trust will also be responsible for paying other expenses
incurred as a result of being a publicly traded entity,
including costs associated with annual and quarterly reports to
unitholders, tax return and Schedule K-1 preparation and
distribution, independent auditor fees and registrar and
transfer agent fees.
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ECA will be entitled, during the subordination period, to
receive a quarterly incentive distribution from the trust in an
amount equal to 50% of the amount by which distributions paid to
all unitholders exceed the incentive thresholds described
herein. A more detailed description of these distributions is
set forth under the caption Description of the Trust
Agreement Fees and Expenses Fees to
ECA.
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ECA has incurred costs of approximately $5 million in
securing the hedging contracts to be transferred to the trust.
ECA will be entitled to reimbursement for these expenditures
only if and to the extent distributions to trust unitholders
would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to
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the common and subordinated unitholders. ECAs
reimbursement right will terminate at the end of the
subordination period.
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The amount of costs and expenses that will be borne by the trust
may vary materially from
quarter-to-quarter.
The extent by which the costs and expenses described above are
higher or lower in any quarter will directly decrease or
increase the amount received by the trust and available for
distribution to the unitholders. For a further summary of
post-production costs and applicable taxes for the producing
lives of the Producing Wells and PUD Wells, see The
Underlying Properties. Historical post-production costs
and taxes, however, may not be indicative of future
post-production costs and taxes.
A decrease in the differential between the price realized
by ECA for natural gas produced from the Underlying Properties
and the NYMEX or other benchmark price of natural gas could
reduce the proceeds to the trust and therefore the cash
distributions by the trust and the value of trust units.
The prices received for ECAs natural gas production
usually exceed the relevant benchmark prices, such as NYMEX,
that are used for calculating hedge positions. The difference
between the price received and the benchmark price is called a
basis differential. The differential may vary significantly due
to market conditions, the quality and location of production and
other factors. ECA cannot accurately predict natural gas
differentials. Decreases in the differential between the
realized price of natural gas and the benchmark price for
natural gas could reduce the proceeds to the trust and therefore
the cash distributions by the trust and the value of the trust
units.
ECA has entered into natural gas hedging contracts for the
benefit of the trust that cover only a portion of the estimated
natural gas production attributable to the trusts royalty
interests, and such hedging arrangements will terminate after
March 31, 2014. The trusts receipt of any payments
due based on these natural gas hedging contracts depends upon
the financial position of the hedge contract counterparties. A
default by any of the hedge contract counterparties could reduce
the amount of cash available for distribution to the trust
unitholders.
Fifty percent of the estimated natural gas production
attributable to the trusts royalty interests will be
hedged from April 1, 2010 through March 31, 2014. As a
result, the remaining 50% of estimated production through
March 31, 2014 and all production after such date will not
be hedged to protect against the price risks inherent in holding
interests in natural gas, a commodity that is frequently
characterized by significant price volatility. Furthermore,
while the use of hedging transactions limits the downside risk
of price declines, swaps may also limit the trusts ability
to realize cash flow from natural gas price increases on the
portion of the production attributable to the trusts
royalty interests that is hedged. The trust will not have any
ability to terminate the swaps before the expiration date.
In the event that any of the counterparties to the natural gas
hedging contracts default on their obligations to make payments
to the trust under the hedge contracts, the cash distributions
to the trust unitholders would likely be materially reduced as
the hedge payments are intended to provide additional cash to
the trust during periods of lower natural gas prices. ECA will
have no continuing obligation with respect to the natural gas
hedge contracts.
Natural gas wells are subject to operational hazards that
can cause substantial losses. ECA maintains insurance; however,
ECA may not be adequately insured for all such hazards.
There are a variety of operating risks inherent in natural gas
production and associated activities, such as fires, leaks,
explosions, mechanical problems, major equipment failures, blow-
24
outs, uncontrollable flow of natural gas, water or drilling
fluids, casing collapses, abnormally pressurized formations and
natural disasters. The occurrence of any of these or similar
accidents that temporarily or permanently halt the production
and sale of natural gas at any of the Underlying Properties will
reduce trust distributions by reducing the amount of proceeds
available for distribution.
Additionally, if any of such risks or similar accidents occur,
ECA could incur substantial losses as a result of injury or loss
of life, severe damage or destruction of property, natural
resources and equipment, regulatory investigation and penalties
and environmental damage and
clean-up
responsibility. If ECA experiences any of these problems, its
ability to conduct operations and perform its obligations to the
trust could be adversely affected. While ECA intends to obtain
and maintain insurance coverage it deems appropriate for these
risks with respect to the Underlying Properties, ECAs
operations may result in liabilities exceeding such insurance
coverage or liabilities not covered by insurance. If a well is
damaged, ECA would have no obligation to drill a replacement
well or make the trust whole for the loss.
The subordination of certain trust units held by ECA does
not assure that you will in fact receive any specified return on
your investment in the trust.
Although ECA will not be entitled to receive any distribution on
its subordinated units unless there is enough cash for all of
the common units to receive a distribution equal to the
subordination threshold for such quarter (which is equal to 80%
of the target distribution level for the corresponding quarter),
the subordinated units constitute only a 25% interest in the
trust, and this feature does not guarantee that common units
will receive a distribution equal to the subordination
threshold, or any distribution at all. Additionally, the
subordination period will terminate and the subordinated units
will convert into common units four quarters following
ECAs completion of its drilling obligation. Depending on
the prices at which ECA is able to sell volumes attributable to
the trust, the common units may receive a distribution that is
below the subordination threshold.
Estimates of future cash distributions to unitholders,
subordination thresholds and incentive thresholds are based on
assumptions that are inherently subjective and are subject to
significant business, economic, financial, legal, regulatory and
competitive risks and uncertainties that could cause actual cash
distributions to differ materially from those estimated.
The estimates of target distributions to unitholders,
subordination thresholds and incentive thresholds, as set forth
in Target Distributions and Subordination and Incentive
Thresholds, are based on ECAs calculations, and ECA
has not received an opinion or report on such calculations from
any independent accountants. Such calculations are based on
assumptions about drilling, production, natural gas prices,
hedging activities, capital expenditures, expenses, and other
matters that are inherently uncertain and are subject to
significant business, economic, financial, legal, regulatory and
competitive risks and uncertainties that could cause actual
results to differ materially from those estimated. In
particular, these estimates have assumed that natural gas
production is sold at prices consistent with NYMEX forward
pricing as of March 11, 2010 for the thirty-six month
period ending March 31, 2013 and increased thereafter by a
2.5% annual escalator (as adjusted for a basis differential of
$0.15 per MMBtu escalated at 2.5% annually starting in the
second quarter of 2013), capped at $9.00 per MMBtu starting
in 2025; however, actual sales prices may be significantly
lower. Additionally, these estimates assume that the PUD Wells
will be drilled on ECAs current anticipated schedule and
the related Underlying Properties will achieve production
volumes set forth in the reserve report; however, the drilling
of the development wells may be delayed and actual production
volumes may be significantly lower.
25
Furthermore, the subordination thresholds for each quarter
during the subordination period do not represent distributions
you should expect to receive. To the extent actual cash
distributions differ materially from those set forth in the
estimates underlying target distributions, the actual
distributions you receive may be lower than the target
distribution and the subordination threshold for the applicable
quarter. A cash distribution to trust unitholders below the
target distribution amount or the subordination threshold may
materially adversely affect the market price of the trust units.
The trustee may, under certain circumstances, sell the
royalty interests and dissolve the trust. The trust will begin
to terminate following the end of the
20-year
period in which the trust owns the Term Royalties.
The trustee must sell the royalty interests if the holders of a
majority of the trust units approve the sale or vote to dissolve
the trust. The trustee must also sell the royalty interests if
the gross proceeds to the trust are less than $1.5 million
for any four consecutive quarters. Sale of all the royalty
interests will result in the dissolution of the trust. The net
proceeds of any such sale will be distributed to the trust
unitholders. The trust will begin to liquidate on the
Termination Date. The trust unitholders will not be entitled to
receive any proceeds from the sale of production from the
Underlying Properties following such date. The Term Royalties
will automatically revert to ECA at the Termination Date, while
the Perpetual Royalties will be sold and the proceeds will be
distributed to the unitholders (including ECA to the extent of
any trust units it owns) at the Termination Date or soon
thereafter. ECA will have a first right of refusal to purchase
the Perpetual Royalties at the Termination Date. A more detailed
description of this right of first refusal is set forth under
the caption The Trust.
ECA and the Private Investors may sell trust units in the
public or private markets, and such sales could have an adverse
impact on the trading price of the common units.
After the closing of the offering, ECA will hold an aggregate of
3,395,433 common units and 4,500,000 subordinated
units. In addition, the Private Investors will hold
1,104,567 common units. All of the subordinated units will
automatically convert into common units at the end of the
subordination period, which is currently expected to occur on
April 1, 2014. ECA and the Private Investors have agreed
not to sell any trust units for a period of 180 days after
the date of this prospectus without the consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc., acting as representatives of the several underwriters. See
Underwriting. After such period, ECA and the Private
Investors may sell trust units in the public or private markets,
and any such sales could have an adverse impact on the price of
the common units or on any trading market that may develop. ECA
has granted registration rights to the Private Investors which,
if exercised, would facilitate sales of common units by such
holders. In addition, ECA would have the ability to register
common units for sale on its own behalf.
There has been no public market for the common units and
no independent appraisal of the value of the royalty interests
has been performed.
The initial public offering price of the common units will be
determined by negotiation among ECA and the underwriters. Among
the factors to be considered in determining the initial public
offering price, in addition to prevailing market conditions,
will be current and historical natural gas prices, current and
prospective conditions in the supply and demand for natural gas,
reserve and production quantities estimated for the royalty
interests and the trusts cash distributions prospects.
None of ECA, the trust or the underwriters will obtain any
independent appraisal or other opinion of the value of the
royalty interests other than the reserve report prepared by
Ryder Scott.
26
Conflicts of interest could arise between ECA and the
trust unitholders.
As a working interest owner in the Underlying Properties, ECA
could have interests that conflict with the interests of the
trust and the trust unitholders. For example:
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Notwithstanding its drilling obligation to the trust, ECAs
interests may conflict with those of the trust and the trust
unitholders in situations involving the development,
maintenance, operation or abandonment of the Underlying
Properties. Additionally, ECA may abandon a well which is
uneconomic to it while such well is still generating revenue for
the trust unitholders. Subsequent to fulfilling its drilling
obligation, ECA may make decisions with respect to expenditures
and decisions to allocate resources on projects in other areas
that adversely affect the Underlying Properties, including
reducing expenditures on these properties, which could cause gas
production to decline at a faster rate and thereby result in
lower cash distributions by the trust in the future.
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ECA may sell some or all of the Underlying Properties, subject
to its obligation not to sell any of the underlying PUD
properties prior to satisfying its obligation to drill the PUD
Wells. Such sale may not be in the best interests of the trust
unitholders. Any purchaser may lack ECAs experience in the
Marcellus Shale or its credit worthiness.
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ECA may, without the consent of the trust unitholders, require
the trust to release royalty interests with an aggregate value
to the trust of up to $5.0 million during any
12-month
period. These releases will be made only in connection with the
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests. See The Underlying
Properties Sale and abandonment of Underlying
Properties.
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After it has completed its drilling obligation, ECA may in its
discretion increase its Post-Production Services Fee for
post-production costs on its Greene County Gathering System to
the extent necessary to recover certain capital expenditures on
the Greene County Gathering System.
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ECA is permitted under the conveyance agreements creating the
royalty interests to enter into new processing and
transportation contracts without obtaining bids from or
otherwise negotiating with any independent third parties, and
ECA will deduct from the trusts proceeds any charges under
such contracts attributable to production from the trust
properties. Provisions in the conveyance agreements, however,
require that charges under future contracts with affiliates of
ECA relating to processing or transportation of natural gas must
be comparable to charges prevailing in the area for similar
services.
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ECA has registration rights and can sell its units without
considering the effects such sale may have on common unit prices
or on the trust itself. Additionally, ECA can vote its trust
units in its sole discretion.
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The trust is managed by a trustee who cannot be replaced
except at a special meeting of trust unitholders.
The business and affairs of the trust will be managed by the
trustee. Your voting rights as a trust unitholder are more
limited than those of stockholders of most public corporations.
For example, there is no requirement for annual meetings of
trust unitholders or for an annual or other periodic re-election
of the trustee. The trust agreement provides that the trustee
may only be removed and replaced by the holders of a majority of
the outstanding trust units, including trust units held by ECA,
at a special meeting of trust unitholders called by either the
trustee or
27
the holders of not less than 10% of the outstanding trust units.
As a result, it will be difficult for public unitholders to
remove or replace the trustee without the cooperation of ECA (so
long as it holds a significant percentage of total trust units)
or other holders of a substantial percentage of the outstanding
trust units.
Trust unitholders have limited ability to enforce
provisions of the royalty interests, and ECAs liability to
the trust is limited.
The trust agreement permits the trustee and the trust to sue ECA
or any other future owner of the Underlying Properties to
enforce the terms of the conveyances creating the PDP and PUD
Royalty Interests. If the trustee does not take appropriate
action to enforce provisions of these conveyances, trust
unitholders recourse would be limited to bringing a
lawsuit against the trustee to compel the trustee to take
specified actions. The trust agreement expressly limits a trust
unitholders ability to directly sue ECA or any other third
party other than the trustee. As a result, trust unitholders
will not be able to sue ECA or any future owner of the
Underlying Properties to enforce these rights. Furthermore, the
royalty interest conveyances provide that, except as set forth
in the conveyances, ECA will not be liable to the trust for the
manner in which it performs its duties in operating the
Underlying Properties as long as it acts in good faith.
Courts outside of Delaware may not recognize the limited
liability of the trust unitholders provided under Delaware
law.
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of corporations under the General
Corporation Law of the State of Delaware. No assurance can be
given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
ECA is subject to complex federal, state, local and other
laws and regulations that could adversely affect the cost,
manner or feasibility of conducting its operations or expose ECA
to significant liabilities.
ECAs natural gas exploration, production and
transportation operations are subject to complex and stringent
laws and regulations. In order to conduct its operations in
compliance with these laws and regulations, ECA must obtain and
maintain numerous permits, drilling bonds, approvals and
certificates from various federal, state and local governmental
authorities and engage in extensive reporting. ECA may incur
substantial costs in order to maintain compliance with these
existing laws and regulations. In addition, ECAs costs of
compliance may increase if existing laws and regulations are
revised or reinterpreted, or if new laws and regulations become
applicable to ECAs operations. Such costs could have a
material adverse effect on ECAs business, financial
condition and results of operations. ECA must also comply with
laws and regulations prohibiting fraud and market manipulations
in energy markets. To the extent ECA is a shipper on interstate
pipelines, it must comply with the tariffs of such pipelines and
with federal policies related to the use of interstate capacity.
Laws and regulations governing natural gas exploration and
production may also affect production levels. ECA is required to
comply with federal and state laws and regulations governing
conservation matters, including provisions related to the
unitization or pooling of the natural gas properties; the
establishment of maximum rates of production from natural gas
wells; the spacing of wells; the plugging and abandonment of
wells; and removal of related production equipment. These and
other laws and regulations can limit the amount of natural gas
ECA can produce from its wells, limit the number of wells it can
drill, or limit the locations at which it can conduct drilling
operations, which in turn could negatively impact trust
distributions,
28
estimated and actual future net revenues to the trust and
estimates of reserves attributable to the trusts interests.
New laws or regulations, or changes to existing laws or
regulations may unfavorably impact ECA, could result in
increased operating costs and have a material adverse effect on
ECAs financial condition and results of operations. For
example, Congress is currently considering legislation that, if
adopted in its proposed form, would subject companies involved
in natural gas and oil exploration and production activities to,
among other items, additional regulation of and restrictions on
hydraulic fracturing of wells, the elimination of most
U.S. federal tax incentives and deductions available to
natural gas exploration and production activities, and the
prohibition or additional regulation of private energy commodity
derivative and hedging activities. These and other potential
regulations could increase ECAs operating costs, reduce
ECAs liquidity, delay ECAs operations or otherwise
alter the way ECA conducts its business, which could have a
material adverse effect on ECAs financial condition,
results of operations and cash flows.
The ability of ECA to satisfy its obligations to the trust
depends on the financial position of ECA, and in the event of a
default by ECA in its obligation to drill the development wells,
or in the event of ECAs bankruptcy, it may be expensive
and time-consuming for the trust to exercise its
remedies.
ECA is a privately held, independent energy company engaged in
the exploration, development, production, gathering and
aggregation and sale of natural gas and oil, primarily in the
Appalachian Basin, Gulf Coast and Rocky Mountain regions in the
United States and in New Zealand. Pursuant to the terms of the
Administrative and Drilling Services Agreement, ECA will be
obligated to drill the PUD Wells at its own expense. ECA is also
the operator of all of the Producing Wells and will agree to
operate substantially all of the PUD Wells until completion of
its drilling obligation. The conveyances also provide that ECA
will be obligated to market, or cause to be marketed, the
natural gas production related to the Underlying Properties. Due
to the trusts reliance on ECA to fulfill these numerous
obligations, the value of the trusts royalty interest and
its ultimate cash available for distribution will be highly
dependent on ECAs performance. ECA will not be a reporting
company following this offering and will not file periodic
reports with the SEC. Therefore, as a trust unitholder, you will
not have access to financial information of ECA.
The ability of ECA to perform these obligations will depend on
ECAs future financial condition and economic performance
and access to capital, which in turn will depend upon the supply
and demand for natural gas and oil, prevailing economic
conditions and financial, business and other factors, many of
which are beyond the control of ECA. See Information about
Energy Corporation of America found on
page ECA-1
for additional information relating to ECA, including
information relating to the business of ECA, historical
financial statements of ECA and other financial information
relating to ECA.
In the event that ECA defaults on its obligation to drill the
PUD Wells, the trusts remedy would be to foreclose on the
trusts Drilling Support Lien on all of ECAs
remaining interests in the AMI to recover the security interest
in the amount of $91 million, which amount will be reduced
proportionately as each PUD Well is drilled. The process of
foreclosing on such collateral may be expensive and
time-consuming and delay the drilling and completion of the PUD
Wells; such delays and expenses would reduce trust distributions
by reducing the amount of proceeds available for distribution.
The amount of the security interest recovered is required to be
applied to completion of the drilling obligations of ECA, will
not result in any distribution to the trust unitholders and may
be insufficient to drill the number of wells needed for the
trust to realize the full value of the PUD Royalty Interest.
Furthermore, the trust would have to seek a new party to perform
the drilling and operations of the wells. The trust may not be
able to find a
29
replacement driller or operator, and it may not be able to enter
into a new agreement with such replacement party on favorable
terms within a reasonable period of time.
Due to uncertainty under the laws of Pennsylvania, there is a
risk that the royalty interests conveyed by ECA to the trust
would not be treated as real property interests, or interests in
hydrocarbons in place or to be produced. As a result, the
royalty interests might be treated as unsecured claims of the
trust against ECA in the event of ECAs bankruptcy. The
Royalty Interest Lien is intended to provide security to the
trust should the royalty interests be subject to such a
challenge. If the PDP Royalty Interest or the PUD Royalty
Interest were determined not to be a real property interest
owned by the trust, the trusts remedy would be to
foreclose on the trusts Royalty Interest Lien to cause the
trust to receive a volume of natural gas production from the
trust properties calculated in accordance with the provisions of
the conveyances of the royalty interests to the trust.
Foreclosure on the Royalty Interest Lien is exercisable only
following a bankruptcy filing of ECA or its successor and based
on an uncured payment default occurring under the conveyances of
the royalty interests to the trust existing at the time of, or
occurring after, such bankruptcy filing. Similar to the Drilling
Support Lien, the process of foreclosing to enforce the Royalty
Interest Lien may be expensive and time-consuming; and the
resulting delays and expenses would reduce trust distributions
by reducing the amount of proceeds available for distribution.
The proceeds of the royalty interests may be commingled, for a
period of time, with proceeds of ECAs retained interest.
It is possible that the trust may not have adequate facts to
trace its entitlement to funds in the commingled pool of funds
and that other persons may, in asserting claims against
ECAs retained interest, be able to assert claims to the
proceeds that should be delivered to the trust. In addition,
during a bankruptcy of ECA, it is possible that payments of the
royalties may be delayed or deferred. It is also possible that
the obligation to pay royalties will be disaffirmed or
cancelled. In either situation, the trust may need to look to
the Royalty Interest Lien to replace its rights under the
royalty interests. During the pendency of ECAs bankruptcy
proceedings, the trusts ability to foreclose on the
Drilling Support Lien or the Royalty Interest Lien, and the
ability to collect cash payments from customers being held in
ECAs accounts that are attributable to production from the
trust properties, may be stayed by the bankruptcy court. Delay
in realizing on the collateral for the Drilling Support Lien and
the Royalty Interest Lien is possible, and it cannot be
guaranteed that a bankruptcy court would permit such
foreclosure. It is possible that the bankruptcy would also delay
the execution of a new agreement with another driller or
operator. If the trust enters into a new agreement with a
drilling or operating partner, the new partner might not achieve
the same levels of production or sell natural gas at the same
prices as ECA was able to achieve.
ECAs performance of its drilling obligations to the
trust and the financial results of the trust may not be as
successful as the drilling and financial results of Eastern
American Natural Gas Trust or ECAs other royalty interest
ventures.
As disclosed in this prospectus, ECA previously sponsored the
formation of Eastern American Natural Gas Trust, and ECA has
previously sold term royalty interests in a separate transaction
to private investors. The historical results of operations and
performance of the Eastern American Natural Gas Trust should not
be relied on as an indicator of how this trust will perform.
The operations of ECA are subject to environmental laws
and regulations that may result in significant costs and
liabilities.
The natural gas exploration and production operations of ECA in
the Marcellus Shale are subject to stringent and comprehensive
federal, state and local laws and regulations governing the
30
discharge of materials into the environment or otherwise
relating to environmental protection. These laws and regulations
may impose numerous obligations that are applicable to
ECAs operations including the acquisition of a permit
before conducting drilling; water withdrawal or waste disposal
activities; the restriction of types, quantities and
concentration of materials that can be released into the
environment; the limitation or prohibition of drilling
activities on certain lands lying within wilderness, wetlands
and other protected areas; and the imposition of substantial
liabilities for pollution resulting from operations. Numerous
governmental authorities, such as the U.S. Environmental
Protection Agency (EPA) and analogous state
agencies, have the power to enforce compliance with these laws
and regulations and the permits issued under them, often
requiring difficult and costly actions. Failure to comply with
these laws and regulations may result in the assessment of
administrative, civil or criminal penalties; the imposition of
investigatory or remedial obligations; and the issuance of
injunctions limiting or preventing some or all of ECAs
operations.
There is inherent risk of incurring significant environmental
costs and liabilities in the performance of ECAs
operations due to its handling of petroleum hydrocarbons and
wastes, because of air emissions and wastewater discharges
related to its operations, and as a result of historical
industry operations and waste disposal practices. Under certain
environmental laws and regulations, ECA could be subject to
joint and several strict liability for the removal or
remediation of previously released materials or property
contamination regardless of whether ECA was responsible for the
release or contamination or if the operations were not in
compliance with all applicable laws at the time those actions
were taken. Private parties, including the owners of properties
upon which ECAs wells are drilled and facilities where
ECAs petroleum hydrocarbons or wastes are taken for
reclamation or disposal may also have the right to pursue legal
actions to enforce compliance, as well as to seek damages for
non-compliance, with environmental laws and regulations or for
personal injury or property damage. In addition, the risk of
accidental spills or releases could expose ECA to significant
liabilities that could have a material adverse effect on its
financial condition or results of operations. Changes in
environmental laws and regulations occur frequently, and any
changes that result in more stringent or costly waste handling,
storage, transport, disposal or cleanup requirements could
require ECA to make significant expenditures to attain and
maintain compliance and may otherwise have a material adverse
effect on its results of operations, competitive position or
financial condition. ECA may not be able to recover some or any
of these costs from insurance. As a result of the increased cost
of compliance, ECA may decide to discontinue drilling.
Additionally, permitting delays may inhibit ECAs ability
to drill the PUD Wells on schedule.
Climate change laws and regulations restricting emissions
of greenhouse gases could result in increased
operating costs and reduced demand for the natural gas that ECA
produces while the physical effects of climate change could
disrupt ECAs production and cause ECA to incur significant
costs in preparing for or responding to those effects.
On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, methane and other greenhouse gases
(GHGs) present a danger to public health and the
environment. These findings allow the agency to adopt and
implement regulations that would restrict emissions of GHGs
under existing provisions of the federal Clean Air Act.
Accordingly, the EPA has proposed regulations that would require
a reduction in emissions of GHGs from motor vehicles and could
trigger permit review for GHG emissions from certain stationary
sources. In addition, on October 30, 2009, the EPA
published a final rule requiring the reporting of GHG emissions
from specified large GHG emission sources in the United States,
beginning in 2011 for emissions occurring in 2010. Only very
recently, on March 23, 2010, the EPA announced a proposed
rulemaking that would expand its final rule on reporting of GHG
emissions to include owners and operators of onshore oil and
natural gas production. If the proposed rule is finalized in its
current form, monitoring of those newly covered sources would
commence on January 1,
31
2011. Also, on June 26, 2009, the U.S. House of
Representatives passed the American Clean Energy and
Security Act of 2009 (ACESA), which would
establish an economy-wide
cap-and-trade
program to reduce U.S. emissions of GHGs. Under this
legislation, the EPA would issue a capped and steadily declining
number of tradable emissions allowances authorizing emissions of
GHGs into the atmosphere. These reductions would be expected to
cause the cost of allowances to escalate significantly over
time. The net effect of ACESA will be to impose increasing costs
on the combustion of carbon-based fuels such as oil, refined
petroleum products and natural gas. The U.S. Senate has
begun work on its own legislation for restricting domestic GHG
emissions and the Obama Administration has indicated its support
for legislation to reduce GHG emissions through an emission
allowance system. At the state level, more than one-third of the
states, either individually or through multi-state regional
initiatives, already have begun implementing legal measures to
reduce emissions of GHGs. The adoption and implementation of any
regulations imposing reporting obligations on, or limiting
emissions of GHGs from, ECAs equipment and operations
could require ECA to incur costs to reduce emissions of GHGs
associated with its operations or could adversely affect demand
for the natural gas that it produces. Finally, it should be
noted that some scientists have concluded that increasing
concentrations of greenhouse gases in the Earths
atmosphere may produce climate changes that have significant
physical effects, such as increased frequency and severity of
storms, droughts, and floods and other climatic events; if any
such effects were to occur, they could have an adverse effect on
ECAs assets and operations.
Federal legislation and state legislative and regulatory
initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays
as well as adversely affect ECAs services.
Two companion bills have been introduced in the
U.S. Congress, known as the Fracturing Responsibility
and Awareness of Chemicals Act (FRAC Act),
that would repeal an exemption in the federal Safe Drinking
Water Act for the underground injection of hydraulic fracturing
fluids near drinking water sources. Hydraulic fracturing is an
important and commonly used process for the completion of
natural gas wells, and to a lesser extent, oil wells, in
formations with low permeabilities, such as shale formations,
and involves the pressurized injection of water, sand and
chemicals into rock formations to stimulate natural gas
production. Sponsors of the FRAC Act have asserted that
chemicals used in the fracturing process could adversely affect
drinking water supplies. If enacted, the FRAC Act could result
in additional regulatory burdens involving permitting,
construction standards for wells, monitoring, recordkeeping and
closure of wells. The FRAC Act also proposes requiring the
disclosure of chemical constituents used in the fracturing
process to state or federal regulatory authorities who would
then make such information publicly available. The availability
of this information could make it easier for third parties
opposing the hydraulic fracturing process to initiate legal
proceedings based on allegations that specific chemicals used in
the fracturing process could adversely affect groundwater.
Recently, on March 18, 2010, the EPA announced that it has
allocated $1.9 million in 2010 and has requested funding in
fiscal year 2011 for conducting a comprehensive research study
on the potential adverse impacts that hydraulic fracturing may
have on water quality and public health. In addition, various
state and local governments are considering increased regulatory
oversight of hydraulic fracturing through additional permit
requirements, operational restrictions and temporary or
permanent bans on hydraulic fracturing in certain
environmentally sensitive areas such as watersheds.
Specifically, the Pennsylvania Department of Environmental
Protection has adopted a new permitting policy concerning
discharges to surface waters from wastewater treatment
facilities handling flowback fluids and produced waters from oil
and gas well sites that could result in increased requirements
for treatment of these fluids and limitations on their discharge
to receiving waters. The adoption of the FRAC Act or any other
federal or state laws or regulations imposing reporting
obligations on, or otherwise limiting, the hydraulic fracturing
process could make it more difficult for ECA to complete natural
gas wells in the
32
Marcellus Shale as well as increase its costs of compliance and
doing business. Moreover, while performance of the EPA study is
not imminent, the results of such a study, once completed, could
further spur action towards federal legislation and regulation
of hydraulic fracturing activities. If ECA is unable to remove
and dispose of water at a reasonable cost and within applicable
environmental rules, ECAs ability to produce gas
commercially and in commercial quantities from the Underlying
Properties could be impaired.
Tax Risks
Related to the Trusts Common Units
The trusts tax treatment depends on its status as a
partnership for federal income tax purposes. If the IRS were to
treat the trust as a corporation for federal income tax
purposes, then its cash available for distribution to you would
be substantially reduced.
The anticipated after-tax economic benefit of an investment in
the trust units depends largely on the trust being treated as a
partnership for federal income tax purposes. The trust has not
requested, and does not plan to request, a ruling from the
Internal Revenue Service, or IRS, on this or any other tax
matter affecting it.
It is possible in certain circumstances for a publicly traded
trust otherwise treated as a partnership, such as the trust, to
be treated as a corporation for federal income tax purposes.
Although the trust does not believe based upon its current
activities that it is so treated, a change in current law could
cause it to be treated as a corporation for federal income tax
purposes or otherwise subject it to taxation as an entity.
If the trust was treated as a corporation for federal income tax
purposes, it would pay federal income tax on its taxable income
at the corporate tax rate, which is currently a maximum of 35%,
and would likely be required to pay state income tax.
Distributions to you would generally be taxed again as corporate
distributions, and no income, gains, losses, deductions or
credits would flow through to you. Because a tax would be
imposed upon the trust as a corporation, its cash available for
distribution to you would be substantially reduced. Therefore,
treatment of the trust as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to the trust unitholders, likely causing a substantial
reduction in the value of the trust units.
The trust agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects the trust to taxation as a corporation or otherwise
subjects it to entity-level taxation for federal income tax
purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on the trust.
If the trust were subjected to a material amount of
additional entity-level taxation by Pennsylvania or any other
states, it would reduce the trusts cash available for
distribution to you.
The trust will be required to pay Pennsylvania franchise tax on
its capital stock value, as determined pursuant to the statute
and apportioned to Pennsylvania. The current tax rate of 0.289%
is currently scheduled to be reduced to 0.189% in 2012 and
0.089% in 2013 and to be completely phased out in 2014. This
schedule may be altered and the taxes left in place subject to
the General Assembly in its annual budget process. Changes in
current state law may subject the trust to additional
entity-level taxation by Pennsylvania or other states. Because
of widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of any
additional taxes on the trust may substantially reduce the
33
cash available for distribution to you and, therefore,
negatively impact the value of an investment in the trust units.
The trust agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects the trust to additional amounts of entity-level
taxation for state or local income tax purposes, the target
distribution amounts may be adjusted to reflect the impact of
that law on the trust.
The tax treatment of an investment in trust units could be
affected by recent and potential legislative, judicial or
administrative changes and differing interpretations, possibly
on a retroactive basis.
The recently enacted Health Care and Education Reconciliation
Act of 2010 includes a provision that, in taxable years
beginning after December 31, 2012, subjects an individual
having adjusted gross income in excess of $200,000 (or $250,000
for married taxpayers filing joint returns) to an additional
medicare tax equal generally to 3.8% of the lesser
of such excess or the individuals net investment income,
which appears to include interest income and royalty income
derived from investments such as the trust units as well as any
net gain from the disposition of trust units. In addition,
absent new legislation extending the current rates, beginning
January 1, 2011, the highest marginal U.S. federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Current law may change so as to cause the trust to be treated as
a corporation for federal income tax purposes or otherwise
subject the trust to entity-level taxation. Specifically, the
present federal income tax treatment of publicly traded
partnerships, including the trust, or an investment in the trust
units may be modified by administrative, legislative or judicial
interpretation at any time. For example, at the federal level,
legislation has been proposed that would eliminate partnership
tax treatment for certain publicly traded partnerships. Although
such legislation would not apply to the trust as currently
proposed, it could be amended prior to enactment in a manner
that does apply to the trust.
If the IRS contests the federal income tax positions the
trust takes, the market for the trust units may be adversely
impacted and the cost of any IRS contest will reduce the
trusts cash available for distribution to you.
The trust has not requested a ruling from the IRS with respect
to its treatment as a partnership for federal income tax
purposes or any other matter affecting the trust. The IRS may
adopt positions that differ from the conclusions of the
trusts counsel expressed in this prospectus or from the
positions the trust takes. It may be necessary to resort to
administrative or court proceedings to attempt to sustain some
or all of the conclusions of the trusts counsel or the
positions the trust takes. A court may not agree with some or
all of the conclusions of the trusts counsel or positions
the trust takes. Any contest with the IRS may materially and
adversely impact the market for the trust units and the price at
which they trade. In addition, the trusts costs of any
contest with the IRS will be borne indirectly by the trust
unitholders because the costs will reduce the trusts cash
available for distribution.
You will be required to pay taxes on your share of the
trusts income even if you do not receive any cash
distributions from the trust.
Because the trust unitholders will be treated as partners to
whom the trust will allocate taxable income which could be
different in amount than the cash the trust distributes, you
will be required to pay any federal income taxes and, in some
cases, state and local income taxes on your share of the
trusts taxable income even if you receive no cash
distributions from the trust.
34
You may not receive cash distributions from the trust equal to
your share of the trusts taxable income or even equal to
the actual tax liability that results from that income.
Tax gain or loss on the disposition of the trust units
could be more or less than expected.
If you sell your trust units, you will recognize a gain or loss
equal to the difference between the amount realized and your tax
basis in those trust units. Because distributions in excess of
your allocable share of the trusts net taxable income
decrease your tax basis in your trust units, the amount, if any,
of such prior excess distributions with respect to the trust
units you sell will, in effect, become taxable income to you if
you sell such trust units at a price greater than your tax basis
in those trust units, even if the price you receive is less than
your original cost. Furthermore, a substantial portion of the
amount realized, whether or not representing gain, may be taxed
as ordinary income due to potential recapture items, including
depletion recapture. Please read Federal Income Tax
Considerations Disposition of
Trust Units Recognition of Gain or Loss
for a further discussion of the foregoing.
Tax-exempt entities and
non-U.S.
persons face unique tax issues from owning the trust units that
may result in adverse tax consequences to them.
Investment in trust units by tax-exempt entities, such as
individual retirement accounts (known as IRAs), and
non-U.S. persons
raises issues unique to them. For example, distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
may be required to file U.S. federal income tax returns and
pay tax on their share of the trusts taxable income. If
you are a tax exempt entity or a
non-U.S. person,
you should consult a tax advisor before investing in the trust
units.
The trust will treat each purchaser of trust units as
having the same economic attributes without regard to the actual
trust units purchased. The IRS may challenge this treatment,
which could adversely affect the value of the trust
units.
Due to a number of factors, including the trusts inability
to match transferors and transferees of trust units, the trust
will adopt positions that may not conform to all aspects of
existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. It also could affect the timing of
these tax benefits or the amount of gain from your sale of trust
units and could have a negative impact on the value of the trust
units or result in audit adjustments to your tax returns. Please
read Federal Income Tax Considerations Tax
Consequences of Trust Unit Ownership
Section 754 Election.
The trust will prorate its items of income, gain, loss and
deduction between transferors and transferees of the trust units
each month based upon the ownership of the trust units on the
first day of each month, instead of on the basis of the date a
particular trust unit is transferred. The IRS may challenge this
treatment, which could change the allocation of items of income,
gain, loss and deduction among the trust unitholders.
The trust will generally prorate its items of income, gain, loss
and deduction between transferors and transferees of the trust
units each month based upon the ownership of the trust units on
the first day of each month, instead of on the basis of the date
a particular trust unit is transferred. The use of this
proration method may not be permitted under existing Treasury
Regulations, and, accordingly, the trusts counsel is
unable to opine as to the validity of this method. Recently,
however, the U.S. Treasury Department issued proposed
Treasury Regulations that provide a safe harbor pursuant to
which publicly traded partnerships may use a similar monthly
simplifying convention to allocate tax items among transferor
and transferee unitholders. Nonetheless, the proposed
regulations do not specifically authorize the use of the
proration
35
method the trust will adopt. If the IRS were to challenge the
trusts proration method, the trust may be required to
change its allocation of items of income, gain, loss and
deduction among the trust unitholders. Please read Federal
Income Tax Considerations Disposition of
Trust Units Allocations Between Transferors and
Transferees.
A trust unitholder whose trust units are loaned to a
short seller to cover a short sale of trust units
may be considered as having disposed of those trust units. If
so, he would no longer be treated for tax purposes as a partner
with respect to those trust units during the period of the loan
and may recognize gain or loss from the disposition.
Because a trust unitholder whose trust units are loaned to a
short seller to cover a short sale of trust units
may be considered as having disposed of the loaned trust units,
he may no longer be treated for tax purposes as a partner with
respect to those trust units during the period of the loan to
the short seller and the unitholder may recognize gain or loss
from such disposition. Moreover, during the period of the loan
to the short seller, any of the trusts income, gain, loss
or deduction with respect to those trust units may not be
reportable by the unitholder and any cash distributions received
by the unitholder as to those trust units could be fully taxable
as ordinary income. The trusts counsel has not rendered an
opinion regarding the treatment of a unitholder where trust
units are loaned to a short seller to cover a short sale of
trust units; therefore, trust unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
loaning their trust units.
The trust will adopt certain valuation methodologies that
may affect the income, gain, loss and deduction allocable to the
trust unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the trust units.
The federal income tax consequences of the ownership and
disposition of trust units will depend in part on the
trusts estimates of the relative fair market values, and
the initial tax bases of the trusts assets. Although the
trust may from time to time consult with professional appraisers
regarding valuation matters, the trust will make many of the
relative fair market value estimates itself. These estimates and
determinations of basis are subject to challenge and will not be
binding on the IRS or the courts. If the estimates of fair
market value or basis are later found to be incorrect, the
character and amount of items of income, gain, loss or
deductions previously reported by trust unitholders might
change, and trust unitholders might be required to adjust their
tax liability for prior years and incur interest and penalties
with respect to those adjustments.
The sale or exchange of 50% or more of the trusts
capital and profits interests during any twelve-month period
will result in the termination of the trusts partnership
status for federal income tax purposes.
The trust will be considered to have technically terminated for
federal income tax purposes if there is a sale or exchange of
50% or more of the total interests in its capital and profits
within a twelve-month period. For purposes of determining
whether the 50% threshold has been met, multiple sales of the
same trust unit within any 12 month period will be counted
only once. The trusts termination would, among other
things, result in the closing of its taxable year for all trust
unitholders, which would result in the trust filing two tax
returns (and the trust unitholders could receive two Schedules
K-1) for one calendar year. The IRS has recently announced a
relief procedure whereby if a publicly traded partnership that
has technically terminated requests and the IRS grants special
relief, among other things, the partnership will be required to
provide only a single
Schedule K-1
to unitholders for the tax year in which the termination occurs.
In the case of a unitholder reporting on a taxable year other
than a calendar year ending December 31, the
36
closing of the trusts taxable year may also result in more
than twelve months of the trusts taxable income being
includable in his taxable income for the year of termination. A
technical termination would not affect the trusts
classification as a partnership for federal income tax purposes,
but instead, the trust would be treated as a new partnership for
tax purposes. If treated as a new partnership, the trust must
make new tax elections and could be subject to penalties if the
trust is unable to determine that a technical termination
occurred.
Certain federal income tax preferences currently available
with respect to natural gas production may be eliminated as a
result of future legislation.
Among the changes contained in President Obamas Budget
Proposal for Fiscal Year 2011 (the 2011 Budget) is
the elimination of certain key U.S. federal income tax
preferences relating to natural gas exploration and production.
The 2011 Budget proposes to eliminate certain tax preferences
applicable to taxpayers engaged in the exploration or production
of natural resources effective in 2011. Specifically, the 2011
Budget proposes to repeal the deduction for percentage depletion
with respect to oil and natural gas wells, including interests
such as the Perpetual Royalty Interests, in which case only cost
depletion would be available.
37
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements
within the meaning of Section 27A of the Securities Act and
the Private Securities Litigation Reform Act of 1995 about ECA
and the trust that are subject to risks and uncertainties. All
statements other than statements of historical fact included in
this document, including, without limitation, statements under
Summary and Risk Factors regarding the
financial position, business strategy, production and reserve
growth, and other plans and objectives for the future operations
of ECA and the activities of the trust are forward-looking
statements.
Such statements may be influenced by factors that could cause
actual outcomes and results to differ materially from those
projected. Forward-looking statements are subject to risks and
uncertainties and include statements made in this prospectus
under Target Distributions and Subordination and Incentive
Thresholds, statements pertaining to future development
activities and costs, and other statements in this prospectus
that are prospective and constitute forward-looking statements.
When used in this document, the words believes,
expects, anticipates,
intends or similar expressions are intended to
identify such forward-looking statements. The following
important factors, in addition to those discussed elsewhere in
this document, could affect the future results of the energy
industry in general, and ECA and the trust in particular, and
could cause those results to differ materially from those
expressed in such forward-looking statements:
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risks incident to the drilling and operation of natural gas
wells;
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future production and development costs;
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the effect of existing and future laws and regulatory actions;
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the effect of changes in commodity prices, the ability of the
trusts hedge counterparties to meet their contractual
obligations and conditions in the capital markets;
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competition from others in the energy industry; and
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uncertainty of estimates of natural gas reserves and production.
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This prospectus describes other important factors that could
cause actual results to differ materially from expectations of
ECA and the trust, including under the heading Risk
Factors. All written and oral forward-looking statements
attributable to ECA or the trust or persons acting on behalf of
ECA or the trust are expressly qualified in their entirety by
such factors.
38
USE OF
PROCEEDS
The trust is offering the common units to be sold in this
offering. Assuming no exercise of the underwriters
over-allotment option and an initial public offering price of
$ per common unit, the
estimated net proceeds of this offering will be approximately
$ million, after deducting
underwriting discounts and commissions and offering expenses.
The trust will use the net proceeds to pay ECAs
wholly-owned subsidiary for the conveyance of the Term
Royalties. In turn, such subsidiary will use all of such amount
to repay a $
million
demand note payable to ECA issued as consideration for the
transfer of the Term Royalties thereto.
An increase or decrease in the initial public offering price of
$1.00 per common unit would cause the net proceeds from the
offering, after deducting underwriting discounts and
commissions, to increase or decrease by
$ million. If the proceeds
increase due to a higher initial public offering price, the
trust will distribute the additional proceeds to ECA as
consideration for its contribution of the Perpetual Royalties.
If the proceeds decrease due to a lower initial public offering
price, the trust will decrease the amount of proceeds paid to
ECAs subsidiary.
The trust will use the net proceeds from any exercise of the
underwriters over-allotment option to repurchase an equal
number of common units from ECA at the initial public offering
price, after deducting underwriting discounts and commissions.
ECA will use the proceeds received both from the repayment of
the demand note by ECAs subsidiary and from any exercise
of the underwriters over-allotment option to purchase
209,316 common units from the Private Investors at the
initial public offering price and for general corporate
purposes, including for the drilling of the PUD Wells. Please
read Certain Transactions.
39
NATURAL
GAS FUNDAMENTALS IN THE MARCELLUS SHALE
DEMAND
FOR NATURAL GAS
Natural gas continues to be a critical component of energy
consumption in the United States, accounting for approximately
24.4% of all energy used in 2009, representing approximately
22.8 Tcf of natural gas, according to the U.S. Energy
Information Administration (EIA). According to the
EIA, during the period from 2001 through 2009, natural gas
consumption increased by 2.7% overall from an average of
approximately 60.9 Bcf per day in 2001 to an average of
approximately 62.6 Bcf per day in 2009.
The EIA estimates that real gross domestic product will grow by
2.4% per year from 2008 to 2035 (Annual Energy Outlook 2010).
Over the same period, the EIA estimates that total domestic
energy consumption will increase by over 19%. Consumption of
natural gas is projected to continue to increase through this
period due to:
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domestic economic and population growth;
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added capacity of natural gas-fired, as opposed to coal-fired,
electricity generation;
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growth in the application of natural gas as a fuel source as a
means of diversifying away from foreign oil, such as in natural
gas vehicles; and
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indirectly through additions of electric vehicles.
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NATURAL
GAS RESERVES AND PRODUCTION
Historically, the majority of the domestic natural gas supply
has been produced from onshore and offshore conventional sources
and is supplemented by production from historically declining
pipeline imports from Canada, imports of liquefied natural gas
(LNG) from foreign sources as well as some
production in Alaska. In order to maintain current levels of
U.S. natural gas supply and to meet the projected increase
in demand, new sources of domestic natural gas must continue to
be developed to offset an established trend of depletion
associated with these conventional sources as well as the
uncertainty of future LNG imports and infrastructure challenges
associated with sourcing additional production from Alaska. Over
the past several years, a fundamental shift in natural gas
production has emerged with the increased contribution of
natural gas from unconventional resources, defined by the EIA as
natural gas produced from shale formations and coalbeds. The
emergence of these unconventional resources has been made
possible through advances in technology that have allowed
producers to extract significant volumes of natural gas from
these unconventional plays at cost-advantaged per unit economics
versus most conventional sources.
40
The U.S. Geological Service, Mineral Management Service and
EIA estimate that in 2010 the U.S. possesses over 2,000 Tcf
of technically recoverable natural gas resources, representing a
92 year reserve life based on current production levels, an
increase of approximately 30% from 2008 estimates of technically
recoverable natural gas resources, which is primarily driven by
shale gas and other unconventional sources. As total energy
consumption increases and the depletion of onshore and offshore
conventional resources continues, natural gas from
unconventional resources is forecast to continue to gain market
share from higher-cost conventional sources of natural gas.
Natural gas production from shale formations is forecast to
provide the majority of the growth in unconventional natural gas
supply, increasing to approximately 26% of total
U.S. natural gas supply in 2035 as compared with 11.5% in
2009. This represents a projected two-fold increase in natural
gas shales market share of U.S. natural gas supply.
The chart below illustrates the composition of the EIAs
forecasted natural gas production through 2035.
OVERVIEW
OF THE MARCELLUS SHALE
The Marcellus Shale formation is the most expansive shale gas
play in the U.S., spanning six states in the northeastern U.S.
In its April 2009
Modern Shale Gas: A Primer
, the United
States Department of Energy quoted an estimated potential
recoverable resource in the Marcellus Shale formation of over
260 Tcf of gas. The Marcellus Shale is a black, organic rich
shale formation located at depths between 6,000 and
8,500 feet, covering approximately 95,000 square miles
at an average thickness of 50 ft to 200 ft. In the area of the
Underlying Properties in Greene County, Pennsylvania, the
Marcellus Shale ranges in thickness from 135 feet to
180 feet.
The first commercial well drilled and completed in the Marcellus
Shale was in 2005 in Pennsylvania. Since the beginning of 2007,
there have been approximately 2,700 wells permitted in
Pennsylvania in the Marcellus Shale and over 1,050 of the
approved wells have been drilled.
41
In 2009, more than 550 wells were drilled in the Marcellus
Shale, making it one of the most active and prominent shale gas
plays in the U.S., and it is expected to continue to be an area
of active, widespread drilling. During 2009, there were more
than 50 operators active in the play.
Advances in modern drilling and completion technologies, such as
horizontal drilling and hydraulic fracturing, have increased the
value potential for many properties in Appalachia by enabling
better exploitation of the Marcellus Shale formation and other
unconventional reservoirs that are challenging to produce
efficiently. In general, horizontal wells use directional
drilling to create one or more lateral legs designed to allow
the well bore to stay in contact with the reservoir longer and
to intersect more vertical fractures in the formation than
conventional methods. These lateral legs can be several thousand
feet long. While it is more expensive than vertical drilling on
a per well basis, horizontal drilling may improve overall
returns on investment by increasing recovery volumes and rates,
limiting the number of wells necessary to develop an area and
reducing the costs and surface disturbances caused by multiple
vertical wells. Horizontal drilling and completion techniques
have shown improvements in terms of costs and drilling times
throughout the Marcellus Shale. ECA has increased the
productivity of its operations in Appalachia which target
development of the Marcellus Shale formation through the use of
horizontal drilling.
42
ENERGY
CORPORATION OF AMERICA
ECA is a privately held energy company engaged in the
exploration, development, production, gathering, aggregation and
sale of natural gas and oil, primarily in the Appalachian Basin,
Gulf Coast and Rocky Mountain regions in the United States and
in New Zealand. ECA or its predecessors have owned and operated
natural gas properties in the Appalachian Basin for more than
45 years, and ECA is one of the largest natural gas
operators in the Appalachian Basin. As of December 31,
2009, ECA operated approximately 5,100 wells in the
Appalachian Basin and had an aggregate leasehold position of
approximately one million gross acres with 85% of this acreage
held by production. ECA sells gas from its own wells as well as
third-party wells to local gas distribution companies,
industrial end users located in the Northeast, other gas
marketing entities and into the spot market for gas delivered
into interstate pipelines. ECA owns and operates approximately
5,000 miles of gathering lines and intrastate pipelines
that are used in connection with its gas aggregation activities.
During the fiscal year ended June 30, 2009, ECA and its
affiliates aggregated and sold 22.5 Bcf of gas for an
average of 62 MMcf of gas per day, of which 20.7 Bcf,
or 57 MMcf per day, represented sales of gas produced from
wells operated by ECA.
Substantially all of the production subject to the PDP Royalty
Interest and PUD Royalty Interest will be gathered by ECAs
Greene County Gathering System. This system currently accesses
two separate interconnects with the Texas Eastern Transmission,
L.P. and Columbia Gas Transmission, L.L.C. interstate pipeline
systems and includes six (6) compressors (with 8,860 total
horsepower) together with associated processing equipment.
ECAs interconnect agreements with these interstate
pipelines currently allow it to deliver at the interconnections
between ECAs facilities and the interstate pipelines up to
a total of 110,000 MMBtu per day for transportation by the
interstate pipelines to ECAs customers (approximately
16,000 MMBtu per day is currently being utilized), which is
in excess of its current and expected volumes from the
Underlying Properties. To the extent necessary, ECA will add
additional compression and related facilities to this system at
no cost to the trust, other than potential increases to the
Post-Production Service fee to the extent necessary to recover
certain capital expenditures after drilling is complete.
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger in
June 1995. ECAs predecessor began operating in the
Appalachian Basin in 1963. ECAs principal offices are
located at 4643 South Ulster Street, Suite 1100, Denver,
Colorado 80237, and its telephone number is
(303) 694-2667.
For additional information concerning ECA, see Information
about Energy Corporation of America beginning on
page ECA-1
of this prospectus. ECA will not be a reporting company
following this offering and will not file periodic reports with
the SEC. Therefore, as a trust unitholder, you will not have
access to the financial information of ECA.
The trust units do not represent interests in or obligations
of ECA.
43
SUMMARY
CONSOLIDATED FINANCIAL DATA OF ECA
The summary consolidated financial data presented below should
be read in conjunction with the audited consolidated financial
statements and the unaudited condensed consolidated financial
statements of ECA and the related notes and
Managements Discussion and Analysis of Financial
Condition and Results of Operations of Energy Corporation of
America included elsewhere in this prospectus. The
following summary consolidated financial data of ECA as of, and
for the years ended, June 30, 2007, 2008 and 2009 have been
derived from ECAs audited consolidated financial
statements included elsewhere in this prospectus. The following
summary consolidated financial data of ECA as of
December 31, 2009 and for the six-month periods ended
December 31, 2008 and 2009 have been derived from
ECAs unaudited interim condensed consolidated financial
statements. The unaudited financial statements were prepared on
a basis consistent with the audited statements and, in the
opinion of ECA, include all adjustments (consisting only of
normal recurring adjustments) necessary to present fairly the
results of ECA for the periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
Year Ended June 30,
|
|
|
December 31,
|
|
Historical Results
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
(Dollars in thousands, except per share and reserve data)
|
|
|
(Unaudited)
|
|
|
Operating revenue
|
|
$
|
211,954
|
|
|
$
|
247,071
|
|
|
$
|
216,220
|
|
|
$
|
125,110
|
|
|
$
|
85,040
|
|
Income from operations
|
|
|
40,658
|
|
|
|
51,912
|
|
|
|
30,350
|
|
|
|
15,478
|
|
|
|
11,989
|
|
Earnings per common share basic and diluted
|
|
|
33.66
|
|
|
|
19.93
|
|
|
|
36.98
|
|
|
|
25.39
|
|
|
|
2.85
|
|
Dividends declared
|
|
|
11.23
|
|
|
|
12.50
|
|
|
|
12.50
|
|
|
|
6.25
|
|
|
|
6.50
|
|
Total assets
|
|
|
413,321
|
|
|
|
557,980
|
|
|
|
543,719
|
|
|
|
538,501
|
|
|
|
534,025
|
|
Total long-term debt
|
|
|
135,166
|
|
|
|
197,125
|
|
|
|
218,134
|
|
|
|
213,490
|
|
|
|
237,779
|
|
Production (MMcfe) (unaudited)
|
|
|
9,636
|
|
|
|
10,684
|
|
|
|
9,646
|
|
|
|
5,099
|
|
|
|
5,464
|
|
Net proved developed reserves (MMcfe) (unaudited)
|
|
|
173,474
|
|
|
|
176,672
|
|
|
|
145,102
|
|
|
|
|
|
|
|
|
|
44
MANAGEMENT
OF ECA
The executive officers and directors of ECA are listed below,
together with a description of their experience and certain
other information. All of the directors were elected or
re-elected for a one-year term at ECAs December 2009
annual meeting of stockholders. Executive officers are appointed
by the Board of Directors.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with ECA or its Subsidiaries
|
|
John Mork
|
|
|
62
|
|
|
President and Chief Executive Officer
|
Michael S. Fletcher
|
|
|
60
|
|
|
Chief Financial Officer
|
Donald C. Supcoe
|
|
|
53
|
|
|
Senior Vice President, Secretary and General Counsel
|
J. Michael Forbes
|
|
|
49
|
|
|
Vice President and Treasurer
|
Kyle M. Mork
|
|
|
30
|
|
|
Vice President of Eastern Operations
|
George V. OMalley
|
|
|
58
|
|
|
Vice President Accounting
|
W. Gaston Caperton, III
|
|
|
70
|
|
|
Director
|
Peter H. Coors
|
|
|
63
|
|
|
Director
|
L.B. Curtis
|
|
|
85
|
|
|
Director (Chairman Emeritus)
|
John J. Dorgan
|
|
|
86
|
|
|
Director
|
John S. Fischer
|
|
|
59
|
|
|
Director
|
Thomas R. Goodwin
|
|
|
66
|
|
|
Director (Chairman)
|
F.H. McCullough, III
|
|
|
62
|
|
|
Director
|
Julie M. Mork
|
|
|
59
|
|
|
Director
|
Jerry W. Neely
|
|
|
73
|
|
|
Director
|
Arthur C. Nielsen, Jr.
|
|
|
90
|
|
|
Director
|
Jay S. Pifer
|
|
|
72
|
|
|
Director
|
John Mork
has been President and Chief Executive
Officer of ECA and a Director of ECA since its formation.
Mr. Mork served in various capacities at Union Oil Company
until 1972 when he joined Pacific States Gas and Oil, Inc. and
subsequently founded Eastern American Energy Corporation
(EAEC). Mr. Mork was President and a Director
of EAEC from 1973 until 1993 with the incorporation of ECA.
Mr. Mork is a past Director of the Independent Petroleum
Association of America, and the Independent Oil and Gas
Association of West Virginia. Mr. Mork was a member of and
held various positions with the Young Presidents
Organization from 1984 until 1998. He also founded the Mountain
State Chapter of the Young Presidents Organization located
in Charleston, West Virginia. He is currently a member of the
Chief Executives Organization, the World Presidents
Organization, the University of Southern California Engineering
School Board of Councilors and the University of Southern
California Board of Trustees. Mr. Mork holds a Bachelor of
Science Degree in Petroleum Engineering from the University of
Southern California and is a graduate of the Stanford Business
School Program for Chief Executive Officers. Mr. Mork
serves on the Board of Directors of the ECA Foundation, Inc. He
is the husband of Julie Mork and the father of Kyle Mork.
Michael S. Fletcher
has been Chief Financial
Officer of ECA since December 1999. He also held the position of
Treasurer of ECA from December 1999 through December 2000. In
addition, Mr. Fletcher was President of Mountaineer Gas
Company from 1998 until ECA sold Mountaineer in August 2000.
Prior to becoming President in 1998, he held the positions of
Senior Vice President and Chief Financial Officer of
Mountaineer. Before joining Mountaineer in 1987,
Mr. Fletcher was a partner of Arthur Andersen and Company
and was employed by that firm for fifteen years.
Mr. Fletcher is a Certified Public Accountant and a
graduate of Utah State
45
University with a Bachelor Degree in Accounting.
Mr. Fletcher serves on the Board of Directors of the ECA
Foundation, Inc.
Donald C. Supcoe
has been a Director of the ECA
since 2005. He has served as Senior Vice President, Corporate
Secretary and General Counsel since 2000 and is responsible for
ECAs operations east of the Mississippi River.
Mr. Supcoe was the Senior Vice President of Mountaineer Gas
Company from 1998 until its sale in August 2000. Prior to
joining Mountaineer in 1998, he was the Vice President, General
Counsel and Corporate Secretary of ECAs predecessor where
he held various positions since 1981. Mr. Supcoe is active
in the Independent Oil and Gas Association of West Virginia and
currently serves as President of that organization. He is also a
past Vice President of the Independent Petroleum Association of
America. Mr. Supcoe is currently a member of the Board of
Directors of Mid-Atlantic Holdings, Inc., and is a Trustee at
Large of the Energy and Mineral Law Foundation. Mr. Supcoe
graduated from West Virginia University with a Bachelor of
Science Degree in Business Administration. Mr. Supcoe
received a Doctor of Jurisprudence Degree from West Virginia
University College of Law. Mr. Supcoe serves on the Board
of Directors of the ECA Foundation, Inc.
J. Michael Forbes
is Vice President and Treasurer
of ECA. Mr. Forbes has been an officer of ECA since 1995
and prior to that was an officer with its predecessor, which he
joined in 1982. Mr. Forbes graduated with a Bachelor of
Arts in Accounting and Finance and a minor in Economics from
Glenville State College and is a Certified Public Accountant. He
also holds a Master of Business Administration from Marshall
University and is a graduate of Stanford Universitys
Program for Chief Financial Officers. Mr. Forbes serves on
the board for numerous community organizations, including Thomas
Health Systems where he serves as First Vice Chairman, the ECA
Foundation, Inc. and is the Past Chairman of the YMCA of the
Kanawha Valley.
Kyle M. Mork
has been the Vice President of
Eastern Operations for ECA since 2006. He began his career with
Halliburton Energy Services as a stimulation engineer before
moving to ECA in 2003 as a drilling engineer in Houston, Texas.
In 2004, he became the Drilling Manager for ECAs Eastern
Region based in Charleston, West Virginia. He graduated in 2002
with a Bachelor of Science Degree in Chemical Engineering from
Cornell University, and has taken Masters level courses in
Petroleum Engineering at the University of Southern California.
Currently, he is enrolled in the Executive MBA program at the
Kellogg Graduate School of Management at Northwestern University
and will graduate in June 2010. Kyle also serves on the Board of
Directors of the ECA Foundation, Inc., the YMCA of the Kanawha
Valley, Energize WV, and the Clay Center for the Arts. He is the
son of John and Julie Mork.
George V. OMalley
has been Vice President of
Accounting for ECA since December 2002. Before being elected
Vice President, Mr. OMalley served as Director of
Accounting. Mr. OMalley joined its predecessor in
April 1991 and served in various capacities including Vice
President and Treasurer. Prior to joining ECA, he held various
positions in industry and public accounting.
Mr. OMalley currently serves on the Marshall
University School of Business and Department of Accountancy and
Legal Environment Advisory Boards. He is a former board member
and past President of the West Virginia Society of CPAs
and board member of the Independent Oil & Gas
Association of West Virginia. Mr. OMalley graduated
from Marshall University with a Bachelor Degree in Accounting
and is a Certified Public Accountant.
W. Gaston Caperton, III
has been a Director
of ECA since 1997. Mr. Caperton has been a successful
leader in three diverse fields: business, government and
education. He was the principal owner of a large insurance
brokerage firm, is a former two-term governor of West Virginia,
and is the current President and Chief Executive Officer of The
College Board.
46
Peter H. Coors
has been a Director of ECA since
1997. Mr. Coors is the Chairman of Molson Coors Brewing
Company and the Chairman of MillerCoors LLC. He received his
Bachelor Degree in Industrial Engineering from Cornell
University in 1969 and his Master of Business Administration
from the University of Denver in 1970. Mr. Coors also
serves on the Board of Directors of the University of Colorado
Hospital. He is President of the Adolph Coors Foundation, Castle
Rock Foundation, and University of Colorado Hospital Foundation.
He also serves on the Board of the Denver Area Council of the
Boy Scouts of America and is a member of Denver
Universitys Strategic Panel on Immigration.
L.B. Curtis
has been a Director of ECA since 1993.
He was Chairman from 1998 through 2006 and is now Chairman
Emeritus. Mr. Curtis was a Director of its predecessor from
1988 until 1993. Mr. Curtis is retired from a career at
Conoco, Inc. where he held the position of Vice President of
Production Engineering with Conoco Worldwide. Mr. Curtis
was highly recognized across the petroleum industry in the
upstream segment of the industry. He is a member of the American
Petroleum Institute and Society of Petroleum Engineers (SPE) and
is a trustee of the SPE Foundation. He was instrumental in the
design and development of the North Sea tension-leg
production platform and a member of the Dupont Lavoisier
Academy. Mr. Curtis graduated from The Colorado School of
Mines with an Engineer of Petroleum Professional Degree.
John J. Dorgan
has been a Director of ECA since
1993 and served as a Director of its predecessor in 1992. He is
a former Executive Vice President and consultant to Occidental
Petroleum Corporation where he had worked in various capacities
starting in 1972. He is also a former Director and Chairman of
the Finance Committee, Canadian Occidental.
John S. Fischer
has been a Director of ECA since
2005. He founded Solid Systems Engineering Co. in 1979 to
service high tonnage conveyor systems in the mining, power and
primary metals industries; in 2008 the company was acquired by
Fenner Dunlop International. In 1994 Mr. Fischer started
Air Control Science, Inc. having recognized the need for a firm
with innovative technology to focus exclusively on effective
design and construction of dust, spillage and fume control
systems for the coal-fired power, coal mining and primary metals
industries; in 2007 Air Control Science was acquired by CCC
Group, Inc. Mr. Fischer has authored and co-authored
patents related to leading technology in coal-fired power and
primary metals particulate and dust control. Mr. Fischer
graduated from the Northwestern University Kellogg Graduate
School with a Master of Business Administration. Currently, he
is a member of the World Presidents Organization and Chief
Executives Organization. Mr. Fischer serves on the National
Coal Council for the Secretary of Energy, the Board of
University of Colorado Leeds Business School and the Board of
the Great Lakes Business School in Chennai India.
Thomas R. Goodwin
has been a Director of ECA since
2005 and has served as Chairman of the Board of Directors since
2007. Mr. Goodwin is Managing Partner of the law firm of
Goodwin and Goodwin, LLP which provides legal advice to ECA. He
is a member of the West Virginia State Bar and has appeared
before the West Virginia Supreme Court of Appeals and the Fourth
Circuit Court of Appeals. He is listed in the Best Lawyers of
America and is counselor to corporations and board of directors.
He formerly served as the West Virginia State Tax Commissioner
and Executive Assistant to the Governor of West Virginia,
Chairman of West Virginia Economic Development Authority,
Chairman of the West Virginia Municipal Bond Committee, and past
member of Board of Advisors of West Virginia University.
Mr. Goodwins legal expertise is focused on corporate
purchases, corporate sales and financing, and complex
litigation. He received his law degree from West Virginia
University and his Master Degree in Law from Harvard Law School.
F.H. McCullough, III
has been a Director of
ECA since 1993. He joined EAEC in 1977 and served in various
capacities until 1999, including Director from 1978 until 1993.
Mr. McCullough
47
is currently President and Chief Financial Officer of Spring
Creek Energy Company, LLC, a developer of metallurgical coal
reserves in West Virginia. He has served as a Director of the
Independent Oil and Gas Association of West Virginia and is the
Co-Founder, past President and current Director of the Angelman
Syndrome Foundation, Inc. Mr. McCullough is a graduate of
the University of Southern California with a Bachelor of Arts
Degree in International Economics and two Masters Degrees in
Business Administration and Financial Systems Management. He is
a graduate of the Northwestern University Kellogg Graduate
School of Management Executive Marketing Program.
Mr. McCullough serves on the Board of Directors of the ECA
Foundation, Inc.
Julie M. Mork
has been a Director of ECA since
1993. She is the Managing Director of the ECA Foundation, Inc.,
a private corporate foundation based in Denver, Colorado having
a focus on youth and education. Mrs. Mork served as a
founder and Secretary/Treasurer of Pacific States
Gas & Oil, Inc. and EAEC. From 1989 until 1991, she
served as Community Relations and Human Resources Director of
EAEC. She has volunteered her time to several organizations
including the Anchor Center for Blind Children where she
currently serves as a member of the Advisory Board and is a past
President of its Board of Directors. She also served as a member
of the Cherry Creek Schools Foundation for six years. In October
2004, Mrs. Mork was elected to the National Board of
College Summit, an organization dedicated to increasing the
college enrollment rate of low-income students in America.
Mrs. Mork received a Bachelor of Arts Degree in History
from the University of California in Los Angeles and holds a
Certificate in Real Estate Paralegal Training. She is the wife
of John Mork and the mother of Kyle Mork.
Jerry W. Neely
has been a Director of ECA since
2009. Mr. Neely is the former President, Chairman and CEO
of Smith International, a public multinational oil service
company. He is currently on the Board of Directors of Smith
International, Avery Dennison, Security Pacific Corporation,
Security Pacific National Bank, Peretec Computer, American
Petroleum Institute, Petroleum Suppliers Association and the
World Presidents Organization. He is on the University of
Southern California Board of Trustees and was awarded the USC
School of Business Outstanding Alumni Achievement Award. He has
a Bachelor of Science Degree in Industrial Management and
Business Administration from the University of Southern
California.
Arthur C. Nielsen, Jr.
Chairman Emeritus of the
A.C. Nielsen Company, has been a Director of ECA since 1993. He
was a Director of its predecessor from 1985 until 1993. He has
served on the board of directors of 21 firms, some for more than
a quarter of a century, including the A.C. Nielsen Company,
Dun & Bradstreet, General Binding Corporation, Harris
Bank, Marsh & McLennan, Motorola, Walgreens Co.,
Hercules, and International Executive Service Corp., and was
Advisor to three U.S. Presidents. He is a Life Trustee for
the American Management Association, a Director for the Chicago
Foundation for Education, Life Member and President of the
Economic Club of Chicago, Life Trustee for the Advertising
Council, Life Trustee for the Illinois Childrens Home and
Aid Society, Life Trustee for the University of Chicago,
President Emeritus and Past President of the Wisconsin Alumni
Research Foundation, Life Trustee for Northwestern Memorial
Hospital, and Past President of the Management Executive
Society. Mr. Nielsen is a graduate of the University of
Wisconsin, from which he received an honorary doctorate of Human
Letters Degree.
Jay S. Pifer
has been a Director of ECA since
2003. Mr. Pifer served as President of West Penn Power Co.,
Monongahela Power Co., and The Potomac Edison Co. before
becoming President of Allegheny Power where he also served as
Chief Operating Officer before retiring. Under his leadership
Allegheny Power became recognized as a world-class company and
was ranked number one in the nation in customer satisfaction
among the 30 largest electric and gas companies, ranked second
in the east and in the top ten nationally by JD Power and
Associates. Active in community affairs, Mr. Pifer has
served on the boards of numerous organizations including,
Waynesburg College, Penn State Fayette University Advisory
Board, University of
48
Pittsburgh-Greensburg, United Way, as well as Director and
Chairman of the Energy Association of Pennsylvania, Director of
Ohio Electric Utilities Institute, TEAM Pennsylvania, Western
Pennsylvania Conservancy, Educational Alliance of West Virginia,
The Westmoreland Trust and chair of their Strategic Planning
Committee, and Director of the Business Roundtable of
Pennsylvania and West Virginia. He is a graduate of Penn State
University and Clarion State University.
BENEFICIAL
OWNERSHIP OF ECA
The following table sets forth certain information regarding
(i) the share ownership of ECA by each person known to ECA
to be the beneficial owner of more than 5% of the outstanding
shares of common stock of ECA, (ii) the share ownership of
common stock of ECA by each director, (iii) the share
ownership of common stock of ECA by certain executive officers
and (iv) the share ownership of common stock of ECA by all
directors and executive officers as a group, in each case as of
December 31, 2009. The business address of each officer and
director listed below is:
c/o Energy
Corporation of America, 4643 S. Ulster,
Suite 1100, Denver, Colorado 80237.
|
|
|
|
|
|
|
|
|
|
|
Beneficial Ownership
|
|
|
|
Common Stock
|
|
|
|
Shares
|
|
|
Percent
|
|
|
W. Gaston Caperton, III
|
|
|
11,680
|
|
|
|
2.24
|
%
|
Peter H. Coors
|
|
|
8,196
|
|
|
|
1.57
|
%
|
L.B. Curtis
|
|
|
10,750
|
|
|
|
2.06
|
%
|
John J. Dorgan
|
|
|
4,130
|
|
|
|
*
|
|
John S. Fischer
|
|
|
|
|
|
|
|
|
Michael S. Fletcher
|
|
|
1,000
|
|
|
|
*
|
|
J. Michael Forbes
|
|
|
1,850
|
|
|
|
*
|
|
Thomas R. Goodwin
|
|
|
|
|
|
|
|
|
F.H. McCullough, III (1)
|
|
|
60,080
|
|
|
|
11.54
|
%
|
John Mork (2)
|
|
|
365,443
|
|
|
|
70.18
|
%
|
Julie M. Mork (2)
|
|
|
365,443
|
|
|
|
70.18
|
%
|
Kyle M. Mork (3)
|
|
|
5,544
|
|
|
|
1.06
|
%
|
Arthur C. Nielsen, Jr.
|
|
|
19,880
|
|
|
|
3.82
|
%
|
George OMalley
|
|
|
|
|
|
|
|
|
Jerry W. Neely
|
|
|
|
|
|
|
|
|
Jay S. Pifer
|
|
|
|
|
|
|
|
|
Donald C. Supcoe
|
|
|
4,583
|
|
|
|
*
|
|
All officers and directors as a group (17 persons)
|
|
|
493,136
|
|
|
|
94.70
|
%
|
|
|
|
*
|
|
Less than one percent
|
|
(1)
|
|
Includes 58,000 shares held by
F.H. McCullough, III and Kathy McCullough as joint tenants,
880 shares held by the Katherine F. McCullough Trust, and
400 shares held by each of the Lesley McCullough Trust, the
Meredith McCullough Trust and the Kristin McCullough Trust.
|
|
(2)
|
|
Includes 283,304 shares held
by Shenandoah LLC, an entity wholly owned and controlled by a
grantor trust created by John and Julie Mork, 74,032 shares
held by John and Julie Mork as joint tenants, 2,563 shares
held by Julie Mork individually, and 5,544 shares held by
the Alison Mork Trust.
|
|
(3)
|
|
Includes 5,544 shares held by
the Kyle Mork Trust.
|
49
The following table sets forth certain information regarding
(1) the share ownership of ECA by each person known to ECA
to be the beneficial owner of more than 5% of the outstanding
shares of Class A Stock, (2) the share ownership of
ECAs Class A Stock by each Director, (3) the
share ownership of ECAs Class A Stock by certain
executive officers and (4) the share ownership of
ECAs Class A Stock by all directors and executive
officers as a group, in each case as of December 31, 2009.
The Class A Stock differs from the Common Stock in that the
Class A Stock does not have voting rights. The business
address of each officer and director listed below is:
c/o Energy
Corporation of America, 4643 South Ulster Street,
Suite 1100, Denver, Colorado 80237.
|
|
|
|
|
|
|
|
|
|
|
Beneficial Ownership
|
|
|
|
Class A Stock
|
|
|
|
Shares
|
|
|
Percent
|
|
|
W. Gaston Caperton, III
|
|
|
3,420
|
|
|
|
5.19
|
%
|
Peter H. Coors
|
|
|
4,516
|
|
|
|
6.86
|
%
|
L.B. Curtis
|
|
|
1,180
|
|
|
|
1.79
|
%
|
John J. Dorgan
|
|
|
3,820
|
|
|
|
5.80
|
%
|
John S. Fischer
|
|
|
480
|
|
|
|
*
|
|
Michael S. Fletcher (2)
|
|
|
2,270
|
|
|
|
3.45
|
%
|
J. Michael Forbes (2)
|
|
|
1,550
|
|
|
|
2.35
|
%
|
Thomas R. Goodwin
|
|
|
3,820
|
|
|
|
5.80
|
%
|
F.H. McCullough, III
|
|
|
1,180
|
|
|
|
1.79
|
%
|
John Mork (1)(2)
|
|
|
4,750
|
|
|
|
7.21
|
%
|
Julie M. Mork (1)(2)
|
|
|
4,750
|
|
|
|
7.21
|
%
|
Kyle M. Mork (2)(3)
|
|
|
1,969
|
|
|
|
2.98
|
%
|
Jerry W. Neely
|
|
|
|
|
|
|
|
|
Arthur C. Nielsen, Jr.
|
|
|
1,180
|
|
|
|
1.79
|
%
|
George V. OMalley (2)
|
|
|
1,170
|
|
|
|
1.78
|
%
|
Jay S. Pifer
|
|
|
1,340
|
|
|
|
2.03
|
%
|
Donald C. Supcoe (2)
|
|
|
2,630
|
|
|
|
3.99
|
%
|
All officers and directors as a group (17 persons)
|
|
|
35,275
|
|
|
|
53.55
|
%
|
|
|
|
*
|
|
Less than one percent
|
|
(1)
|
|
Includes 1,730 shares held by
John and Julie Mork as joint tenants, 1,800 shares held by
Julie Mork individually and 1,220 shares held by the Alison
Mork Trust.
|
|
(2)
|
|
Includes shares included in
ECAs Incentive Stock Purchase Plan.
|
|
(3)
|
|
Includes 1,219 shares held by
the Kyle Mork Trust.
|
50
EASTERN
AMERICAN NATURAL GAS TRUST
In 1993, ECA sponsored the formation of the Eastern American
Natural Gas Trust (NYSE: NGT), a publicly traded Delaware trust
(NGT), to which it contributed net profits interests
in Appalachian Basin natural gas properties trust units.
Depositary units consisting of trust units and an interest in
United States Treasury obligations (Depositary
Units) were sold in a public offering at a price of $20.50
per Depositary Unit, resulting in gross proceeds of
$120.9 million. This royalty trust holds net profits
interests conveyed from the interests of ECA in 650 producing
gas wells, 65 proved development well locations and associated
acreage located in West Virginia and Pennsylvania. In connection
with the formation of this trust, ECA agreed to drill 65
development wells over a period of five years from which NGT
would be entitled to a specified percentage of the proceeds from
the natural gas production. ECA completed its obligation within
the stipulated period. From the formation of the trust through
December 31, 2009, NGT distributed $31.02 per Depositary
Unit in the aggregate. As of March 24, 2010, the closing
price of each Depositary Unit as reported by the New York Stock
Exchange was $23.26. The Eastern American Natural Gas Trust is
expected to terminate in 2013. The historical results of
operations and performance of NGT should not be relied on as an
indicator of how the trust will perform.
51
THE
TRUST
The trust is a statutory trust created under the Delaware
Statutory Trust Act in March 2010. The business and affairs
of the trust will be managed
by ,
as trustee. Although ECA will operate all of the Producing Wells
and substantially all of the PUD Wells, ECA has no ability to
manage or influence the management of the trust. In addition,
the Corporation Trust Company will act as Delaware trustee
of the trust. The Delaware trustee will have only minimal rights
and duties as are necessary to satisfy the requirements of the
Delaware Statutory Trust Act.
In connection with the formation of the trust, ECA will convey
to a wholly owned subsidiary a term royalty interest entitling
the holder of the interest to receive 45% of the proceeds from
the sale of production of natural gas attributable to ECAs
interest in the Producing Wells (after deducting post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PDP
Royalty) and a term royalty interest entitling such holder
of the interest to receive 25% of the proceeds from the sale of
the production of natural gas attributable to ECAs
interest in the PUD Wells (after deducting post-production costs
and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 (the Term PUD
Royalty) in exchange for a demand note in the principal
amount of $ million. The Term
PDP Royalty and the Term PUD Royalty are collectively referred
to as the Term Royalties.
Prior to the closing of this offering, ECA and the Private
Investors will convey to the trust perpetual royalty interests
entitling the trust to receive, in the aggregate, 45% of the
proceeds from the sale of production of natural gas attributable
to the interests of ECA in the Producing Wells (after deducting
post-production costs and any applicable taxes) (the
Perpetual PDP Royalty) and ECA will convey to the
trust a perpetual royalty interest entitling the trust to
receive an additional 25% of the proceeds from the sale of
production of natural gas attributable to ECAs interest in
the PUD Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PUD Royalty) in
exchange for an aggregate 4,500,000 common units
constituting 25% of the trust units outstanding and 4,500,000
subordinated units constituting 25% of the trust units
outstanding. The Perpetual PDP Royalty and the Perpetual PUD
Royalty are collectively referred to as the Perpetual
Royalties.
In connection with the completion of this offering, ECAs
subsidiary will convey the Term Royalties to the trust in
exchange for the net proceeds of this offering, after deducting
underwriting commissions and discounts and expenses, and will
use the net proceeds to repay the demand note to ECA.
The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the trust. The trustee may authorize the trust to borrow from
the trustee as a lender provided the terms of the loan are fair
to the trust unitholders. The trustee may also deposit funds
awaiting distribution in an account with itself, if the interest
paid to the trust at least equals amounts paid by the trustee on
similar deposits, and make other short term investments with the
funds distributed to the trust.
The trust will be responsible for paying all legal, accounting,
tax advisory, engineering, printing costs and other
administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of being a publicly traded
entity, including costs associated with annual and quarterly
reports to unitholders, tax return and Schedule K-1
preparation and distribution, independent auditor fees and
registrar and transfer agent fees. These trust administrative
expenses as well as the costs associated with being a publicly
traded entity are anticipated to aggregate approximately
$800,000 per year, although such costs could be greater or less
depending on future events that cannot be predicted. Included in
the $800,000 annual estimate is
52
an annual administrative fee of
$
for the trustee and an annual administrative fee of
$
for the Delaware trustee. These costs as well as those to be
paid to ECA pursuant to the Administrative and Drilling Services
Agreement outlined below under Administrative
and Drilling Services Agreement, will be deducted by the
trust before distributions are made to trust unitholders.
The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a first right
of refusal to purchase the Perpetual Royalties at the
Termination Date.
ADMINISTRATIVE
AND DRILLING SERVICES AGREEMENT
In connection with the closing of this offering, the trust will
enter into an Administrative and Drilling Services Agreement
with ECA that obligates the trust to pay ECA each quarter an
administrative services fee for accounting, bookkeeping and
informational services to be performed by ECA on behalf of the
trust relating to the royalty interests. The annual fee, payable
in equal quarterly installments, will total $60,000. After the
completion of ECAs drilling obligation, ECA and the
trustee each may terminate the provisions of the Administrative
and Drilling Services Agreement relating to the provision by ECA
of administrative services at any time following delivery of
notice no less than 90 days prior to the date of
termination.
The Administrative and Drilling Services Agreement will also
obligate ECA to use commercially reasonable efforts to drill all
of the PUD Wells by March 31, 2013. In the event of delays,
ECA will have until March 31, 2014 to fulfill its drilling
obligations. ECA will grant to the trust the first perfected
Drilling Support Lien on ECAs retained interest in the AMI
in order to secure the estimated amount of the drilling costs
for the trusts interests in the PUD Wells. The amount
obtained by the trust pursuant to the Drilling Support Lien may
not exceed $91 million. As ECA drills individual PUD Wells,
the amount of the Drilling Support Lien will be reduced
proportionately based on the number of PUD Wells drilled. This
Drilling Support Lien is nonrecourse to ECA.
For purposes of ECAs drilling obligation, ECA will be
credited with a full development well drilled if its working
interest in the development well drilled is 100%. In the event
that ECAs working interest in a development well drilled
is less than 100%, ECA will be credited with a portion of a
development well in the proportion that its working interest in
the development well bears to 100%. For example, if ECAs
working interest in a development well drilled by ECA in
connection with fulfilling its drilling obligation to the trust
is 50%, ECA will be credited with one-half of a development well
for purposes of satisfying its drilling obligation in the period
the development well was drilled. As a result, ECA will be
required to drill more than the 52 Marcellus Shale natural gas
development wells, in the aggregate, if ECAs interest in
any development well is less than 100%.
Wells drilled horizontally in the Marcellus Shale formation with
a horizontal lateral distance (measured from the midpoint of the
curve to the end of the lateral) of less than 2,500 feet
will count as a fractional well in proportion to total lateral
length divided by 2,500 feet. In the event ECA commences
drilling of a PUD Well, but fails to drill beyond the mid-point
of the curve in the Marcellus Shale formation, such well will
not count as a fractional well. Wells with a horizontal lateral
distance of greater than 2,500 feet (subject to a maximum
of 3,500 feet) will count as one well plus a fractional
well equal to the length drilled in excess of 2,500 (up to
3,500 feet) feet divided by 2,500 feet. Among the Producing
Wells, the average lateral length completed has been
approximately 2,500 feet, with the most recent wells
extending beyond the average with
53
a maximum lateral length drilled of 3,271 feet. The reserve
report was prepared based on an average lateral length of 2,000
feet for the PUD Wells.
ECA is obligated to bear all of the costs of drilling and
completing the PUD Wells. ECA is required to complete and equip
each development well that reasonably appears to ECA to be
capable of producing gas in quantities sufficient to pay
completion, equipping and operating costs. In making such
decisions, ECA is required to act as a reasonably prudent
operator in the AMI under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. See The Underlying
Properties Sale and Abandonment of Underlying
Properties.
ECA will covenant and agree not to drill and complete, and will
not permit any other person within its control to drill and
complete, any well in the Marcellus Shale formation on lease
acreage included within the AMI for its own account until such
time as ECA has met its commitment to drill the PUD Wells. Once
ECA has drilled all of the PUD Wells, the trustee will be
required to release the Drilling Support Lien. Upon the
trustees release of the Drilling Support Lien, ECA will
further agree not to drill and complete, and will not permit any
other person within its control to drill and complete, any well
on the lease acreage that is located within 500 feet of any
PUD Well or Producing Well in the Marcellus Shale formation.
54
TARGET
DISTRIBUTIONS AND SUBORDINATION AND INCENTIVE
THRESHOLDS
ECA will create the royalty interests through conveyances to the
trust of royalty interests carved from their working interests
in specified gas properties in Pennsylvania. The PDP Royalty
Interest will entitle the trust to receive 90% of the proceeds
(after deducting post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs interest in the Producing Wells for a period of
20 years commencing on April 1, 2010 and 45%
thereafter. The PUD Royalty Interest will entitle the trust to
receive 50% of the proceeds (after deducting post-production
costs and any applicable taxes) from the sale of future
production of natural gas attributable to ECAs interest in
the PUD Wells for a period of 20 years commencing on
April 1, 2010 and 25% thereafter.
The amount of trust revenues and cash distributions to trust
unitholders will depend on:
|
|
|
|
|
the timing of initial production from the PUD Wells;
|
|
|
|
natural gas prices received;
|
|
|
|
the volume and Btu rating of natural gas produced and sold;
|
|
|
|
post-production costs and any applicable taxes;
|
|
|
|
the reimbursement by the trust, if any, of ECAs costs
associated with establishing hedging contracts for the benefit
of the trust; and
|
|
|
|
administrative expenses of the trust and expenses incurred as a
result of being a publicly traded entity.
|
ECA has calculated quarterly target levels of cash distributions
for the life of the trust. Such target distribution levels are
set forth on Annex B to this prospectus. The target
distributions were prepared by ECA on an accrual basis based on
volumes, pricing and other assumptions that are described below
in Significant assumptions used to prepare the
target distributions. As used herein, accrual basis means
ECA will pay to the trust each quarter an amount equal to the
estimated proceeds of production from the trust properties
during the calendar quarter most recently ended before the
distribution (after deducting post-production costs and any
applicable taxes), regardless of whether such amounts have
actually been received by ECA from the purchaser of the natural
gas produced.
The amount of the quarterly distributions may fluctuate from
quarter to quarter, depending on the proceeds received by the
trust, among other factors. Annex B reflects that while
target distributions increase as ECA completes its drilling
obligations and production attributable to the trust increases,
over time these target distributions decline as a result of the
depletion of the reserves in the Underlying Properties. These
target distributions do not represent the actual
distributions you should expect to receive with respect to your
common units. Rather, the trust has established the target
distributions in part to calculate the subordination and
incentive thresholds described in more detail below.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,500,000 of the trust
units it will retain following this offering, which will
constitute 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust if and to the extent there is
sufficient cash to provide a cash distribution on the common
units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated in order to make a distribution, to the extent
possible, of up to the subordination threshold amount
55
on the common units. Each applicable quarterly subordination
threshold is equal to 80% of the target distribution level for
the corresponding quarter as reflected on Annex B. In
exchange for agreeing to subordinate these trust units, and in
order to provide additional financial incentive to ECA to
perform its drilling obligation and operations on the Underlying
Properties in an efficient and cost-effective manner, ECA will
be entitled to receive incentive distributions equal to 50% of
the amount by which the cash available for distribution on all
of the trust units in any quarter exceeds 150% of the
subordination threshold for such quarter (which is 120% of the
target distribution for such quarter). ECAs right to
receive the incentive distributions will terminate upon the
expiration of the subordination period.
ECA has incurred costs of approximately $5 million in
securing the hedging contracts to be transferred to the trust.
ECA will be entitled to reimbursement for these expenditures
plus interest accrued at 10% per annum only if and to the extent
distributions to trust unitholders would otherwise exceed the
incentive threshold. This reimbursement will be deducted, over
time, from the 50% of cash available for distribution in excess
of the incentive thresholds otherwise payable to the trust
unitholders.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it is transferring to
the trust. The trust currently expects that ECA will complete
its drilling obligation on or before March 31, 2013 and
that, accordingly, the subordinated units would convert into
common units on or before March 31, 2014. In the event of
delays, ECA will have until March 31, 2014 to drill all the
PUD Wells, in which event the subordinated units would convert
into common units on or before March 31, 2015.
The table below sets forth the target distributions and
subordination and incentive thresholds for each calendar quarter
during the full potential subordination period. The effective
date of the trust is April 1, 2010, meaning it will receive
the proceeds of production attributable to the PDP Royalty
Interest from that date even though the PDP Royalty Interest
will not be conveyed to the trust until the closing of this
offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordination
|
|
Target
|
|
Incentive
|
Period
|
|
Threshold
|
|
Distribution
|
|
Threshold
|
|
|
|
|
(per unit)
|
|
|
|
2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter
|
|
$
|
0.217
|
|
|
$
|
0.271
|
|
|
$
|
0.326
|
|
Third Quarter
|
|
|
0.298
|
|
|
|
0.372
|
|
|
|
0.447
|
|
Fourth Quarter
|
|
|
0.426
|
|
|
|
0.532
|
|
|
|
0.639
|
|
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.413
|
|
|
|
0.516
|
|
|
|
0.619
|
|
Second Quarter
|
|
|
0.418
|
|
|
|
0.523
|
|
|
|
0.627
|
|
Third Quarter
|
|
|
0.520
|
|
|
|
0.650
|
|
|
|
0.780
|
|
Fourth Quarter
|
|
|
0.544
|
|
|
|
0.680
|
|
|
|
0.815
|
|
2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.562
|
|
|
|
0.702
|
|
|
|
0.843
|
|
Second Quarter
|
|
|
0.595
|
|
|
|
0.744
|
|
|
|
0.893
|
|
Third Quarter
|
|
|
0.607
|
|
|
|
0.759
|
|
|
|
0.911
|
|
Fourth Quarter
|
|
|
0.688
|
|
|
|
0.859
|
|
|
|
1.031
|
|
2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
0.773
|
|
|
$
|
0.967
|
|
|
$
|
1.160
|
|
Second Quarter
|
|
|
0.771
|
|
|
|
0.964
|
|
|
|
1.157
|
|
Third Quarter
|
|
|
0.717
|
|
|
|
0.896
|
|
|
|
1.075
|
|
Fourth Quarter
|
|
|
0.674
|
|
|
|
0.842
|
|
|
|
1.010
|
|
2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.623
|
|
|
|
0.779
|
|
|
|
0.935
|
|
Second Quarter
|
|
|
0.601
|
|
|
|
0.751
|
|
|
|
0.902
|
|
Third Quarter
|
|
|
0.583
|
|
|
|
0.728
|
|
|
|
0.874
|
|
Fourth Quarter
|
|
|
0.561
|
|
|
|
0.701
|
|
|
|
0.841
|
|
2015:
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
|
0.530
|
|
|
|
0.663
|
|
|
|
0.795
|
|
56
ECA does not as a matter of course make public projections as to
future sales, earnings, or other results. However, the
management of ECA has prepared the projected operational and
financial information set forth below in order to present the
target distributions attributable to the natural gas sales
volumes reflected in Ryder Scotts reserve report attached
hereto as Annex A. The target distributions, in the view of
ECAs management, were prepared on a reasonable basis based
on the assumptions outlined in Significant
assumptions used to prepare the target distributions.
The projections outlined below are not fact and should not be
relied upon as being necessarily indicative of future results,
and readers of this prospectus are cautioned not to place undue
reliance on the projected financial information.
Neither ECAs independent auditors, nor any other
independent accountants, have compiled, examined, or performed
any procedures with respect to the projected financial
information contained herein, nor have they expressed any
opinion or any other form of assurance on such information or
its achievability, and assume no responsibility for, and
disclaim any association with, the projected financial
information.
The projections and assumptions on which they are based are
subject to significant uncertainties, many of which are beyond
the control of ECA and the trust.
Actual cash distributions
to trust unitholders, therefore, could vary significantly based
upon events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections.
Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in natural gas prices
production volumes. See Sensitivity of target
distributions to natural gas prices and volumes which
shows estimated effects to cash distributions through
March 31, 2011 from hypothetical changes in natural gas
prices as well as hypothetical changes in production volumes. As
a result of typical production declines for natural gas
properties, production estimates generally decrease from year to
year. However, the production estimates included in the table
below reflect that these declines are expected to be offset by
additional production from PUD Wells as they are turned in line.
The timing of the completion of, and the amount of production
attributable to the PUD Wells, are substantially dependent on
ECA executing its drilling plans with respect to the drilling
and completion of the PUD Wells in a manner substantially
similar to those underlying the assumptions used in establishing
these target distributions. Please see Risk Factors
for risks relating to the timing of drilling and amount of
production attributable to the PUD Wells.
As a result of
these factors, the target distributions shown in the tables
below are not necessarily indicative of distributions for future
years.
Because payments to the trust will be generated by
depleting assets and the trust has a finite life with the
production from the Underlying Properties diminishing over time,
a portion of each distribution will represent a return of trust
unitholders original investment. See Risk
Factors The natural gas reserves attributable to the
Underlying Properties of the trust are depleting assets and
production from those reserves will diminish over time.
Furthermore, the trust is generally precluded from acquiring
other oil and gas properties or royalty interests to replace the
depleting assets and production.
57
The table below presents the calculation of the target
distributions for each quarter through and including the quarter
ending June 30, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarters Ending
|
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
June 30,
|
|
|
|
2010
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(In thousands, except well number, volumetric and per unit
data)
|
|
|
Number of wells producing at quarter end
|
|
|
8
|
|
|
|
17
|
|
|
|
22
|
|
|
|
25
|
|
|
|
31
|
|
Estimated Production from Trust Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas PDP Sales Volumes (MMcf)
|
|
|
879
|
|
|
|
1,190
|
|
|
|
1,265
|
|
|
|
1,066
|
|
|
|
962
|
|
Natural Gas PUD Sales Volumes (MMcf)
|
|
|
|
|
|
|
81
|
|
|
|
514
|
|
|
|
553
|
|
|
|
769
|
|
Total Sales Volumes (MMcf)
|
|
|
879
|
|
|
|
1,271
|
|
|
|
1,779
|
|
|
|
1,619
|
|
|
|
1,731
|
|
Daily Sales Volumes (Mcf/d)
|
|
|
9,664
|
|
|
|
13,814
|
|
|
|
19,336
|
|
|
|
17,988
|
|
|
|
19,020
|
|
Commodity Prices and Hedging Positions
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumed NYMEX Price ($/MMBtu) (2)
|
|
$
|
4.58
|
|
|
$
|
4.75
|
|
|
$
|
5.27
|
|
|
$
|
5.81
|
|
|
$
|
5.34
|
|
Assumed Price ($/Mcf)
|
|
|
4.72
|
|
|
|
4.89
|
|
|
|
5.42
|
|
|
|
5.98
|
|
|
|
5.50
|
|
Realized Unhedged Price after Basis Differential ($/Mcf)
|
|
|
4.88
|
|
|
|
5.04
|
|
|
|
5.58
|
|
|
|
6.13
|
|
|
|
5.65
|
|
Daily Hedged Volumes
(MMcf/d) (3)
|
|
|
7.3
|
|
|
|
7.3
|
|
|
|
9.7
|
|
|
|
9.0
|
|
|
|
9.5
|
|
Percent of Total Volumes Swapped
|
|
|
75
|
%
|
|
|
53
|
%
|
|
|
38
|
%
|
|
|
40
|
%
|
|
|
38
|
%
|
Swap Price ($/MMBtu)
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
|
$
|
6.75
|
|
Percent of Total Volumes Floored
|
|
|
|
|
|
|
|
|
|
|
12
|
%
|
|
|
10
|
%
|
|
|
12
|
%
|
Floor Price ($/MMBtu)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
|
$
|
5.00
|
|
Realized Hedged Weighted Average Price ($/Mcf) (3)
|
|
$
|
6.55
|
|
|
$
|
6.13
|
|
|
$
|
6.15
|
|
|
$
|
6.53
|
|
|
$
|
6.21
|
|
Cash available for distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Sales Revenues
|
|
$
|
4,288
|
|
|
$
|
6,408
|
|
|
$
|
9,923
|
|
|
$
|
9,932
|
|
|
$
|
9,786
|
|
Swap and Floor Hedge Revenues
|
|
|
1,476
|
|
|
|
1,381
|
|
|
|
1,021
|
|
|
|
635
|
|
|
|
960
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenues
|
|
$
|
5,764
|
|
|
$
|
7,788
|
|
|
$
|
10,944
|
|
|
$
|
10,566
|
|
|
$
|
10,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-Production Services Fee (4)
|
|
$
|
471
|
|
|
$
|
681
|
|
|
$
|
953
|
|
|
$
|
867
|
|
|
$
|
927
|
|
Trust Expenses
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
200
|
|
|
|
201
|
|
Franchise Taxes
|
|
|
207
|
|
|
|
207
|
|
|
|
211
|
|
|
|
211
|
|
|
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Available for Distribution
|
|
$
|
4,885
|
|
|
$
|
6,701
|
|
|
$
|
9,581
|
|
|
$
|
9,288
|
|
|
$
|
9,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Units Outstanding
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
|
|
18,000
|
|
Target Distribution Per Trust Unit
|
|
$
|
0.271
|
|
|
$
|
0.372
|
|
|
$
|
0.532
|
|
|
$
|
0.516
|
|
|
$
|
0.523
|
|
Subordination Threshold Per Trust Unit
|
|
$
|
0.217
|
|
|
$
|
0.298
|
|
|
$
|
0.426
|
|
|
$
|
0.413
|
|
|
$
|
0.418
|
|
Incentive Threshold Per Trust Unit
|
|
$
|
0.326
|
|
|
$
|
0.447
|
|
|
$
|
0.639
|
|
|
$
|
0.619
|
|
|
$
|
0.627
|
|
|
|
|
(1)
|
|
For a more detailed description of
the natural gas hedging contracts established for the benefit of
the trust, please see Description of the Royalty
Interests.
|
|
(2)
|
|
Based on NYMEX forward pricing as
of March 11, 2010. Assumed price per Mcf calculated based
on an assumed conversion rate of 1.03 MMBtu per Mcf.
|
58
|
|
|
(3)
|
|
Adjusted for an assumed basis
differential of $0.15 per MMBtu.
|
|
(4)
|
|
Consists of a fee of $0.52 per
MMBtu.
|
SIGNIFICANT
ASSUMPTIONS USED TO PREPARE THE TARGET DISTRIBUTIONS
In preparing the target distributions and subordination and
incentive threshold tables above and sensitivity tables below,
the revenues and expenses of the trust were calculated based on
the terms of the conveyances creating the trusts royalty
interests using the following assumptions and those set forth
above under Target Distributions and Subordination and
Incentive Thresholds. These calculations are described
under Description of the Royalty Interests.
Production estimates.
Production estimates for each
of the quarters during the life of the trust are based on the
reserve report. The estimates of reserves and production
relating to the Underlying Properties and the royalty interests
included in the reserve report have been made in accordance with
the SECs new rules for reserve reporting. Production
attributable to the royalty interests from the Underlying
Properties for the twelve months ending June 30, 2011 is
estimated to be 6,400 MMcfe of natural gas. The estimated
production in the forecast period gives effect to the drilling
and completion by ECA of three PUD Wells in the third quarter of
2010; five PUD Wells in the fourth quarter of 2010; three PUD
Wells in the first quarter of 2011; six PUD Wells in the second
quarter of 2011; and the completion by ECA of its drilling
obligation to the trust by March 31, 2013. See
Natural gas prices below for a
description of changes in production due to price variations.
Differing levels of production will result in different levels
of distributions and cash returns.
Natural gas prices.
The hypothetical natural gas
prices utilized for purposes of preparing the target
distributions are based on estimated market prices for natural
gas based on NYMEX forward pricing as of March 11, 2010 for
the thirty-six month period ending March 31, 2013 and
increased thereafter by a 2.5% annual escalator (as adjusted for
a basis differential of $0.15 per MMBtu), capped at $9.00 per
MMBtu starting in 2025. The assumed price per Mcf is calculated
based on an assumed conversion rate of 1.03 MMBtu per Mcf.
Actual MMBtu per Mcf may differ as it will be based on the
actual heat content of the gas produced. These prices estimate
market prices of $4.58 per MMBtu for the quarter ending
June 30, 2010, $4.75 per MMBtu for the quarter ending
September 30, 2010, $5.27 per MMBtu for the quarter ending
December 31, 2010, $5.81 per MMBtu for the quarter ending
March 31, 2011 and $5.34 per MMBtu for the quarter ending
June 30, 2011. We have assumed that 50% of the estimated
natural gas production attributable to the trusts royalty
interests will be hedged from April 1, 2010 to
March 31, 2014. These hedging contracts will be transferred
to the trust by ECA, and ECA will be entitled to recoup the
costs of establishing the hedging contracts if cash available
for distribution by the trust reaches certain levels. The
average realized sales price for gas gathered and sold on
ECAs Greene County Gathering System (prior to any
post-production costs) for the twelve months ended June 30,
2009 was $6.85 per MMBtu. This was approximately $0.46
above the average closing NYMEX natural gas futures contract
prices for the same period. However, if previously occurring
location, quality and other differentials change in the future,
there may be more significant differences between the natural
gas price received and the NYMEX price than the assumed $0.15
per MMBtu differential used in these estimations. In addition,
the market price of natural gas is generally higher in the
winter months than during the other months of the year due to
increased demand for natural gas for heating purposes during the
winter season. The price of natural gas fluctuates based on
levels of supply and demand at any given time. The adjustments
to realized natural gas prices applied in the tables above are
based upon an analysis by ECA of the historic price
differentials for production from the Underlying Properties with
consideration given to quality and transportation and marketing
costs that may affect these differentials for the forecast
period. There is no assurance that these assumed differentials
will be the same during the periods presented in the tables
above.
59
If natural gas prices decline, the operators of producing oil
and gas properties may elect to reduce or completely suspend
production. ECA is required under the applicable conveyance to
act as a reasonably prudent operator with respect to the
Underlying Properties under the same or similar circumstances as
it would act if it were acting with respect to its own
properties, disregarding the existence of the royalty interests
as burdens affecting such property. No adjustments have been
made to estimated production in the tables above to reflect
potential reductions or suspensions of production.
Administrative expense.
Trust administrative expense
per year is expected to be approximately $800,000 per year,
although such costs could be greater or less depending on future
events that cannot be predicted. Included in the $800,000 annual
estimate, among other miscellaneous items, is an annual
administrative fee of
$ for the trustee and
an annual administrative fee of
$ for the Delaware
trustee. In addition, the trust will pay an annual
administrative fee to ECA pursuant to the Administrative and
Drilling Services Agreement, which fee will total $60,000 per
year which will remain flat for the life of the trust. The
balance ($740,000) is escalated at 2.5% annually starting in the
second quarter of 2011. The trust will also pay, out of the
first cash payment received by the trust, the trustees and
Delaware trustees legal expenses incurred in forming the
trust as well as the Delaware trustees acceptance fee in
the amount of $ . These
costs will be deducted by the trust before distributions are
made to trust unitholders.
Tax treatment of royalty interests.
For federal
income tax purposes, the Term PDP Royalty will be and the Term
PUD Royalty should be treated as debt instruments. Accordingly,
the Term Royalties will be subject to the original issue
discount, or OID, rules of the Internal Revenue Code which
require that payments made to the trust with respect to the Term
Royalties will be treated first as consisting of a payment of
interest to the extent of interest deemed accrued under the OID
rules at the applicable federal rate and the excess, if any,
will be treated as a payment of principal (which is
non-taxable). For federal income tax purposes, the Perpetual PDP
Royalties will be, and the Perpetual PUD Royalties should be,
treated as mineral royalty interests, which give rise to
ordinary income subject to depletion.
Timing of actual cash distributions.
The payments by
ECA in respect of the royalty interests will be made by ECA on
an accrual basis. As used herein, accrual basis means ECA will
pay to the trust each calendar quarter an amount equal to the
proceeds of estimated production from the trust properties
during the calendar quarter most recently ended before the
distribution.
Post-production costs.
The Post-Production Services
Fee of $0.52 per MMBtu is held flat for the life of the trust.
The actual Post-Production Services Fee of $0.52 per MMBtu may
differ once ECAs drilling obligation is fulfilled. ECA may
increase this fee to the extent necessary to recover certain
capital expenditures on the Greene County Gathering System after
the completion of the drilling period, provided the resulting
charge does not exceed the prevailing charges in the area for
similar services.
Estimated total reserves and quarterly production volumes are
net of an assumed 5% natural gas fuel compression charge and
line loss, which percentage is based off of ECAs
historical experience in Greene County, Pennsylvania. In the
event that ECA chooses to use electrical compression in the
future, costs would differ. Actual compressor fuel charges and
line loss will be allocated to the trusts interests and
may differ from the 5% assumed in the reserve report. No other
post-production costs were contemplated in the target
distributions but the trust would be responsible for any new
post-production costs.
Applicable taxes.
There are currently no taxes in
Pennsylvania related to the production or severance of oil and
natural gas in Pennsylvania. Pennsylvania has not historically
imposed any
60
such taxes, but legislation is pending in the Pennsylvania
Senate Finance and the House Energy and Environmental Resources
Committees that provides for a severance tax of 5% on the value
of the natural gas at the wellhead plus $0.047 per thousand
cubic feet of natural gas severed. See Risk
Factors Recently proposed severance taxes in
Pennsylvania could materially increase the post-production costs
that are borne by the trust. In addition, the trust will
be required to pay Pennsylvania franchise tax on its capital
stock value, as determined pursuant to the statute and
apportioned to Pennsylvania. The current tax rate of 0.289% is
currently scheduled to be reduced to 0.189% in 2012 and 0.089%
in 2013 and to be completely phased out in 2014. This schedule
may be altered and the taxes left in place subsequent to the
General Assembly in its annual budget process.
Hedge cost reimbursement.
To the extent that the
trust has cash available for distribution in excess of the
incentive thresholds during the subordination period, ECA will
be entitled to receive 50% of such cash as incentive
distributions and 50% of such cash as recoupment of its costs
for establishing the hedge contracts until it has recouped
approximately $5 million. The incentive distributions and
the hedging reimbursement terminate upon completion of the
subordination period.
SENSITIVITY
OF TARGET DISTRIBUTIONS TO CHANGES IN NATURAL GAS PRICES AND
VOLUMES
The amount of revenues of the trust and cash distributions to
the trust unitholders will be directly dependent on the sales
price for natural gas sold, the volumes of gas produced and, to
some degree, variations in property and production taxes, if
any, and post-production costs. The following tables demonstrate
the projected effect that hypothetical changes in the estimated
gas production for the forecast period ending June 30, 2011
as reflected in the reserve report and the impact that
hypothetical fluctuations in assumed realized gas prices could
have on cash distributions to the trust unitholders.
These tables set forth the sensitivity of annual cash
distributions per trust unit for the forecast period ending
June 30, 2011 based upon (1) the assumption that a
total of 18,000,000 trust units are issued and outstanding after
the closing of the offering made hereby; (2) an assumed
initial public offering price of $ per common
unit; (3) various realizations of production levels
estimated in the reserve report; (4) various hypothetical
realized gas prices; (5) the impact of the natural gas
hedging contracts owned by the trust that entitle the trust to
receive payments from the counterparties to such contracts in
the event that natural gas prices are lower than the floor
prices specified in the contracts; (6) assumptions
regarding applicable taxes and post-production costs;
(7) assumptions regarding administrative expenses; and
(8) other assumptions described below under
Significant Assumptions Used to Prepare the
Target Distributions. The hypothetical realized prices of
gas production shown have been chosen solely for illustrative
purposes.
The tables give effect to the subordination and incentive
distribution features that are contained in the terms of the
trust. For a description of the way in which those features
would impact trust unitholders distributions, please see
Target Distributions and Subordination and Incentive
Thresholds.
The below tables are not a projection or forecast of the
actual or estimated results from an investment in the common
units. The purpose of these tables is to illustrate the
sensitivity of cash distributions to changes in production
levels and the price of natural gas. There is no assurance that
the hypothetical assumptions described below will actually occur
or that production levels and the price of natural gas will not
change by amounts different from those shown in the tables.
61
The trusts natural gas hedging contracts will be in
effect only through March 31, 2014, and thus there is
likely to be greater fluctuation in cash distributions resulting
from fluctuations in realized natural gas prices in periods
subsequent to the expiration of those contracts. See Risk
factors for a discussion of various items that could
impact production levels and the price of natural gas.
These distributions are sensitized to both assumed NYMEX natural
gas prices as well as the assumed production from the trust
properties. The quarterly distributions in the tables below are
based on assumptions outlined in Significant
Assumptions Used to Prepare the Target Distributions. In
the tables set forth below, we have provided examples of
possible distributions for the quarters ending June 30,
2010, September 30, 2010, December 31, 2010 and
March 31, 2011 based on various NYMEX pricing and
production assumptions.
For scenarios in these tables which involve lower NYMEX gas
prices and production volumes, the quarterly distribution per
unit does not fall below the subordination threshold because
either the per unit cash available for distribution to trust
unitholders was at or above the subordination threshold or the
cash flows to the subordinated units support the distributions
to the common units. For scenarios in these tables with higher
gas prices and production volumes, the quarterly distribution
per unit does not exceed the incentive threshold either because
the per unit cash available for distribution to trust
unitholders was at or below the incentive threshold or because
the per unit cash available for distribution in excess of the
incentive threshold is used to reimburse ECA for its costs of
approximately $5 million plus interest accrued at 10% per
annum to establish the natural gas hedging contracts transferred
to the trust.
62
For each table, the assumed NYMEX gas price per MMBtu used to
estimate quarterly distributions is also the assumed NYMEX gas
price for all previous quarters. In order for a trust unitholder
to receive a distribution in excess of the incentive threshold,
the hedge cost must be repaid to ECA in full.
63
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of the working interests owned
by ECA and the Private Investors in the Marcellus Shale
formation in Greene County, Pennsylvania arising under leases
and farmout agreements related to properties from which the PDP
Royalty Interest and the PUD Royalty Interest will be conveyed.
There are in excess of 100 potential drilling locations for the
PUD Wells within the AMI. As of March 31, 2010 and after
giving effect to the conveyance of the PDP Royalty Interest and
the PUD Royalty Interest, the total gas reserves attributable to
the trust interests were 104.6 Bcf. This amount includes
72.4 Bcf attributable to the PUD Royalty Interest and
32.2 Bcf attributable to the PDP Royalty Interest. ECA is
currently the operator of all of the wells subject to the PDP
Royalty Interest. ECA has an average working interest of
approximately 93% in the wells subject to the PDP Royalty
Interest. The reserves attributable to the trusts royalty
interests include the reserves that are expected to be produced
from the Marcellus Shale formation during the
20-year
period in which the trust owns the royalty interests as well as
the residual interest in the reserves that the trust will sell
on or shortly following the Termination Date.
HISTORICAL
RESULTS FROM THE PRODUCING WELLS
The following table provides revenues and direct operating
expenses relating to the Producing Wells for the six months
ended December 31, 2009 derived from the Underlying
Properties audited statement of revenues and direct
operating expenses included elsewhere in this prospectus. During
the six months ended December 31, 2009, only four of the 14
Producing Wells were completed. As a result, the information in
the table set forth below will not be comparable to the
trusts results going forward as ECA completes additional
Producing Wells. The information in the table below does not
reflect the formation of the trust or the conveyance of the PDP
Royalty Interest to the trust. The selected financial data
presented below should be read in conjunction with the audited
statement of revenues and direct operating expenses of the
Underlying Properties, the related notes and Discussion
and Analysis of Historical Results from the Producing
Wells included elsewhere in this prospectus and the
discussion of ECAs business and related Managements
Discussion and Analysis of Business and Operations set forth in
Information about Energy Corporation of America.
|
|
|
|
|
|
|
Six Months Ended
|
Historical Results
|
|
December 31, 2009
|
|
|
(Dollars in thousands, except volumetric data)
|
|
Natural gas sales volumes (Mcf) (unaudited)
|
|
|
841,261
|
|
Gross sales price per Mcf (unaudited)
|
|
$
|
4.31
|
|
|
|
|
|
|
Revenues from gas sales
|
|
$
|
3,623
|
|
Direct operating expenses:
|
|
|
|
|
Production and property taxes
|
|
|
|
|
Production expenses
|
|
|
24
|
|
Marketing fee (1)
|
|
|
132
|
|
Gathering and transportation charges
|
|
|
458
|
|
|
|
|
|
|
Total
|
|
|
614
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
3,009
|
|
|
|
|
|
|
|
|
|
(1)
|
|
A wholly-owned subsidiary of ECA
markets the production from the Underlying Properties.
Historically, such subsidiary has charged a marketing fee for
its services; however, the trust will not be charged a marketing
fee by ECA for marketing production.
|
64
NATURAL
GAS SALES PRICES AND PRODUCTION COSTS
The following table sets forth the production, the average sales
price per Mcf and the production costs for the six-month period
ended December 31, 2009 for the Producing Wells on a
historical basis and for the six months ended on
December 31, 2009 for the royalty interests on a pro forma
basis.
|
|
|
|
|
|
|
|
|
|
|
Historical for
|
|
Pro forma for
|
|
|
Producing Wells
|
|
Royalty Interest (1)
|
|
|
Six Months Ended
|
|
Six Months Ended
|
|
|
December 31,
|
|
December 31,
|
|
|
2009
|
|
2009
|
|
Production (MMcf)
|
|
|
841
|
|
|
|
757
|
|
Average net sales price per Mcf:
|
|
|
|
|
|
|
|
|
Average gross sales price per Mcf
|
|
$
|
4.31
|
|
|
$
|
4.31
|
|
Gathering and transportation charges (Mcf)
|
|
|
0.54
|
|
|
|
0.54
|
|
Average sales price (2)
|
|
|
3.60
|
|
|
|
3.76
|
|
Average production cost per Mcf (3)
|
|
$
|
0.03
|
|
|
|
|
|
|
|
|
(1)
|
|
Pro forma figures are calculated as
if the conveyances were in effect for the period indicated.
|
|
(2)
|
|
Average sales price generally
represents the realized price of gas which is net of
post-production costs and applicable taxes, if any.
|
|
(3)
|
|
Production costs include lease
operating costs.
|
DISCUSSION
AND ANALYSIS OF HISTORICAL RESULTS FROM THE PRODUCING
WELLS
The Producing Wells for the six months ended December 31,
2009 consisted of four horizontal wells producing from the
Marcellus Shale formation in Greene County, Pennsylvania. One
well began producing in each of the months of July, August,
September and October 2009. At the end of the period, all
four wells were completed and producing an average of more
than 5,600 Mcf per day. Total volumes produced during the
period from the properties were in excess of 800,000 Mcf.
These wells were drilled with an average lateral length of
2,000 feet and completed with an average of
7.5 fracture stimulations per well. The average gross sales
price received for gas produced was $4.31 per Mcf, before
deduction of any post-production costs or operating expenses.
Post-production costs, which consist of gathering and marketing
fees, averaged $0.70 per Mcf. Operating expenses averaged
approximately $1,333 per well month during the period. Revenues
less direct operating expenses were approximately
$3.01 million for the six months ended December 31,
2009.
THE
UNDERLYING PUD PROPERTIES
At the completion of this offering, the underlying PUD
properties will consist of all of the working interests in
proved undeveloped gas properties in the AMI held by ECA. The
interests of ECA in the gas properties to which the underlying
PUD properties relate consist of working interests of
approximately 100%. The conveyance related to the PUD Royalty
Interest, however, provides that the proceeds from the PUD Wells
will be calculated on the basis that the underlying PUD Wells
are only burdened by interests that in total would not exceed
12.5% of the revenues from such properties, regardless of
whether the other interest owners are actually entitled to a
greater percentage of revenues from such properties. The AMI is
located in Greene County, Pennsylvania, which is in southwestern
Pennsylvania and consists of approximately 121 square miles.
65
The PUD Royalty Interest will entitle the trust to receive an
undivided 50% interest in the proceeds from the sale of future
production of natural gas resulting from the drilling of the PUD
Wells. Once ECA has drilled all of the PUD Wells, the trustee
will be required to release the Drilling Support Lien.
ECA will covenant and agree not to drill and complete, and will
not permit any other person within its control to drill and
complete, any well in the Marcellus Shale formation on the lease
acreage included within the AMI described above for its own
account until such time as ECA has met its commitment to drill
the PUD Wells. Upon the trustees release of the Drilling
Support Lien, ECA will further agree not to drill and complete,
and will not permit any other person within its control to drill
and complete, any well in the Marcellus Shale formation on the
lease acreage that is located within 500 feet of any PUD or
Producing Well.
ECA, in the conveyance documents for the PUD Royalty Interest,
will expressly except and reserve all right, title and interest
in and to any well and appurtenant production facilities not
expressly conveyed to the trust. The PDP Royalty Interest is
included within the AMI and those properties will remain subject
to the terms and conditions of the PDP Royalty Interest
conveyance documents.
The PUD Royalty Interest conveyances shall further provide that
the PUD Royalty Interest of the trust will be applicable to any
additional acreage leased or acquired by any other means by ECA
within the AMI until the drilling obligation of ECA to the trust
is met. No assurance can be given, however, that any development
well will produce in commercial quantities or that the
characteristics of any development well will match the
characteristics of ECAs existing wells or ECAs
historical drilling success rate. ECA operates all of the
Producing Wells and will agree to operate not less than 90% of
the PUD Wells during the subordination period.
NATURAL
GAS RESERVES
Ryder Scott estimated natural gas reserves attributable to the
Underlying Properties as of March 31, 2010. Numerous
uncertainties are inherent in estimating reserve volumes and
values, and the estimates are subject to change as additional
information becomes available. The reserves actually recovered
and the timing of production of the reserves may vary
significantly from the original estimates.
66
Proved reserves of Underlying Properties and royalty
interests.
The following table, effective as of
March 31, 2010, contains certain estimated proved reserves,
estimated future net revenues and the discounted present value
thereof attributable to both the Underlying Properties and the
royalty interests, in each case derived from the reserve report.
The reserve report was prepared by Ryder Scott in accordance
with criteria established by the SEC. In accordance with the
SECs new rules, the reserves presented below were
determined using the twelve month unweighted arithmetic average
of the
first-day-of-the-month
price for the period from April 1, 2009 through
March 1, 2010, without giving effect to any derivative
transactions, and were held constant for the life of the
properties. This yielded a price for natural gas of $3.984 per
MMBtu. Proved reserve quantities attributable to the royalty
interests are calculated by multiplying the gross reserves for
each property by the royalty interest assigned to the trust in
each property. The net revenues attributable to the trusts
reserves are net of the trusts obligation to reimburse ECA
for the post-production costs. The reserves related to the
Underlying Properties include all of the proved reserves
expected to be economically produced from the Marcellus Shale
formation during the life of the properties. The reserves and
revenues attributable to the trusts interests include only
the reserves attributable to the Underlying Properties that are
expected to be produced within the
20-year
period in which the trust owns the royalty interest as well as
the 50% residual interest in the reserves that the trust will
own on the Termination Date. A summary of the reserve report is
included as Annex A to this prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Gas
|
|
|
|
Discounted
|
|
|
Reserves
|
|
Estimated Future
|
|
Estimated Future
|
Proved reserves
|
|
(Bcfe)
|
|
Net Revenues
|
|
Net Revenues (1)
|
|
|
(Dollars in thousands)
|
|
Underlying Properties
|
|
|
193.8
|
|
|
$
|
507,289
|
|
|
$
|
168,687
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty Interests:
|
|
|
|
|
|
|
|
|
|
|
|
|
PDP Royalty Interest (90%) (2)
|
|
|
32.2
|
|
|
$
|
119,757
|
|
|
$
|
67,161
|
|
PUD Royalty Interest (50%)
|
|
|
72.4
|
|
|
$
|
269,175
|
|
|
$
|
133,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
104.6
|
|
|
$
|
388,932
|
|
|
$
|
200,270
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The present values of future net
revenues for the Underlying Properties and the royalty interests
were determined using a discount rate of 10% per annum.
|
|
(2)
|
|
Includes reserves currently behind
pipe in existing wells which are in the process of being
completed.
|
Information concerning historical changes in net proved reserves
attributable to the Underlying Properties, and the calculation
of the standardized measure of discounted future net revenues
related thereto, is contained in the unaudited supplemental
information contained elsewhere in this prospectus. ECA has not
filed reserve estimates covering the Underlying Properties with
any other federal authority or agency.
SALE AND
ABANDONMENT OF UNDERLYING PROPERTIES
ECA and any transferee will have the right to abandon its
interest in any well or property comprising a portion of the
Underlying Properties if, in its opinion, such well or property
ceases to produce or is not capable of producing in commercially
paying quantities. To reduce or eliminate the potential conflict
of interest between ECA and the trust in determining whether a
well is capable of producing in commercially paying quantities,
ECA is required under the applicable conveyance to act as a
reasonably prudent operator in the AMI under the same or similar
circumstances would act if it were acting with respect to its
own properties, disregarding the existence of the royalty
interests as a burden affecting such property.
67
After completion of its drilling obligation, ECA generally may
sell all or a portion of its interests in the Underlying
Properties, subject to and burdened by the royalty interests,
without the consent of the trust unitholders. In addition, ECA
may, without the consent of the trust unitholders, require the
trust to release royalty interests with an aggregate value to
the trust not to exceed $5.0 million during any
12-month
period. These releases will be made only in connection with a
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests. ECA operates all of the
Producing Wells and will operate not less than 90% of the PUD
Wells during the subordination period. Any net sales proceeds
paid to the trust are distributable to trust unitholders for the
quarter in which they are received. ECA has not identified for
sale any of the Underlying Properties.
MARKETING
AND POST-PRODUCTION SERVICES
Pursuant to the terms of the conveyances creating the royalty
interests, ECA will have the responsibility to market, or cause
to be marketed, the natural gas production related to the
Underlying Properties. The terms of the conveyances creating the
royalty interests do not permit ECA to charge any marketing fee
when determining the proceeds upon which the royalty payments
will be calculated. As a result, the proceeds to the trust from
the sales of natural gas production from the Underlying
Properties will be determined based on the same price (net of
post-production costs) that ECA receives for natural gas
production attributable to ECAs remaining interest in the
Underlying Properties.
A wholly owned subsidiary of ECA markets the majority of
ECAs operated production and markets substantially all of
the gas produced from the Underlying Properties. Such subsidiary
enters into gas sales arrangements with large aggregators of
supply and these arrangements may be on a
month-to-month
basis or may be for a term of up to one year or longer. The
natural gas is sold at a market price and subsequently any
applicable post-production costs will be deducted. The trust
will not be charged any fee for marketing by ECA. The primary
aggregators of supply with whom ECA currently does business in
the AMI are BP Energy Company, Equitable Energy LLC, South
Jersey Resource Group and Hess Corporation. In addition to
providing marketing services, ECAs subsidiary purchases
all of the production from the Underlying Properties.
Substantially all of the production from the Producing Wells and
the PUD Wells will be gathered by ECAs Greene County
Gathering System. Following this offering, the trust will pay
the initial Post-Production Services Fee of $0.52 per MMBtu for
use of this system, including ECAs costs to gather,
compress, transport, process, treat, dehydrate and market the
gas. This fee is fixed until ECAs drilling obligation is
satisfied; thereafter, ECA may increase this fee to the extent
necessary to recover certain capital expenditures on the Greene
County Gathering System made after the completion of the
drilling period, provided the resulting charge does not exceed
the prevailing charges in the area for similar services. This
fee does not include the cost of fuel used in the compression
process or equivalent electricity charges when electric
compressors are used. The reserve report assumes a 5% retainage
for compression fuel and line loss on the Greene County
Gathering System. This percentage represents current operating
conditions, though such level may fluctuate going forward. The
trusts cash available for distribution will be reduced by
ECAs deductions for these post-production services.
There are currently no third-party post-production costs, but
ECA or one of its affiliates may enter into arrangements with
third parties to provide gathering, transportation, processing
and other reasonable post-production services, including
transportation on downstream interstate pipelines. Such
additional post-production costs will be expressed as either
(1) a cost per MMBtu or Mcf or (2) a percentage of the
gross production from a well. To the extent that post-production
costs are expressed as a cost per MMBtu or Mcf, such costs may
be deducted by the ultimate
68
purchaser of the natural gas prior to payment being made to ECA
or its marketing affiliate for such production. At other times,
ECA or its marketing affiliate will make payments directly to
the third parties providing such post-production services. In
either instance, the trusts cash available for
distribution will be reduced by the costs paid by ECA for such
post-production services provided by third parties. If the
post-production costs are expressed as a percentage of the gross
production from a well, then the volume of production from that
well actually available for sale is less the applicable
percentage charged, and as a result the reserves associated with
that well that are attributable to the royalty interest are
reduced accordingly.
The post-production costs for natural gas production from the
Producing Wells were $0.52 per MMBtu as of December 31,
2009. After giving effect to the drilling and completion of the
PUD Wells, ECA anticipates that the Post-Production Services Fee
will be the only such cost, yielding the weighted average
post-production costs for production attributable to the
trusts royalty interest of approximately $0.52 per MMBtu.
Regardless of whether the post-production costs are based upon
(1) a cost per MMBtu or Mcf or (2) a percentage of
gross production from a well, such costs may increase or
decrease in the future. The post-production costs attributable
to third party arrangements may be costs established by
arms-length negotiations or pursuant to a state or federal
regulatory proceeding. ECA will be permitted to deduct from the
proceeds available to the trust other post-production costs
necessary to make the natural gas from the Underlying Properties
marketable, so long as such costs do not materially exceed the
charges prevailing in the area for similar services.
ECA expects to enter into similar gas supply arrangements and
post-production service arrangements for the gas to be produced
from the underlying PUD properties. Any new gas supply
arrangements or those entered into for providing post-production
services, will be utilized in determining the proceeds for the
Underlying Properties.
TITLE TO
PROPERTIES
The Underlying Properties are subject to certain burdens that
are described in more detail below. To the extent that these
burdens and obligations affect ECAs rights to production
and the value of production from the Underlying Properties, they
have been taken into account in calculating the trusts
interests and in estimating the size and the value of the
reserves attributable to the royalty interests.
ECA acquired its interests in the Underlying Properties through
a variety of means, including through the acquisition of oil and
gas leases by ECA directly from the mineral owner, through
assignments of oil and gas leases to ECA by the lessee who
originally obtained the leases from the mineral owner, through
farmout agreements that grant ECA the right to earn interests in
the properties covered by such agreements by drilling wells, and
through acquisitions of other oil and gas interests by ECA.
ECAs interests in the gas properties comprising the
Underlying Properties are typically subject, in one degree or
another, to one or more of the following:
|
|
|
|
|
royalties and other burdens, express and implied, under gas
leases;
|
|
|
|
production payments and similar interests and other burdens
created by ECA or its predecessors in title;
|
69
|
|
|
|
|
a variety of contractual obligations arising under operating
agreements, farmout agreements, production sales contracts and
other agreements that may affect the properties or their titles;
|
|
|
|
liens that arise in the normal course of operations, such as
those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under operating
agreements that are not yet delinquent or, if delinquent, are
being contested in good faith by appropriate proceedings;
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|
pooling, unitization and communitization agreements,
declarations and orders;
|
|
|
|
easements, restrictions,
rights-of-way
and other matters that commonly affect property;
|
|
|
|
conventional rights of reassignment that obligate ECA to
reassign all or part of a property to a third party if ECA
intends to release or abandon such property; and
|
|
|
|
rights reserved to or vested in the appropriate governmental
agency or authority to control or regulate the Underlying
Properties and the royalty interests therein.
|
ECA believes that the burdens and obligations affecting the
Underlying Properties and the royalty interests are conventional
in the industry for similar properties. ECA also believes that
the burdens and obligations do not, in the aggregate, materially
interfere with the use of the Underlying Properties and will not
materially adversely affect the value of the royalty interest.
ECA believes that its title to the Underlying Properties is, and
the trusts title to the royalty interests will be, good
and defensible in accordance with standards generally accepted
in the oil and gas industry, subject to such exceptions as are
not so material as to detract substantially from the use or
value of such properties or royalty interests. Consistent with
industry practice, ECA has not obtained a preliminary title
review of the PUD Wells. Prior to drilling a PUD Well, ECA
intends to obtain a preliminary title review to ensure there are
no obvious defects in title to the well. Frequently, as a result
of such examination, certain curative work must be done to
correct defects in the marketability of title. ECA does not
intend to perform any further title examination prior to the
closing of the offering being made hereby. The conveyance
related to the PUD Royalty Interest obligates ECA to conduct a
more thorough title examination of the drill site tract prior to
drilling any of the PUD Wells. ECA will not be relieved of its
obligation to drill a well if such title examination prior to
drilling reveals a title defect preventing ECA from drilling in
such drill site.
It is unclear under Pennsylvania law whether the royalty
interests would be treated as real property interests.
Nevertheless, ECA intends to record the conveyances of the
royalty interests in the real property records of Pennsylvania
in accordance with local recording acts. ECA will grant to the
trust the Royalty Interest Lien to provide protection to the
trust, in the event of a bankruptcy of ECA, against the risk
that the royalty interests were not considered real property
interests.
COMPETITION
AND MARKETS
The natural gas industry is highly competitive. ECA competes
with major oil and gas companies and independent oil and gas
companies for oil and gas leases, equipment, personnel and
markets for the sale of natural gas. Many of these competitors
are financially stronger than ECA, but even financially troubled
competitors can affect the market because of their need to sell
natural gas at any price to attempt to maintain cash flow. The
trust will be subject to the same competitive conditions as ECA
and other companies in the natural gas industry.
70
Natural gas competes with other forms of energy available to
customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy,
as well as business conditions, conservation, legislation,
regulations and the ability to convert to alternate fuels and
other forms of energy may affect the demand for natural gas.
Future price fluctuations for natural gas will directly impact
trust distributions, estimates of reserves attributable to the
trusts interests, and estimated and actual future net
revenues to the trust. In view of the many uncertainties that
affect the supply and demand for natural gas, neither the trust
nor ECA can make reliable predictions of future gas supply and
demand, future gas prices or the effect of future gas prices on
the trust.
REGULATION
Natural gas regulation.
The availability, terms and
cost of transportation significantly affect sales of natural
gas. The interstate transportation and sale for resale of
natural gas is subject to federal regulation, including
regulation of the terms, conditions and rates for interstate
transportation, storage and various other matters, primarily by
the Federal Energy Regulatory Commission. Federal and state
regulations govern the price and terms for access to natural gas
pipeline transportation. The Federal Energy Regulatory
Commissions regulations for interstate natural gas
transmission in some circumstances may also affect the
intrastate transportation of natural gas.
Although natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas
regulation. Neither ECA nor the trust can predict whether new
legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the
various state legislatures, and what effect, if any, the
proposals might have on the operations of the Underlying
Properties. Sales of condensate and natural gas liquids are not
currently regulated and are made at market prices.
Environmental regulation.
The exploration,
development and production operations of ECA are subject to
stringent and comprehensive federal, state and local laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may, among other things, require the
acquisition of permits to conduct drilling, water withdrawal and
waste disposal operations; govern the amounts and types of
substances that may be disposed or released into the
environment; limit or prohibit construction or drilling
activities in sensitive areas such as wetlands, wilderness areas
or areas inhabited by endangered or threatened species; require
investigatory and remedial actions to mitigate pollution
conditions arising from ECAs operations or attributable to
former operations; and impose obligations to reclaim and abandon
well sites and pits. Failure to comply with these laws and
regulations may result in the assessment of administrative,
civil and criminal penalties, the imposition of remedial
obligations and the issuance of orders enjoining some or all of
ECAs operations in affected areas.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, any changes in environmental laws and
regulations or re-interpretation of enforcement policies that
result in more stringent and costly waste handling, storage,
transport, disposal, or remediation requirements could have a
material adverse effect on ECAs operations and financial
position. ECA may be unable to pass on such increased compliance
costs to its customers. Moreover, accidental releases or spills
may occur in the course of ECAs operations, and there can
be no assurance that ECA will not incur significant costs and
liabilities as a result of such releases or spills, including
any third party claims for damage to property and natural
resources or personal injury. While ECA believes that it is in
71
substantial compliance with existing environmental laws and
regulations and that continued compliance with current
requirements would not have a material adverse effect on it,
there is no assurance that this trend will continue in the
future.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations to which
ECAs business operations are subject and for which
compliance may have a material adverse impact on ECAs
capital expenditures, results of operations or financial
position.
Hazardous Substances and Wastes.
The Comprehensive
Environmental Response, Compensation, and Liability Act, as
amended, (CERCLA), also known as the Superfund law
and comparable state laws impose liability without regard to
fault or the legality of the original conduct on certain classes
of persons who are considered to be responsible for the release
of a hazardous substance into the environment. These
persons include current and prior owners or operators of the
site where the release occurred and entities that disposed or
arranged for the disposal of the hazardous substances found at
the site. Under CERCLA, these responsible persons
may be subject to joint and several, strict liability for the
costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources,
and for the costs of certain health studies. CERCLA also
authorizes the EPA and, in some instances, third parties to act
in response to threats to the public health or the environment
and to seek to recover from the responsible classes of persons
the costs they incur. It is not uncommon for neighboring
landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of
hazardous substances or other pollutants into the environment.
ECA generates materials in the course of ECAs operations
that may be regulated as hazardous substances.
ECA also generates solid and hazardous wastes that are subject
to the requirements of the Resource Conservation and Recovery
Act, as amended (RCRA), and comparable state
statutes. RCRA imposes strict requirements on the generation,
storage, treatment, transportation and disposal of hazardous
wastes. In the course of its operations, ECA generates petroleum
hydrocarbon wastes and ordinary industrial wastes that may be
regulated as hazardous wastes.
ECA currently owns or leases, and in the past may have owned or
leased, properties that have been used for numerous years to
explore and produce oil and natural gas. Although ECA may have
utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons and wastes may have been
disposed of or released on or under the properties owned or
leased by ECA or on or under the other locations where these
hydrocarbons and wastes have been taken for treatment or
disposal. In addition, certain of these properties have been
operated by third parties whose treatment and disposal or
release of hydrocarbons and wastes was not under ECAs
control. These properties and wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under these
laws, ECA could be required to remove or remediate previously
disposed wastes, to clean up contaminated property and to
perform remedial operations to prevent future contamination.
Air Emissions.
The Clean Air Act, as amended, and
comparable state laws and regulations restrict the emission of
air pollutants from many sources and also impose various
monitoring and reporting requirements. These laws and
regulations may require ECA to obtain pre-approval for the
construction or modification of certain projects or facilities
expected to produce or significantly increase air emissions,
obtain and strictly comply with stringent air permit
requirements or utilize specific equipment or technologies to
control emissions. Obtaining permits has the potential to delay
the development of natural gas projects. While ECA may be
required to incur certain capital expenditures in the next few
years for air pollution control
72
equipment or other air emissions-related issues, ECA does not
believe that such requirements will have a material adverse
effect on its operations.
Climate Change.
In response to certain scientific
studies suggesting that emissions of certain gases, commonly
referred to as greenhouse gases (GHGs) and including
carbon dioxide and methane, are contributing to the warming of
the Earths atmosphere and other climatic changes, the
U.S. House of Representatives passed the American
Clean Energy and Security Act of 2009 (ACESA)
on June 26, 2009, which would establish an economy-wide
cap-and-trade
program to reduce U.S. emissions of GHGs that may
contribute to warming of the Earths atmosphere and other
climatic changes. ACESA would require a 17 percent
reduction in GHG emissions from 2005 levels by 2020 and just
over an 80% reduction of such emissions by 2050. Under this
legislation, the EPA would issue a capped and steadily declining
number of tradable emissions allowances to major sources of GHG
emissions so that such sources could continue to emit GHGs into
the atmosphere. These allowances would be expected to escalate
significantly in cost over time. The U.S. Senate has begun
work on its own legislation for restricting domestic GHG
emissions and President Obama has indicated his support of
legislation to reduce GHG emissions through an emission
allowance system. Although it is not possible at this time to
predict when the Senate may act on climate change legislation or
how any bill passed by the Senate would be reconciled with
ACESA, any future federal laws or implementing regulations that
may be adopted to address GHG emissions could require ECA to
incur increased operating costs and could adversely affect
demand for the natural gas that it produces.
In addition, on December 15, 2009, the EPA published its
findings that emissions of carbon dioxide, methane and other
GHGs present an endangerment to public health and the
environment because emissions of such gases are, according to
the EPA, contributing to warming of the earths atmosphere
and other climatic changes. These findings allow the EPA to
adopt and implement regulations that would restrict emissions of
GHGs under existing provisions of the federal Clean Air Act.
These findings allow the EPA to adopt and implement regulations
that would restrict emissions of GHGs under existing provisions
of the federal Clean Air Act. Accordingly, the EPA has proposed
regulations that would require a reduction in emissions of GHGs
from motor vehicles and could trigger permit review for GHG
emissions from certain stationary sources. In addition, on
October 30, 2009, the EPA published a final rule requiring
the reporting of GHG emissions from specified large GHG emission
sources in the United States, including sources emitting more
than 25,000 tons of GHGs on an annual basis, beginning in 2011
for emissions occurring in 2010. Only very recently, on
March 23, 2010, the EPA announced a proposed rulemaking
that would expand its final rule on reporting of GHG emissions
to include owners and operators of onshore oil and natural gas
production. If the proposed rule is finalized in its current
form, reporting of GHG emissions from such onshore production
would be required on an annual basis beginning in 2012 for
emissions occurring in 2011. The adoption and implementation of
any regulations imposing reporting obligations on, or limiting
emissions of GHG gases from, ECAs equipment and operations
could require ECA to incur costs to reduce emissions of GHGs
associated with its operations or could adversely affect demand
for the natural gas it produces. Finally, it should be noted
that some scientists have concluded that increasing
concentrations of GHGs in the Earths atmosphere may
produce climate changes that have significant physical effects,
such as increased frequency and severity of storms, droughts,
and floods and other climatic events; if any such effects were
to occur, they could have an adverse effect on ECAs assets
and operations.
Even if such legislation is not adopted at the national level,
more than one-third of the states have begun taking actions to
control
and/or
reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories
and/or
regional GHG cap and trade programs. Although most of the
state-level initiatives have to date focused on large sources of
GHG emissions, such as coal-fired electric plants, it is
possible that smaller sources of emissions could
73
become subject to GHG emission limitations or allowance purchase
requirements in the future. Any one of these climate change
regulatory and legislative initiatives could have a material
adverse effect on ECAs business, financial condition and
results of operations.
Water Discharges.
The Federal Water Pollution
Control Act, as amended (Clean Water Act), and
analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into navigable waters.
Pursuant to the Clean Water Act and analogous state laws,
permits must be obtained to discharge pollutants into state
waters or waters of the United States. Any such discharge of
pollutants into regulated waters must be performed in accordance
with the terms of the permit issued by EPA or the analogous
state agency. Spill prevention, control and countermeasure
requirements under federal law require appropriate containment
berms and similar structures to help prevent the contamination
of navigable waters in the event of a petroleum hydrocarbon tank
spill, rupture or leak. In addition, the Clean Water Act and
analogous state laws, including Pennsylvania, require individual
permits or coverage under general permits for discharges of
storm water runoff from certain types of facilities.
It is customary to recover natural gas from deep shale
formations, including the Marcellus Shale formation, through the
use of hydraulic fracturing, combined with sophisticated
horizontal drilling. Hydraulic fracturing involves the injection
of water, sand and chemical additives under pressure into rock
formations to stimulate gas production. Due to public concerns
raised regarding potential impacts of hydraulic fracturing on
groundwater quality, legislative and regulatory efforts at the
federal level and in some states have been initiated to require
or make more stringent the permitting and compliance
requirements for hydraulic fracturing operations. In particular,
the U.S. Congress has introduced a bill entitled the
Fracturing Responsibility and Awareness of Chemicals
Act to amend the federal Safe Drinking Water Act to
subject hydraulic fracturing operations to regulation under that
Act and to require the disclosure of chemicals used by the oil
and gas industry in the hydraulic fracturing process. Sponsors
of bills currently pending before the U.S. Senate and House
of Representatives have asserted that chemicals used in the
fracturing process could adversely affect drinking water
supplies. Proposed legislation would require, among other
things, the reporting and public disclosure of chemicals used in
the fracturing process, which could make it easier for third
parties opposing the hydraulic fracturing process to initiate
legal proceedings against producers. Recently, on March 18,
2010, the EPA announced that it has allocated $1.9 million
in 2010 and has requested funding in fiscal year 2011 for
conducting a comprehensive research study on the potential
adverse impacts that hydraulic fracturing may have on water
quality and public health. While performance of the EPA study is
not imminent, the results of such a study, once completed, could
further spur action towards federal legislation and regulation
of hydraulic fracturing activities. These bills, if adopted,
could establish an additional level of regulation and permitting
of hydraulic fracturing operations at the federal level, which
could lead to operational delays, increased operating costs and
additional regulatory burdens that could make it more difficult
for ECA to perform hydraulic fracturing. Any increased federal,
state or local regulation could reduce the volumes of natural
gas that ECA produces, which would materially adversely affect
its revenues and results of operations.
Endangered Species Act.
The federal Endangered
Species Act, as amended (ESA), restricts activities
that may affect endangered and threatened species or their
habitats. While some of ECAs facilities or leased acreage
may be located in areas that are designated as habitat for
endangered or threatened species, ECA believes that it is in
substantial compliance with the ESA. However, the designation of
previously unidentified endangered or threatened species could
cause ECA to incur additional costs or become subject to
operating restrictions or bans in the affected areas.
74
Employee Health and Safety.
The operations of ECA
are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act, as amended (OSHA), and comparable state
statutes, whose purpose is to protect the health and safety of
workers. In addition, the OSHA hazard communication standard,
the EPA community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in ECAs operations and that
this information be provided to employees, state and local
government authorities and citizens. ECA believes that it is in
substantial compliance with all applicable laws and regulations
relating to worker health and safety.
State regulation.
Pennsylvania regulates the
drilling for, and the production, gathering and sale of, natural
gas, including imposing requirements for obtaining drilling
permits, the method of developing new fields, the spacing and
operation of wells, production rates and the prevention of waste
of natural gas resources. Realized prices are not currently
subject to state regulation or subject to other similar direct
economic regulation, but there can be no assurance that they
will not do so in the future. The effect of these regulations
may be to limit the amounts of natural gas that may be produced
from ECAs wells and to limit the number of wells or
locations ECA can drill.
75
DESCRIPTION
OF THE ROYALTY INTERESTS
The royalty interests will be conveyed to the trust by ECA by
means of conveyance instruments that will be recorded in the
appropriate real property records in Greene County, Pennsylvania
where the gas properties to which the Underlying Properties
relate are located. The PDP Royalty Interest will burden the
existing working interests owned by ECA in the Producing Wells.
ECA has an average working interest of approximately 93% in
these wells.
The PUD Royalty Interest will initially burden 50% of all of the
interests of ECA in the Marcellus Shale formation in the AMI.
ECAs interests in the gas properties to which the PUD
Wells relate consist of an average working interest of 100%. The
conveyance related to the PUD Royalty Interest, however,
provides that the proceeds from the PUD Wells will be calculated
on the basis that the PUD Wells are only burdened by interests
that in total would not exceed 12.5%. In the event that
ECAs interest in any of the wells subject to the PUD
Royalty Interest that are drilled is subject to burdens in
excess of a 12.5%, such burdens will be fully allocated against
ECAs retained interest in such well, the net effect of
which is that the trust will receive payments with respect to
the PUD Royalty Interest as if the burdens effecting the PUD
Wells were in total 12.5% (proportionately reduced). Please see
The Trust Administrative and Drilling Services
Agreement for a description of the drilling obligations of
ECA to the trust.
PDP Royalty Interest.
The conveyances creating the
PDP Royalty Interest entitle the trust to receive an amount of
cash for each calendar quarter equal to 90% of the proceeds
(after deducting postproduction costs and any applicable
taxes) from the sale of estimated natural gas production
attributable to the Producing Wells regardless of whether such
amounts have actually been received by ECA from the purchases of
the natural gas produced. Proceeds from the sale of natural gas
production attributable to the Producing Wells in any calendar
quarter means:
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amount calculated based on estimated production volumes
attributable to the Producing Wells;
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in each case, after deducting the trusts proportionate
share of:
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any taxes levied on the severance or production of the natural
gas produced from the Producing Wells and any property taxes
attributable to the natural gas production attributable to the
Producing Wells; and
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post-production costs, which will generally consist of costs
incurred to gather, compress, transport, process, treat,
dehydrate and market the natural gas produced. Any charge
payable to ECA for such post-production costs on its Greene
County Gathering System will be limited to $0.52 per MMBtu of
gas gathered until ECA has fulfilled its drilling obligation.
Thereafter, ECA may increase this Post-Production Service Fee to
the extent it is necessary to recover certain capital
expenditures in ECAs Greene County Gathering System.
Additionally, the trust will be charged for the cost of fuel
used in the compression process, including equivalent
electricity charges in instances when electric compressors are
used.
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Proceeds payable to the trust from the sale of natural gas
production attributable to the Producing Wells in any calendar
quarter will not be subject to any deductions for any expenses
attributable to exploration, drilling, development, operating,
maintenance or any other costs incident to the production of
natural gas production attributable to the Producing Wells,
including any costs to plug and abandon a Producing Well.
76
PUD Royalty Interest.
The conveyances creating the
PUD Royalty Interest entitles the trust to receive an amount of
cash for each calendar quarter equal to 50% of the proceeds
(after deducting postproduction costs and any applicable
taxes) from the sale of estimated natural gas production
attributable to the PUD Wells regardless of whether such amounts
have actually been received by ECA from the purchase of the
natural gas produced. Proceeds from the sale of natural gas
production, if any, attributable to the PUD Wells in any
calendar quarter means:
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for any calendar quarter commencing on or after April 1,
2010, the amount calculated based on estimated production
volumes attributable to the PUD Wells:
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in each case after deducting the trusts proportionate
share of:
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any taxes levied on the severance or production of the natural
gas produced from the PUD Wells and any property taxes
attributable to the gas produced from the PUD Wells; and
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post-production costs will generally consist of costs incurred
to gather, compress, transport, process, treat, dehydrate and
market the natural gas produced. Any charge payable to ECA for
such post-production charges on its with ECAs Greene
County Gathering System will be limited to $0.52 per MMBtu of
gas gathered until ECA has fulfilled its drilling obligation.
Thereafter, ECA may increase this Post-Production Services Fee
to the extent is necessary to recover certain capital
expenditures in ECAs Greene County Gathering System.
Additionally, the trust will be charged for the cost of fuel
used in the compression process, including equivalent
electricity charges in instances when electric compressors are
used.
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Proceeds, if any, payable to the trust from the sale of natural
gas production attributable to the PUD Wells in any calendar
quarter:
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will be determined on the basis that ECAs working interest
with respect to the PUD Wells is not subject to burdens
(landowners royalties and other similar interests) in
excess of 12.5% of the proceeds from gas production attributable
to ECAs interest; and
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will not be subject to any deductions for any expenses
attributable to exploration, drilling, development, operating,
maintenance or any other costs incident to the production of
natural gas production attributable to the underlying PUD
properties, including any costs to plug and abandon a well
included in the underlying PUD properties.
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Royalty
Interest Lien
Under the laws of Pennsylvania, it is not clear that the royalty
interests conveyed by ECA to the trust would be treated as real
property interests. Therefore, ECA will grant to the trust the
Royalty Interest Lien to provide protection to the trust,
exercisable in the event of a bankruptcy of ECA, against the
risk that the royalty interests were not considered real
property interests. More specifically, the Royalty Interest Lien
will be a lien in the Subject Interest and the Subject Gas, to
the extent and only to the extent that such Subject Interest and
Subject Gas pertains to Gas in, under and that may be produced,
saved or sold from the Marcellus Shale formation from the
wellbore of the Producing Wells and the PUD Wells, sufficient to
cause the trust to receive a volume of Trust Gas calculated
in accordance with the provisions of the conveyances of the
77
royalty interests. Capitalized terms used in the preceding
sentence and not otherwise defined in this prospectus shall have
the following meanings:
Gas means natural gas and all other gaseous
hydrocarbons, excluding condensate, butane, and other liquid and
liquefiable components that are actually removed from the Gas
stream by separation, processing, or other means.
Subject Gas means Gas from the Marcellus Shale
formation from any Producing Well or PUD Well.
Subject Interest means ECAs undivided
interests in the AMI, as lessee under Gas leases, as an owner of
the Subject Gas (or the right to extract such Gas), or
otherwise, by virtue of which undivided interests ECA has the
right to conduct exploration and Gas production operations on
the AMI.
Trust Gas means that percentage of Gas to which
the Trust is entitled, calculated in accordance with the
provisions of the conveyances of the royalty interests.
It is expressly understood and agreed that the Royalty Interest
Lien shall not include ECAs retained interest in the PUD
and Producing Wells and the AMI or other interest of ECA in the
AMI, and ECA shall have the right to lien, mortgage, sell or
otherwise encumber the ECA retained interest subject to the
Royalty Interest Lien.
ECA will record the conveyances of the royalty interests and a
Mortgage/Fixture Filing in the real estate records of Greene
County, Pennsylvania and will file a corresponding UCC-1
Financing Statement in the Office of the Secretary of State of
West Virginia and the Commonwealth of Pennsylvania.
Hedging
Contracts Transferred to the Trust
At the closing of this offering, ECA will also transfer to the
trust natural gas derivative contracts that equate to
approximately 50% of the estimated natural gas to be produced by
the trust properties from April 1, 2010 through
March 31, 2014. These hedging contracts will consist of
swap contracts and floor price hedging contracts. The swap
contracts will relate to approximately 7,500 MMBtu per day
at an average price of $6.78 per MMBtu for the period commencing
as of April 1, 2010 through June 30, 2012. The floor
price of any floor price hedging contract will be $5.00 per
MMBtu.
78
The following table sets forth the volumes of natural gas
covered by the natural gas hedging contracts and the floor price
for each quarter during the term of the contracts.
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Swap Volume
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Swap Price
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Floor Volume
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Floor Price
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(MMBtu)
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(MMBtu)
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(MMBtu)
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(MMBtu)
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Second Quarter 2010
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682,500
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$
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6.75
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Third Quarter 2010
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690,000
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$
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6.75
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Fourth Quarter 2010
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690,000
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$
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6.75
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225,000
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$
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5.00
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First Quarter 2011
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675,000
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$
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6.75
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159,000
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$
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5.00
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Second Quarter 2011
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682,500
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$
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6.75
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210,000
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$
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5.00
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Third Quarter 2011
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690,000
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$
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6.82
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405,000
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$
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5.00
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Fourth Quarter 2011
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690,000
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$
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6.82
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384,000
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$
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5.00
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First Quarter 2012
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682,500
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$
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6.82
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369,000
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$
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5.00
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Second Quarter 2012
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682,500
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$
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6.82
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516,000
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$
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5.00
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Third Quarter 2012
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1,305,000
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$
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5.00
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Fourth Quarter 2012
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1,362,000
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$
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5.00
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First Quarter 2013
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1,395,000
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$
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5.00
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Second Quarter 2013
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1,380,000
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$
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5.00
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Third Quarter 2013
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1,278,000
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$
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5.00
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Fourth Quarter 2013
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1,188,000
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$
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5.00
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First Quarter 2014
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1,092,000
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$
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5.00
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79
The conveyances also provide that if ECAs interest with
respect to the PDP properties is greater than what was warranted
to the trust in the conveyances, ECA will have the right to
offset against amounts owed to the trust, the difference between
what the trust actually receives from PDP Royalty Interest and
what the trust should have received from the PDP Royalty
Interest had ECAs interest been the amount warranted.
The trust will begin to liquidate on the Termination Date and
will soon thereafter wind up its affairs and terminate. The Term
Royalties will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds thereof will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a first right
of refusal to purchase the Perpetual Royalties at the
Termination Date.
ADDITIONAL
PROVISIONS
If a controversy arises as to the sales price of any production,
then for purposes of determining gross proceeds:
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amounts withheld or placed in escrow by a purchaser are not
considered to be received by the owner of the underlying
property until actually collected;
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amounts received by the owner of the underlying property and
promptly deposited with a nonaffiliated escrow agent will not be
considered to have been received until disbursed to it by the
escrow agent; and
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amounts received by the owner of the underlying property and not
deposited with an escrow agent will be considered to have been
received.
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The trustee is not obligated to return any cash received from
the royalty interests. Any overpayments made to the trust by ECA
due to adjustments to prior calculations of proceeds or
otherwise will reduce future amounts payable to the trust until
ECA recovers the overpayments.
The conveyances generally permit ECA to transfer without the
consent or approval of the trust unitholders all or any part of
its interest in the Underlying Properties, subject to the
royalty interests. Notwithstanding the foregoing, the
Administrative and Drilling Services Agreement provides that ECA
may not sell any of the Underlying Properties subject to the PUD
Royalty Interest until it has satisfied its obligation to drill
PUD Wells pursuant to the terms of the Administrative and
Drilling Services Agreement. The trust unitholders are not
entitled to any proceeds of any sale or transfer of ECAs
interest in the Underlying Properties. Following a sale or
transfer, the Underlying Properties will continue to be subject
to the royalty interests, and the proceeds attributable to the
transferred property will be calculated as described in this
prospectus, and paid by the purchaser or transferee to the
trust. As a result, any additional costs resulting from the
transferred property will not reduce the proceeds paid to the
trust from the Underlying Properties retained by ECA.
ECA or any transferee of an Underlying Property will have the
right to abandon any well or property if it reasonably believes
the well or property ceases to produce or is not capable of
producing in commercially paying quantities. In making such
decisions, ECA or any transferee of an Underlying Property is
required under the applicable conveyance to act as a reasonably
prudent operator in the AMI under the same or similar
circumstances would act if it were acting with respect to its
own properties, disregarding the existence of the royalty
interests as burdens affecting such property. Upon termination
of the lease, that portion of the royalty interests relating to
the abandoned property will be extinguished.
80
ECA may, without the consent of the trust unitholders, require
the trust to release royalty interests with an aggregate value
to the trust up to $5.0 million during any
12-month
period. These releases will be made only in connection with a
sale by ECA of the Underlying Properties and are conditioned
upon the trust receiving an amount equal to the fair value to
the trust of such royalty interests.
ECA must maintain books and records sufficient to determine the
amounts payable for the royalty interests to the trust.
Quarterly and annually, ECA must deliver to the trustee a
statement of the computation of the proceeds for each
computation period as well as quarterly drilling and production
results. Following the completion of this offering, ECA will not
be obligated to publicly file any reports with the SEC.
81
DESCRIPTION
OF THE TRUST AGREEMENT
CREATION
AND ORGANIZATION OF THE TRUST; AMENDMENTS
In connection with the formation of the trust, ECA will convey
to a wholly owned subsidiary a term royalty interest entitling
the holder of the interest to receive 45% of the proceeds from
the sale of production of natural gas attributable to ECAs
interest in the Producing Wells (after deducting post-production
costs and any applicable taxes) for a period of 20 years
commencing on April 1, 2010 the Term PDP Royalty and a term
royalty interest entitling such holder of the interest to
receive 25% of the proceeds from the sale of the production of
natural gas attributable to ECAs interest in the PUD Wells
(after deducting post-production costs and any applicable taxes)
for a period of 20 years commencing on April 1, 2010
(the Term PUD Royalty) in exchange for a demand note
in the principal amount of
$ million. The
Term PDP Royalty and the Term PUD Royalty are collectively
referred to as the Term Royalties.
Prior to the closing of this offering, ECA and the Private
Investors will convey to the trust perpetual royalty interests
entitling the trust to receive, in the aggregate, an additional
45% of the proceeds from the sale of production of natural gas
attributable to the interests of ECA in the Producing Wells
(after deducting post-production costs and any applicable taxes)
(the Perpetual PDP Royalty) and ECA will convey to
the trust a perpetual royalty interest entitling the trust to
receive an additional 25% of the proceeds from the sale of
production of natural gas attributable to ECAs interest in
the PUD Wells (after deducting post-production costs and any
applicable taxes) (the Perpetual PUD Royalty) in
exchange for an aggregate 4,500,000 common units constituting
25% of the trust units outstanding and 4,500,000 subordinated
units constituting 25% of the trust units outstanding. The
Perpetual PDP Royalty and the Perpetual PUD Royalty are
collectively referred to as the Perpetual Royalties.
In connection with the completion of this offering, ECAs
subsidiary will convey the Term Royalties to the trust in
exchange for the proceeds of this offering, after deducting
underwriting commissions and discounts and expenses, and will
use such proceeds to repay the demand note to ECA.
The trust was created under Delaware law to acquire and hold the
royalty interests for the benefit of the trust unitholders
pursuant to an agreement between ECA, the trustee and the
Delaware trustee. The royalty interests are passive in nature
and neither the trust nor the trustee has any control over or
responsibility for costs relating to the operation of the
Underlying Properties. Neither ECA nor other operators of the
Underlying Properties have any contractual commitments to the
trust to provide additional funding or to conduct further
drilling on or to maintain their ownership interest in any of
these properties other than the obligations of ECA to designate
and drill PUD Wells. After the conveyance of the royalty
interests, however, ECA will retain an interest in each of the
Underlying Properties. For a description of the Underlying
Properties and other information relating to them, see The
Underlying Properties.
The trust agreement will provide that the trusts business
activities will be limited to owning the royalty interests and
any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyances
related to the royalty interests and the natural gas hedging
contracts relating to an estimated 50% of the trusts
royalty production for a term ending March 31, 2014. As a
result, the trust will not be permitted to acquire other oil and
gas properties or royalty interests.
The beneficial interest in the trust is divided into 18,000,000
trust units. Each of the trust units represents an equal
undivided beneficial interest in the assets of the trust. Please
read Description of the trust units for additional
information concerning the Trust Units.
82
Amendment of the trust agreement requires a vote of holders of a
majority of the outstanding trust units. However, no amendment
may:
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increase the power of the trustee to engage in business or
investment activities;
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alter the rights of the trust unitholders as among
themselves; or
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permit the trustee to distribute the royalty interests in kind.
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Certain amendments to the trust agreement do not require the
vote of the trust unitholders. The trustee may, without approval
of the trust unitholders, from time to time supplement or amend
the trust agreement in order to cure any ambiguity or to correct
or supplement any defective or inconsistent provisions provided
such supplement or amendment is not adverse to the interest of
the trust unitholders. The business and affairs of the trust
will be managed by the trustee. Although ECA will operate all of
the Producing Wells and substantially all of the PUD Wells
during the subordination period, ECA has no ability to manage or
influence the management of the trust.
ASSETS OF
THE TRUST
Upon completion of this offering, the assets of the trust will
consist of royalty interests, natural gas hedging contracts, the
Administrative and Drilling Services Agreement that obligates
ECA to drill the PUD Wells and any cash and temporary
investments being held for the payment of expenses and
liabilities and for distribution to the trust unitholders.
DUTIES
AND POWERS OF THE TRUSTEE
The duties of the trustee are specified in the trust agreement
and by the laws of the State of Delaware, except as modified by
the trust agreement. The trustees principal duties consist
of:
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collecting cash attributable to the royalty interests;
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paying expenses, charges and obligations of the trust from the
trusts assets;
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determining whether cash distributions exceed subordination or
incentive thresholds, and making such cash distributions to the
common and subordinated unitholders accordingly;
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causing to be prepared and distributed a
Schedule K-1
for each trust unitholder and to prepare and file tax returns on
behalf of the trust;
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causing to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934, as amended, and by
the rules of any securities exchange or quotation system on
which the trust units are listed or admitted to trading; and
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taking any action it deems necessary and advisable to best
achieve the purposes of the trust.
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If a trust liability is contingent or uncertain in amount or not
yet currently due and payable, the trustee may create a cash
reserve to pay for the liability. If the trustee determines that
the cash on hand and the cash to be received are insufficient to
cover the trusts liability, the trustee may borrow funds
required to pay the liabilities. The trustee may borrow the
funds from any person, including itself or its affiliates. The
trustee may also mortgage the assets of the trust to secure
payment of the indebtedness. The terms of such indebtedness and
security interest, if funds were
83
loaned by the entity serving as trustee or Delaware trustee,
would be similar to the terms which such entity would grant to a
similarly situated commercial customer with whom it did not have
a fiduciary relationship, and such entity shall be entitled to
enforce its rights with respect to any such indebtedness and
security interest as if it were not then serving as trustee or
Delaware trustee. If the trustee borrows funds, the trust
unitholders will not receive distributions until the borrowed
funds are repaid.
Each quarter, the trustee will pay trust obligations and
expenses and distribute to the trust unitholders the remaining
proceeds received from the royalty interests. The cash held by
the trustee as a reserve against future liabilities or for
distribution at the next distribution date must be invested in:
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interest bearing obligations of the United States government;
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money market funds that invest only in United States government
securities;
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repurchase agreements secured by interest-bearing obligations of
the United States government; or
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bank certificates of deposit.
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The trust may not acquire any asset except the royalty
interests, the natural gas hedging contracts, cash and temporary
cash investments, and it may not engage in any investment
activity except investing cash on hand.
The trust may merge or consolidate with or into one or more
limited partnerships, general partnerships, corporations,
business trusts, limited liability companies, or associations or
unincorporated businesses if such transaction is agreed to by
the trustee and by the affirmative vote of the holders of a
majority of the outstanding trust units and such transaction is
permitted under the Delaware Statutory Trust Act and any
other applicable law.
The trustee may sell the royalty interests under any of the
following circumstances:
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the sale does not involve a material part of the trusts
assets and is in the best interests of the trust
unitholders; or
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the sale constitutes a material part of the trusts assets
and is in the best interests of the trust unitholders, subject
to the holders representing a majority of the outstanding trust
units approving the sale.
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Upon dissolution of the trust the trustee must sell the royalty
interests. No trust unitholder approval is required in this
event.
The trustee will distribute the net proceeds from any sale of
the royalty interests and other assets to the trust unitholders.
The trustee may require any trust unitholder to dispose of his
trust units if an administrative or judicial proceeding seeks to
cancel or forfeit any of the property in which the trust holds
an interest because of the nationality or any other status of
that trust unitholder. If a trust unitholder fails to dispose of
his trust units, the trustee has the right to purchase them and
to borrow funds to make that purchase.
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The trustee may agree to modifications of the terms of the
conveyances or to settle disputes involving the conveyances. The
trustee may not agree to modifications or settle disputes
involving the royalty part of the conveyances if these actions
would change the character of the royalty interests in such a
way that the royalty interests become net revenue interests or
that the trust becomes an operating business.
LIABILITIES
OF THE TRUST
Because the trust does not conduct an active business and the
trustee has little power to incur obligations, it is expected
that the trust will only incur liabilities for routine
administrative expenses, such as the trustees fees and
accounting, engineering, legal, tax advisory and other
professional fees.
FEES AND
EXPENSES
Ongoing administrative expenses.
The trust will be
responsible for paying all legal, accounting, tax advisory,
engineering, printing and other administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of its being a publicly
traded entity, including costs associated with annual and
quarterly reports to unitholders, tax return and
Schedule K-1 preparation and distribution, independent
auditor fees and registrar and transfer agent fees. These trust
administrative expenses as well as the costs associated with
being a publicly traded entity are initially anticipated to
aggregate approximately $800,000 per year, although such costs
could be greater or less depending on future events that cannot
be predicted. Included in the $800,000 annual estimate is an
annual administrative fee of
$
for the trustee and an annual administrative fee of
$
for the Delaware trustee. These costs as well as those to be
paid to ECA pursuant to the Administrative and Drilling Services
Agreement outlined under The Trust
Administrative and Drilling Services
Agreement, will be deducted by the trust before
distributions are made to trust unitholders.
Fees to ECA.
The Administrative and Drilling
Services Agreement provides that the trust is obligated,
throughout the term of the trust, to pay to ECA each quarter an
administrative services fee for accounting, bookkeeping and
informational services relating to the royalty interests. The
annual fee, payable in equal quarterly installments, will total
$60,000 per year.
FIDUCIARY
RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
Under the trust agreement, the trustee is required to act in the
best interests of the trust unitholders at all times. The
trustee must exercise the same judgment and care in supervising
and managing the trusts assets as persons of ordinary
prudence, discretion and intelligence would exercise.
The trustee will not make business decisions affecting the
assets of the trust. Therefore, substantially all of the
trustees functions under the trust agreement are expected
to be ministerial in nature. See Duties and
Powers of the Trustee, above. The trust agreement,
however, provides that the trustee may:
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charge for its services as trustee;
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retain funds to pay for future expenses and deposit them with
one or more banks or financial institutions (which may include
the trustee to the extent permitted by law);
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lend funds at commercial rates to the trust to pay the
trusts expenses; and
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seek reimbursement from the trust for its
out-of-pocket
expenses.
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In discharging its duty to trust unitholders, the trustee may
act in its discretion and will be liable to the trust
unitholders only for fraud, gross negligence or acts or
omissions constituting bad faith. The trustee will not be liable
for any act or omission of its agents or employees unless the
trustee acted in bad faith or with gross negligence in their
selection and retention. The trustee will be indemnified
individually or as the trustee for any liability or cost that it
incurs in the administration of the trust, except in cases of
fraud, gross negligence or bad faith. The trustee will have a
lien on the assets of the trust as security for this
indemnification and its compensation earned as trustee. Trust
unitholders will not be liable to the trustee for any
indemnification. See Description of the Trust
Units Liability of trust unitholders. The
trustee must ensure that all contractual liabilities of the
trust are limited to the assets of the trust and the trustee
will be liable for its failure to do so.
DURATION
OF THE TRUST; SALE OF ROYALTY INTERESTS
The trust will remain in existence until the Termination Date,
which is March 31, 2030. The trust will dissolve prior to
the Termination Date if:
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the trust sells all of the royalty interests;
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gross proceeds attributable to the royalty interests are less
than $1.5 million for any four consecutive quarters;
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the holders of a majority of the outstanding trust units vote in
favor of dissolution; or
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judicial dissolution of the trust.
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The trustee would then sell all of the trusts assets,
either by private sale or public auction, and distribute the net
proceeds of the sale to the trust unitholders.
DISPUTE
RESOLUTION
Any dispute, controversy or claim that may arise between ECA and
the trustee relating to the trust will be submitted to binding
arbitration before a panel of three arbitrators.
COMPENSATION
OF THE TRUSTEE AND THE DELAWARE TRUSTEE
The trustees and the Delaware trustees compensation
will be paid out of the trusts assets. See
Fees and Expenses.
TAX
MATTERS
Trust unitholders will be treated as partners of the trust for
federal income tax purposes. The trust agreement contains tax
provisions that generally allocate the trusts income,
gain, loss, deduction and credit among the trust unitholders in
accordance with their percentage interests in the trust. The
trust agreement also sets forth the tax accounting principles to
be applied by the trust.
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MISCELLANEOUS
The trustee may consult with counsel, accountants, tax advisors,
geologists and engineers and other parties the trustee believes
to be qualified as experts on the matters for which advice is
sought. The trustee will be protected for any action it takes in
good faith reliance upon the opinion of the expert.
The principal offices of the trustee are located at 4643 South
Ulster Street, Suite 1100, Denver, Colorado 80237, and its
telephone number is 303-694-2667.
The Delaware trustee and the trustee may resign at any time or
be removed with or without cause at any time by a vote of not
less than a majority of the outstanding trust units. Any
successor must be a bank or trust company meeting certain
requirements including having combined capital, surplus and
undivided profits of at least $20 million, in the case of
the Delaware trustee, and $100 million, in the case of the
trustee.
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DESCRIPTION
OF THE TRUST UNITS
Each trust unit is a unit of the beneficial interest in the
trust and is entitled to receive cash distributions from the
trust on a pro rata basis. Each trust unitholder has the same
rights regarding each of his trust units as every other trust
unitholder has regarding his units. The trust will have
18,000,000 trust units outstanding upon completion of the
offering, consisting of 13,500,000 common units and
4,500,000 subordinated units.
DISTRIBUTIONS
AND INCOME COMPUTATIONS
Cash distributions to trust unitholders will be made from
available funds at the trust for each calendar quarter.
Production payments due to the trust with respect to any
calendar quarter will be accrued based on estimated production
volumes attributable to the trust properties during such quarter
(as measured at ECA metering systems) and market prices for such
volumes. ECA will make a payment to the trust equal to such
accrued amounts within 30 days of the end of such calendar
quarter. After receipt of such payment, the trustee will
determine for such calendar quarter the amount of funds
available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the trust over
the trusts expenses for that quarter. Available funds will
be reduced by any cash the trustee decides to hold as a reserve
against future liabilities. Any difference between the payment
made by ECA to the trust with respect to a calendar quarter and
the actual cash production payments relative to the trust
properties received by ECA will be netted against future
payments by ECA to the trust. As a result, during the
subordination period, the netting of such difference could
result in (i) an inability by the trust to make cash
distributions in excess of applicable subordination thresholds
with respect to a subsequent calendar quarter or
(ii) distributions in excess of the incentive thresholds
for a prior calendar quarter notwithstanding the fact that such
shortfall or excess, respectively, would not have existed had
production payments owed to the trust been calculated on an
actual cash basis.
The amount of available funds for distribution each quarter will
be payable to the trust unitholders of record on or about the
45th day following the end of such calendar quarter or such
later date as the trustee determines is required to comply with
legal or stock exchange requirements. It is expected that the
trustee will be able to distribute cash on or about the
60th day (or the next succeeding business day following
such day if such day is not a business day) following such
calendar quarter to each person who was a trust unitholder of
record on the quarterly record date, together with interest
expected to be earned on the amount of such quarterly
distribution from the date of receipt thereof by the trustee to
the payment date.
Unless otherwise advised by counsel or the IRS, the trustee will
treat the income and expenses of the trust for each month as
belonging to the trust unitholders of record on the first
business day of the month. Trust unitholders will recognize
income and expenses for tax purposes in the month the trust
receives or pays those amounts, rather than in the month the
trust distributes them. Minor variances may occur. For example,
the trustee could establish a reserve in one month that would
not result in a tax deduction until a later month. The trustee
could also make a payment in one month that would be amortized
for tax purposes over several months. See Federal income
tax considerations.
TRANSFER
OF TRUST UNITS
Trust unitholders may transfer their trust units by sending
their trust unit certificate to the trustee along with a
transfer form that is properly completed. The trustee will not
require either the transferor or transferee to pay a service
charge for any transfer of a trust unit. The trustee may require
payment of any tax or other governmental charge imposed for a
transfer. The trustee may treat the owner of any trust unit as
shown by its records as the owner of the trust unit. The
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trustee will not be considered to know about any claim or demand
on a trust unit by any party except the record owner. A person
who acquires a trust unit after any quarterly record date will
not be entitled to the distribution relating to that quarterly
record date. Delaware law will govern all matters affecting the
title, ownership or transfer of trust units.
PERIODIC
REPORTS
The trustee will file all required trust federal and state
income tax and information returns. The trustee will prepare and
mail to trust unitholders a
Schedule K-1
that trust unitholders need to correctly report their share of
the income and deductions of the trust. The trustee will also
cause to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934, as amended, and by
the rules of any securities exchange or quotation system on
which the trust units are listed or admitted to trading.
Each trust unitholder and his representatives may examine, for
any proper purpose, during reasonable business hours the records
of the trust and the trustee.
LIABILITY
OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of private corporations for profit
under the General Corporation Law of the State of Delaware. No
assurance can be given, however, that the courts in
jurisdictions outside of Delaware will give effect to such
limitation.
VOTING
RIGHTS OF TRUST UNITHOLDERS
The trustee or trust unitholders owning at least 10% of the
outstanding trust units may call meetings of trust unitholders.
The trust will be responsible for all costs associated with
calling a meeting of trust unitholders unless such meeting is
called by the trust unitholders, in which case the trust
unitholders will be responsible for all costs associated with
calling such meeting of trust unitholders. Meetings must be held
in such location as is designated by the trustee in the notice
of such meeting. The trustee must send written notice of the
time and place of the meeting and the matters to be acted upon
to all of the trust unitholders at least 20 days and not
more than 60 days before the meeting. Trust unitholders
representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder
is entitled to one vote for each trust unit owned.
Unless otherwise required by the trust agreement, a matter may
be approved or disapproved by the vote of a majority of the
trust units held by the trust unitholders at a meeting where
there is a quorum. This is true, even if a majority of the total
trust units did not approve it. The affirmative vote of the
holders of a majority of the outstanding trust units is required
to:
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dissolve the trust;
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remove the trustee or the Delaware trustee;
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amend the trust agreement (except with respect to certain
matters that do not adversely affect the right of trust
unitholders in any material respect);
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merge or consolidate the trust with or into another
entity; or
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approve the sale of all or any material part of the assets of
the trust.
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In addition, certain amendments to the trust agreement may be
made by the trustee without approval of the trust unitholders.
The trustee must consent before all or any part of the trust
assets can be sold except in connection with the dissolution of
the trust or limited sales directed by ECA in conjunction with
its sale of Underlying Properties.
COMPARISON
OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of trust unitholders or for
annual or other periodic re-election of the trustee.
Unitholders should also be aware of the following ways in which
an investment in trust units is different from an investment in
common stock of a corporation.
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Trust units
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Common stock
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Voting
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Trust agreement provides voting rights to trust unitholders to
remove and replace trustee (but not elect) and to approve or
disapprove major trust transactions.
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Corporate statutes provide voting rights to stockholders of the
corporation to elect directors and to approve or disapprove
major corporate transactions.
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Income Tax
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The trust is not subject to federal income tax; trust
unitholders are subject to income tax on their allocable share
of trust income, gain, loss and deduction.
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Corporations are taxed on their income, and their stockholders
are taxed on dividends.
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Distributions
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Substantially all trust revenue is distributed to trust
unitholders.
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Stockholders receive dividends at the discretion of the board of
directors.
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Business and Assets
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The business of the trust is limited to specific assets with a
finite economic life.
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A corporation conducts an active business for an unlimited term
and can reinvest its earnings and raise additional capital to
expand.
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Fiduciary Duties
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To the extent provided in the trust agreement, the trustee has a
fiduciary duty to the trust unitholders.
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Officers and directors have a fiduciary duty of loyalty to
stockholders and a duty to use due care in management and
administration of a corporation.
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TRUST UNITS
ELIGIBLE FOR FUTURE SALE
General
Prior to this offering, there has been no public market for the
common units. Sales of substantial amounts of the common units
in the open market, or the perception that those sales could
occur, could adversely affect prevailing market prices.
Upon completion of this offering, there will be 18,000,000 trust
units outstanding. All of the 9,000,000 common units sold in
this offering, or the 10,350,000 common units if the
underwriters exercise their over-allotment option in full, will
be freely tradable without restriction under the Securities Act.
The 1,104,567 common units to be held by the Private
Investors and the 7,895,433 trust units to be held by ECA
(6,545,433 trust units if the underwriters exercise their
over-allotment in full) following completion of the offering
will be restricted securities within the meaning of
Rule 144 under the Securities Act and may not be sold other
than through registration under the Securities Act or pursuant
to an exemption from registration, subject to the restrictions
on transfer contained in the
lock-up
agreements described below and in Underwriting.
Lock-up
Agreements
In connection with this offering, ECA and the Private Investors
have agreed, for a period of 180 days after the date of
this prospectus, not to offer, sell, contract to sell or
otherwise dispose of or transfer any trust units or any
securities convertible into or exchangeable for trust units,
other than the sale of 209,316 common units to ECA by the
Private Investors, without the prior written consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc., subject to specified exceptions. See
Underwriting for a description of these
lock-up
arrangements. Upon the expiration of these
lock-up
agreements, all of the common units held by ECA and the Private
Investors will be eligible for sale in the public market under
Rule 144 of the Securities Act, subject to volume
limitations and other restrictions contained in Rule 144,
or through registration under the Securities Act.
Rule 144
The common units sold in the offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units owned by an
affiliate of ECA or the trust may not be resold
publicly except in compliance with the registration requirements
of the Securities Act or under an exemption under Rule 144
or otherwise. Rule 144 permits securities acquired by an
affiliate to be sold into the market in an amount that does not
exceed, during any three-month period, the greater of:
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1.0% of the total number of the securities outstanding, or
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the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about the trust. A person who is not deemed to have been an
affiliate of ECA or the trust at any time during the three
months preceding a sale, and who has beneficially owned his
common units for at least six months (provided we are in
compliance with the current public information requirement) or
one year (regardless of whether we are in compliance with the
current public information requirement), would be entitled to
sell common units under Rule 144 without regard to the
rules
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public information requirements, volume limitations, manner of
sale provisions and notice requirements.
Registration
Rights
The trust intends to enter into a registration rights agreement
with ECA and the Private Investors in connection with ECAs
conveyance to the trust of the PDP Royalty Interest and the PUD
Royalty Interest. In the registration rights agreement, the
trust will agree, for the benefit of ECA, the Private Investors
and any of their transferees (each, a holder), to
register the trust units it holds. Specifically, the trust will
agree:
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subject to the restrictions described above under
Lock-up
Agreements and under Underwriting
Lock-up
Agreements, to use its reasonable best efforts to file a
registration statement, including, if so requested, a shelf
registration statement, with the SEC as promptly as practicable
following receipt of a notice requesting the filing of a
registration statement from holders representing a majority of
the then outstanding registrable trust units;
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to use its reasonable best efforts to cause the registration
statement or shelf registration statement to be declared
effective under the Securities Act as promptly as practicable
after the filing thereof; and
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to continuously maintain the effectiveness of the registration
statement under the Securities Act for 90 days (or for
three years if a shelf registration statement is requested)
after the effectiveness thereof or until the trust units covered
by the registration statement have been sold pursuant to such
registration statement or until all registrable trust units:
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have been sold pursuant to Rule 144 under the Securities
Act if the transferee thereof does not receive restricted
securities;
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have been sold in a private transaction in which the
transferors rights under the registration rights agreement
are not assigned to the transferee of the trust units; or
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become eligible for resale pursuant to Rule 144 (or any
similar rule then in effect under the Securities Act).
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ECA and the Private Investors will have the right to require the
trust to file no more than three registration statements in
aggregate.
In connection with the preparation and filing of any
registration statement, ECA will bear all costs and expenses
incidental to any registration statement, excluding certain
internal expenses of the trust, which will be borne by the
trustee, and any underwriting discounts and commissions, which
will be borne by the seller of the trust units.
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FEDERAL
INCOME TAX CONSIDERATIONS
This section is a summary of the material tax considerations
that may be relevant to prospective trust unitholders who are
individual citizens or residents of the United States and,
unless otherwise noted in the following discussion, is the
opinion of Vinson & Elkins L.L.P., counsel to ECA and
the trust, insofar as it relates to legal conclusions with
respect to matters of U.S. federal income tax law. This
section is based upon current provisions of the Internal Revenue
Code of 1986, as amended (the Internal Revenue
Code), existing and proposed Treasury regulations
promulgated under the Internal Revenue Code (the Treasury
Regulations) and current administrative rulings and court
decisions, all of which are subject to change. Future changes in
these authorities may cause the tax consequences to vary
substantially from the consequences described below.
The following discussion does not address all federal income tax
matters affecting the trust or the trust unitholders. Moreover,
the discussion focuses on trust unitholders who are individual
citizens or residents of the United States and has only limited
application to corporations, estates, trusts, nonresident aliens
or other unitholders subject to specialized tax treatment, such
as tax-exempt institutions,
non-U.S. persons,
taxpayers subject to the alternative minimum tax, individual
retirement accounts (IRAs), employee benefit plans, real estate
investment trusts (REITs) or mutual funds. Accordingly, the
trust encourages each prospective trust unitholder to consult,
and depend on, his own tax advisor in analyzing the federal,
state, local and foreign tax consequences particular to him of
the ownership or disposition of trust units.
No ruling has been or will be requested from the Internal
Revenue Service (the IRS) regarding any matter
affecting the trust or prospective trust unitholders. Instead,
the trust will rely on opinions of Vinson & Elkins
L.L.P. Unlike a ruling, an opinion of counsel represents only
that counsels best legal judgment and does not bind the
IRS or the courts. Accordingly, the opinions and statements made
herein may not be sustained by a court if contested by the IRS.
Any contest of this sort with the IRS may materially and
adversely impact the market for the trust units and the prices
at which trust units trade. In addition, the costs of any
contest with the IRS, principally legal, accounting and related
fees, will result in a reduction in cash available for
distribution to the trust unitholders, and thus will be borne
indirectly by the trust unitholders. Furthermore, the tax
treatment of the trust, or of an investment in the trust, may be
significantly modified by future legislative or administrative
changes or court decisions. Any modifications may or may not be
retroactively applied.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Vinson & Elkins
L.L.P. and are based on the accuracy of the representations made
by ECA and the trust.
For the reasons described below, Vinson & Elkins
L.L.P. has not rendered an opinion with respect to the following
specific federal income tax issues: (1) the treatment of a
trust unitholder whose trust units are loaned to a short seller
to cover a short sale of trust units (please read
Tax Consequences of Trust Unit
Ownership Treatment of Short Sales);
(2) whether the trusts monthly convention for
allocating taxable income and losses is permitted by existing
Treasury Regulations (please read Disposition
of Trust Units Allocations Between Transferors
and Transferees); and (3) whether percentage
depletion will be available to a trust unitholder or the extent
of the percentage depletion deduction available to any trust
unitholder (please read Tax Consequences of
Trust Unit Ownership Tax Treatment of the
Perpetual Royalties.
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As used herein, the term trust unitholder means a
beneficial owner of trust units that for U.S. federal
income tax purposes is:
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an individual who is a citizen of the United States or who is
resident in the United States for U.S. federal income tax
purposes,
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a corporation, or an entity treated as a corporation for
U.S. federal income tax purposes, created or organized in
or under the laws of the United States, a state thereof or the
District of Columbia,
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an estate the income of which is subject to U.S. federal
income taxation regardless of its source, or
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a trust if it is subject to the primary supervision of a
U.S. court and the control of one or more United States
persons (as defined for U.S. federal income tax purposes)
or that has a valid election in effect under applicable
U.S. Treasury regulations to be treated as a United States
person.
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The term
non-U.S. trust
unitholder means any beneficial owner of a trust unit
(other than an entity that is classified for U.S. federal
income tax purposes as a partnership or as a disregarded
entity) that is not a trust unitholder.
If an entity that is classified for U.S. federal income tax
purposes as a partnership is a beneficial owner of trust units,
the tax treatment of a member of the entity will depend upon the
status of the member and the activities of the entity. Any
entity that is classified for U.S. federal income tax
purposes as a partnership and that is a beneficial owner of
trust units, and the members of such an entity, should consult
their own tax advisors about the U.S. federal income tax
considerations of purchasing, owning, and disposing of trust
units.
CLASSIFICATION
OF THE TRUST AS A PARTNERSHIP
Although the trust is formed as a statutory trust under Delaware
law, the trusts classification for federal income tax
purposes is based on its characteristics rather than its form.
Based on such characteristics, it is expected that, as described
below, the trust will be treated for federal and applicable
state income tax purposes as a partnership and trust unitholders
will be treated as partners in that partnership.
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss, deduction and credit of the partnership in computing
his federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partner unless the amount of cash distributed to him is in
excess of the partners adjusted basis in his partnership
interest as of the end of the taxable year in which the
distribution is made.
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to in this
discussion as the Qualifying Income Exception,
exists with respect to publicly traded partnerships of which 90%
or more of the gross income for every taxable year consists of
qualifying income. Qualifying income includes income
and gains derived from the exploration, development, production
and marketing of crude oil and natural gas and interest income
(other than from a financial business). Other types of
qualifying income include gains from the sale of real property
and income from certain hedging transactions. The trust
anticipates that substantially all of its
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gross income will be qualifying income. Based upon the factual
representations made by the trust and ECA and a review of the
applicable legal authorities, Vinson & Elkins L.L.P.
is of the opinion that at least 90% of the trusts gross
income will constitute qualifying income.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to the trusts status for
federal income tax purposes or whether the trusts
operations generate qualifying income under
Section 7704 of the Internal Revenue Code. Instead, the
trust will rely on the opinion of Vinson & Elkins
L.L.P. on such matters. It is the opinion of Vinson &
Elkins L.L.P. that, based upon the Internal Revenue Code,
Treasury Regulations, published revenue rulings and court
decisions and the representations described below, the trust
will be classified as a partnership for federal income tax
purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has
relied on factual representations made by the trust and ECA. The
representations made by the trust and ECA upon which
Vinson & Elkins L.L.P. has relied are:
(a) The trust has not, and will not, elect to be treated as
a corporation;
(b) The trust is, and will be organized and operated in
accordance with (i) all applicable trust statutes,
including the Delaware Statutory Trust Act, (ii) the
trust agreement, and (iii) the description thereof in this
prospectus;
(c) For each taxable year, more than 90% of the
trusts gross income will be income that Vinson &
Elkins L.L.P. has opined or will opine is qualifying income
within the meaning of Section 7704(d) of the Internal
Revenue Code; and
(d) Each hedging transaction that the trust treats as
resulting in qualifying income will be appropriately identified
as a hedging transaction pursuant to applicable Treasury
Regulations, and will be associated with oil, gas or products
thereof that are held or will be held by the trust in activities
that Vinson & Elkins L.L.P. has opined or will opine
result in qualifying income.
The trust believes that these representations are true and
expects that these representations will continue to be true in
the future.
If the trust fails to meet the Qualifying Income Exception,
other than a failure that is determined by the IRS to be
inadvertent and that is cured within a reasonable time after
discovery (in which case the IRS may also require the trust to
make adjustments with respect to the trusts unitholders
allocable share of trust income, gain, loss or deduction or pay
other amounts), the trust will be treated as if it had
transferred all of its assets, subject to liabilities, to a
newly formed corporation, on the first day of the year in which
the trust fails to meet the Qualifying Income Exception, in
return for stock in that corporation, and then distributed that
stock to the unitholders in liquidation of their interests in
the trust. This deemed contribution and liquidation should be
tax-free to the trust unitholders and the trust. Thereafter, the
trust would be treated as an association taxable as a
corporation for federal income tax purposes.
If the trust were treated as an association taxable as a
corporation in any taxable year, either as a result of a failure
to meet the Qualifying Income Exception or otherwise, the
trusts items of income, gain, loss and deduction would be
reflected only on the trusts tax return rather than being
passed through to the trust unitholders, and the trusts
net income would be taxed to the trust at corporate rates. In
addition, any distribution made to a trust unitholder would be
treated as either taxable dividend income, to the extent of the
trusts current or accumulated earnings and profits, or, in
the absence of earnings and profits, a nontaxable return of
capital, to the extent
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of the trust unitholders tax basis in his trust units, or
taxable capital gain, after the trust unitholders tax
basis in his trust units is reduced to zero. Accordingly,
taxation as a corporation would result in a material reduction
in a trust unitholders cash flow and after-tax return and
thus would likely result in a substantial reduction of the value
of the trust units.
The discussion below is based on Vinson & Elkins
L.L.P.s opinion that the trust will be classified as a
partnership for federal income tax purposes.
PARTNER
STATUS
Trust unitholders will be treated as partners of ECA Marcellus
Trust I for federal income tax purposes. Also, trust
unitholders whose trust units are held in street name or by a
nominee and who have the right to direct the nominee in the
exercise of all substantive rights attendant to the ownership of
their trust units will be treated as partners of ECA Marcellus
Trust I for federal income tax purposes.
A beneficial owner of trust units whose trust units have been
transferred to a short seller to complete a short sale would
appear, as a result, to lose his status as a partner with
respect to those trust units for federal income tax purposes.
Please read Tax Consequences of
Trust Unit Ownership Treatment of Short
Sales. Income, gain, deductions or losses would not appear
to be reportable by a trust unitholder who is not a partner for
federal income tax purposes, and any cash distributions received
by a trust unitholder who is not a partner for federal income
tax purposes would therefore appear to be fully taxable as
ordinary income. These unitholders are urged to consult their
own tax advisors with respect to their tax considerations
related to holding trust units. The references to
unitholders in the discussion that follows are to
persons who are treated as partners in ECA Marcellus
Trust I for federal income tax purposes.
TAX
CLASSIFICATION OF THE PDP ROYALTY INTEREST AND THE PUD ROYALTY
INTEREST
For federal income tax purposes, the PDP Royalty Interest and
the PUD Royalty Interest will have the tax characteristics of
mineral royalty interests to the extent they are, at the time of
their creation, reasonably expected to have an economic life
that corresponds substantially to the economic life of the
mineral property or properties burdened thereby. Payments out of
production that are received in respect of a mineral interest
that constitutes a royalty interest for federal income tax
purposes are taxable under current law as ordinary income
subject to an allowance for cost or percentage depletion in
respect of such income.
In contrast, the PDP Royalty Interest and the PUD Royalty
Interest will have the tax characteristics of production
payments governed by Section 636 of the Internal Revenue
Code to the extent they may not, at the time of their creation,
be reasonably expected to extend in substantial amounts over the
entire productive lives of the mineral property or properties
they burden. Payments out of production that are received in
respect of a mineral interest that constitutes a production
payment for federal income tax purposes are treated under
current law as consisting of a receipt of principal and interest
on a nonrecourse debt obligation, with the interest component
being taxable as ordinary income.
In the event that a portion of a single royalty interest
terminates by its terms prior to the point in time that the
economically productive life of the burdened mineral property is
substantially exhausted and the remaining portion continues to
burden the property until its economically productive life is
substantially exhausted, the federal income tax characteristics
of the royalty interest are determined as if it comprised two
separate interests, with the terminating
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portion being treated as a production payment and the continuing
portion being treated as a royalty interest.
Based on the reserve report and representations made by ECA
regarding the expected economic life of the Underlying
Properties and the expected duration of the Term Royalties and
the Perpetual Royalties, the Term PDP Royalty will and the Term
PUD Royalty should be treated as production payments
under Section 636 of the Internal Revenue Code, and thus as
nonrecourse debt instruments of ECA for U.S. federal income
tax purposes. The Perpetual PDP Royalty will and the Perpetual
PUD Royalty should be treated as continuing, nonoperating
economic interest in the nature of royalties payable out of
production from the mineral interests they burden.
Consistent with this characterization, ECA and the trust intend
to treat the Perpetual Royalties as mineral royalty interests
for federal income tax purposes. In addition, ECA and the trust
intend to treat the Term Royalties as debt instruments for
U.S. federal income tax purposes subject to the Treasury
Regulations applicable to contingent payment debt instruments
(the CPDI regulations), and the trust will agree to
be bound by ECAs application of the CPDI regulations,
including ECAs determination of the rate at which interest
will be deemed to accrue on the such interests. The remainder of
this discussion assumes that the Term Royalties will be treated
in accordance with that agreement and ECAs determinations
and that the Perpetual Royalties will be treated as mineral
royalty interests. No assurance can be given that the IRS will
not assert that such interests should be treated differently.
Such different treatment could affect the amount, timing and
character of income, gain or loss in respect of an investment in
trust units and could require a trust unitholder to accrue
interest income at a rate different than the comparable
yield described below. Please read Tax
Consequences of Trust Unit Ownership Tax
Treatment of the Term Royalties, and Tax
Consequences of Trust Unit Ownership Tax
Treatment of the Perpetual Royalties.
TAX
CONSEQUENCES OF TRUST UNIT OWNERSHIP
Flow-Through
of Taxable Income
As a partnership for federal income tax purposes, the trust will
not be a taxable entity required to pay any federal income tax.
Instead, each trust unitholder will be required to report on his
income tax return his allocable share of the trusts
income, gains, losses, deductions and credits without regard to
whether the trust makes cash distributions to him. Consequently,
the trust may allocate taxable income to a trust unitholder even
if he has not received a cash distribution.
Accounting
Method and Taxable Year
The trust will use the year ending December 31 as its taxable
year and the accrual method of accounting for federal income tax
purposes. Each trust unitholder will be required to include in
income his share of the trusts income, gain, loss,
deduction and credit for the trusts taxable year ending
within or with his taxable year. In addition, a trust unitholder
who has a taxable year ending on a date other than December 31
and who disposes of all of his trust units following the close
of the trusts taxable year but before the close of his
taxable year must include his share of the trusts income,
gain, loss, deduction and credit in his taxable income for his
taxable year, with the result that he will be required to
include in income for his taxable year his share of more than
twelve months of the trusts income, gain, loss, deduction
and credit. Please read Disposition of
Trust Units Allocations Between Transferors and
Transferees.
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Basis
of Trust Units
A trust unitholders initial tax basis for his trust units
will be the amount he paid for the trust units. That basis will
be increased by his share of the trusts income and gain
and decreased, but not below zero, by distributions from the
trust, by the trust unitholders share of the trusts
losses, if any, by depletion deductions taken by him to the
extent such deductions do not exceed his proportionate allocated
share of the adjusted tax basis of the Perpetual Royalties, and
by his share of the trusts expenditures that are not
deductible in computing taxable income and are not required to
be capitalized. Please read Disposition of
Trust Units Recognition of Gain or Loss.
Allocation
of Income, Gain, Loss, Deduction and Credit
In general, if the trust has a net profit, the trusts
items of income, gain, loss, deduction and credit will be
allocated among the trust unitholders in accordance with their
percentage interests in the trust. At any time that
distributions are made to the common units in excess of
distributions to the subordinated trust units, or incentive
distributions are made in respect of the subordinated trust
units, gross income will be allocated to the recipients to the
extent of these distributions. If the trust has a net loss, that
loss will be allocated first to the subordinated trust units to
the extent of their positive capital accounts and thereafter to
the trust unitholders in accordance with their percentage
interests in the trust.
Specified items of the trusts income, gain, loss,
deduction and credit will be allocated under Section 704(c)
of the Internal Revenue Code to account for any difference
between the tax basis and fair market value of any property
treated as having been contributed to the trust by ECA or
certain of its affiliates that exists at the time of such
contribution, together, referred to in this discussion as the
Contributed Property. These
Section 704(c) Allocations are required to
eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and the tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity. The effect of these 704(c) Allocations to a
unitholder purchasing trust units from the trust in this
offering will be essentially the same as if the tax bases of the
trusts assets were equal to their fair market value at the
time of this offering. Finally, although the trust does not
expect that its operations will result in the creation of
negative capital accounts, if negative capital accounts
nevertheless result, items of the trusts income and gain
will be allocated in an amount and manner sufficient to
eliminate the negative balance as quickly as possible.
An allocation of items of the trusts income, gain, loss,
deduction or credit, other than an allocation required by
Section 704(c) of the Internal Revenue Code to eliminate
the Book-Tax Disparity, will generally be given effect for
federal income tax purposes in determining a unitholders
share of an item of income, gain, loss, deduction or credit only
if the allocation has substantial economic effect. In any other
case, a unitholders share of an item will be determined on
the basis of his interest in the trust, which will be determined
by taking into account all the facts and circumstances,
including:
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his relative contributions to the trust;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Vinson & Elkins L.L.P. is of the opinion that, with
the exception of the issues described in Disposition of
Trust Units Allocations Between Transferors and
Transferees, allocations under the trust agreement will be
given effect for federal income tax purposes in determining a
partners share of an item of income, gain, loss, deduction
or credit.
Treatment
of Trust Distributions
Distributions by the trust to a trust unitholder generally will
not be taxable to the trust unitholder for federal income tax
purposes, except to the extent the amount of any such cash
distribution exceeds his tax basis in his trust units
immediately before the distribution. The trusts cash
distributions in excess of a unitholders tax basis (if
any) generally will be considered to be gain from the sale or
exchange of the trust units, taxable in accordance with the
rules described under Disposition of
Trust Units below.
Ratio
of Taxable Income to Distributions
The trust estimates that a purchaser of trust units in this
offering who owns those trust units from the date of closing of
this offering through the record date for distributions for the
period ending December 31, 2012, will be allocated, on a
cumulative basis, an amount of federal taxable income for that
period that will be % or less of
the cash distributed with respect to that period. These
estimates and assumptions are subject to, among other things,
numerous business, economic, regulatory, legislative,
competitive and political uncertainties beyond the trusts
control. Further, the estimates are based on current tax law and
tax reporting positions that the trust will adopt and with which
the IRS could disagree. Accordingly, the trust cannot assure
unitholders that these estimates will prove to be correct. The
actual percentage of distributions that will correspond to
taxable income could be higher or lower than expected, and any
differences could be material and could materially affect the
value of the trust units.
Tax
Treatment of the Term Royalties
Under the CPDI regulations, the trust generally will be required
to accrue income on the Term Royalties which are treated as
production payments, and therefore as nonrecourse debt
obligations of ECA for federal income tax purposes, in the
amounts described below.
The CPDI regulations provide that the trust must accrue an
amount of ordinary interest income for U.S. federal income
tax purposes, for each accrual period prior to and including the
maturity date of the debt instrument that equals:
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the product of (i) the adjusted issue price (as defined
below) of the debt instrument as of the beginning of the accrual
period; and (ii) the comparable yield to maturity (as
defined below) of such debt instrument, adjusted for the length
of the accrual period;
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divided by the number of days in the accrual period; and
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multiplied by the number of days during the accrual period that
the trust held the debt instrument.
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The issue price of the debt instrument represented
by each production payment held by the trust is the portion of
the first price at which a substantial amount of the trust units
is sold to the public, excluding sales to bond houses, brokers
or similar persons or organizations acting in the capacity of
underwriters, placement agents or wholesalers, that is allocable
to the production payment based on the relative fair market
value of the production payment to the other assets of the
trust. The adjusted issue price of such a debt
instrument is its issue price increased by any
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interest income previously accrued, determined without regard to
any adjustments to interest accruals described below, and
decreased by the projected amount of any payments scheduled to
be made with respect to the debt instrument at an earlier time
(without regard to the actual amount paid). The term
comparable yield means the annual yield ECA would be
expected to pay, as of the initial issue date, on a fixed rate
debt security with no contingent payments but with terms and
conditions otherwise comparable to those of the debt instrument
represented by the production payment.
ECA and the trust intend to take the position that the
comparable yield for each debt instrument held by the trust is
an annual rate of 10%, compounded semi-annually. The CPDI
regulations require that ECA provide to the trust, solely for
determining the amount of interest accruals for
U.S. federal income tax purposes, a schedule of the
projected amounts of payments, which are referred to as
projected payments, on the Term Royalties treated as debt
instruments held by the trust. These payments set forth on the
schedule must produce a total return on such debt instruments
equal to their comparable yield. Amounts treated as interest
under the CPDI regulations are treated as original issue
discount for all purposes of the Internal Revenue Code.
As required by the CPDI regulations, for U.S. federal
income tax purposes, the trust must use the comparable yield and
the schedule of projected payments as described above in
determining the trusts interest accruals, and the
adjustments thereto described below, in respect of the debt
instruments held by the trust.
ECAs determinations of the comparable yield and the
projected payment schedule are not binding on the IRS and it
could challenge such determinations. If it did so, and if any
such challenge were successful, then the amount and timing of
interest income accruals of the trust would be different from
those reported by the trust or included on previously filed tax
returns by the trust unitholders.
The comparable yield and the schedule of projected payments are
not determined for any purpose other than for the determination
for U.S. federal income tax purposes of the trusts
interest accruals and adjustments thereof in respect of the debt
instruments held by the trust and do not constitute a projection
or representation regarding the actual amounts payable to the
trust.
For U.S. federal income tax purposes, the trust is required
under the CPDI regulations to use the comparable yield and the
projected payment schedule established by ECA in determining
interest accruals and adjustments in respect of the production
payments, unless the trust timely discloses and justifies the
use of a different comparable yield and projected payment
schedule to the IRS. Pursuant to the terms of the conveyance,
ECA and the trust have agreed (in the absence of an
administrative determination or judicial ruling to the contrary)
to be bound by ECAs determination of the comparable yield
and projected payment schedule.
If, during any taxable year, the trust receives actual payments
with respect to a debt instrument held by the trust that in the
aggregate exceed the total amount of projected payments for that
taxable year, the trust will incur a net positive
adjustment under the CPDI regulations equal to the amount
of such excess. The trust will treat a net positive
adjustment as additional interest income for such taxable
year.
If the trust receives in a taxable year actual payments with
respect to a debt instrument held by the trust that in the
aggregate are less than the amount of projected payments for
that taxable year, the trust will incur a net negative
adjustment under the CPDI regulations equal to the amount
of such deficit. This adjustment will (a) reduce the
trusts interest income on the debt instrument held by the
trust for that taxable year, and (b) to the extent of any
excess after the application of (a) give rise to an
ordinary loss to the extent of the trusts interest income
on such
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debt instrument during prior taxable years, reduced to the
extent such interest was offset by prior net negative
adjustments. Any negative adjustment in excess of the amount
described in (a) and (b) will be carried forward, as a
negative adjustment to offset future interest income in respect
of that debt instrument held by the trust. If either of the Term
Royalties is not treated as a production payment (and hence not
as a debt instrument) for federal income tax purposes, the trust
intends to take the position that its basis in the Term Royalty
is recouped in proportion to the production from the Term
Royalty.
Neither the trust nor the trust unitholders are entitled to
claim depletion deductions with respect to the Term Royalties.
Tax
Treatment of the Perpetual Royalties
The payments received by the trust in respect of the Perpetual
Royalties treated as mineral royalty interests for federal
income tax purposes should be treated as ordinary income. Trust
unitholders should be entitled to deductions for the greater of
either cost depletion or (if otherwise allowable) percentage
depletion with respect to such income. Although the Internal
Revenue Code requires each trust unitholder to compute his own
depletion allowance and maintain records of his share of the
adjusted tax basis of the underlying royalty interest for
depletion and other purposes, the trust intends to furnish each
of the trust unitholders with information relating to this
computation for federal income tax purposes. Each trust
unitholder, however, remains responsible for calculating his own
depletion allowance and maintaining records of his share of the
adjusted tax basis of the Perpetual Royalties for depletion and
other purposes.
Percentage depletion is generally available with respect to
trust unitholders who qualify under the independent producer
exemption contained in Section 613A(c) of the Internal
Revenue Code. For this purpose, an independent producer is a
person not directly or indirectly involved in the retail sale of
oil, natural gas, or derivative products or the operation of a
major refinery. Percentage depletion is calculated as an amount
generally equal to 15% (and, in the case of marginal production,
potentially a higher percentage) of the trust unitholders
gross income from the depletable property for the taxable year.
The percentage depletion deduction with respect to any property
is limited to 100% of the taxable income of the trust unitholder
from the property for each taxable year, computed without the
depletion allowance. A trust unitholder that qualifies as an
independent producer may deduct percentage depletion only to the
extent the trust unitholders average daily production of
domestic crude oil, or the natural gas equivalent, does not
exceed 1,000 barrels. This depletable amount may be
allocated between oil and natural gas production, with 6,000
cubic feet of domestic natural gas production regarded as
equivalent to one barrel of crude oil. The 1,000-barrel
limitation must be allocated among the independent producer and
controlled or related persons and family members in proportion
to the respective production by such persons during the period
in question.
In addition to the foregoing limitations, the percentage
depletion deduction otherwise available is limited to 65% of a
trust unitholders total taxable income from all sources
for the year, computed without the depletion allowance, net
operating loss carrybacks, or capital loss carrybacks. Any
percentage depletion deduction disallowed because of the 65%
limitation may be deducted in the following taxable year if the
percentage depletion deduction for such year plus the deduction
carryover does not exceed 65% of the trust unitholders
total taxable income for that year. The carryover period
resulting from the 65% net income limitation is unlimited.
In addition to the limitations on percentage depletion discussed
above, on February 1, 2010, the White House released
President Obamas budget proposal for the fiscal year 2011
(the 2011 Budget). The 2011 Budget proposes to
eliminate certain tax preferences applicable to taxpayers
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engaged in the exploration or production of natural resources
effective in 2011. Specifically, the 2011 Budget proposes to
repeal the deduction for percentage depletion with respect to
oil and natural gas wells, in which case only cost depletion
would be available. It is uncertain whether this or any other
legislative proposals will ever be enacted and, if so, when it
would become effective.
Trust unitholders that do not qualify under the independent
producer exemption are generally restricted to depletion
deductions based on cost depletion. Cost depletion deductions
are calculated by (i) dividing the trust unitholders
allocated share of the adjusted tax basis in the underlying
mineral property by the number of mineral units (barrels of oil
and thousand cubic feet, or Mcf, of natural gas) remaining as of
the beginning of the taxable year and (ii) multiplying the
result by the number of mineral units sold within the taxable
year. The total amount of deductions based on cost depletion
cannot exceed the trust unitholders share of the total
adjusted tax basis in the property.
The foregoing discussion of depletion deductions does not
purport to be a complete analysis of the complex legislation and
Treasury Regulations relating to the availability and
calculation of depletion deductions by the trust unitholders.
Further, because depletion is required to be computed separately
by each trust unitholder and not by the trust, no assurance can
be given, and counsel is unable to express any opinion, with
respect to the availability or extent of percentage depletion
deductions to the trust unitholders for any taxable year. The
trust encourages each prospective trust unitholder to consult
his tax advisor to determine whether percentage depletion would
be available to him.
Tax
Treatment Upon Sale of the Perpetual Royalties at Termination
Date
The sale of the Perpetual Royalties by the trust at or shortly
after the Termination Date will generally give rise to long-term
capital gain or loss to the trust unitholders for federal income
tax purposes, except that any gain will be taxed at ordinary
income rates to the extent of depletion deductions that reduced
the trust unitholders adjusted basis in the Perpetual
Royalties. Each trust unitholder will be responsible for
calculating his gain or loss based on the difference between his
pro-rata share of the amount realized on the sale by the trust
and his adjusted basis in the Perpetual Royalties, and if a gain
is realized, the portion thereof taxable as ordinary income by
reason of depletion deductions previously claimed by such trust
unitholder. However, the trust intends to furnish each of the
trust unitholders with information relating to this calculation
for federal income tax purposes in connection with the final
partnership tax return for the trust.
Limitations
on Deductibility of Losses
It is not anticipated that the trust will generate losses.
Nevertheless, should losses result, trust unitholders must
consult their own tax advisors as to the applicability to them
of loss limitation rules that could operate to limit the
deductibility to a trust unitholder of his share of the
trusts losses such as the basis limitation, the at
risk rules and the passive loss rules. Special passive
loss limitation rules apply with respect to publicly-traded
partnerships.
Limitations
on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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the trusts interest expense attributed to portfolio
income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a trust unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a trust
unit. Net investment income includes gross income from property
held for investment and amounts treated as portfolio income
under the passive loss rules, less deductible expenses, other
than interest, directly connected with the production of
investment income, but generally does not include gains
attributable to the disposition of property held for investment
or qualified dividend income. The IRS has indicated that the net
passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders for purposes of
the investment interest deduction limitation. In addition, the
trust unitholders share of the trusts portfolio
income will be treated as investment income.
Entity-Level Withholdings
If the trust is required or elects under applicable law to pay
any federal, state, local or foreign income tax on behalf of any
trust unitholder or any former trust unitholder, the trust is
authorized to pay those taxes from its funds. That payment, if
made, will be treated as a distribution of cash to the trust
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, the trust is authorized to treat the payment as a
distribution to all current trust unitholders. The trust is
authorized to amend its trust agreement in the manner necessary
to maintain uniformity of intrinsic tax characteristics of trust
units and to adjust later distributions, so that after giving
effect to these distributions, the priority and characterization
of distributions otherwise applicable under the trust agreement
is maintained as nearly as is practicable. Payments by the trust
as described above could give rise to an overpayment of tax on
behalf of an individual trust unitholder in which event the
trust unitholder would be required to file a claim in order to
obtain a credit or refund.
Treatment
of Short Sales
A trust unitholder whose trust units are loaned to a short
seller to cover a short sale of trust units may be
considered as having disposed of those units. If so, he would no
longer be treated for tax purposes as a partner with respect to
those trust units during the period of the loan and may
recognize gain or loss from the disposition. As a result, during
this period:
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any of the trusts income, gain, loss, deduction or credit
with respect to those trust units would not be reportable by the
trust unitholder;
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any cash distributions received by the trust unitholder as to
those trust units would be fully taxable; and
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all of these distributions would appear to be ordinary income.
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Vinson & Elkins L.L.P. has not rendered an opinion
regarding the tax treatment of a trust unitholder whose trust
units are loaned to a short seller to cover a short sale of
trust units; therefore, trust unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing and loaning their trust units. The IRS has previously
announced that it is studying issues relating to the tax
treatment of short sales of
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partnership interests. Please also read
Disposition of Trust Units
Recognition of Gain or Loss.
Alternative
Minimum Tax
Each trust unitholder will be required to take into account his
distributive share of any items of the trusts income,
gain, loss, deduction or credit for purposes of the alternative
minimum tax. The current minimum tax rate for noncorporate
taxpayers is 26% on the first $175,000 of alternative minimum
taxable income in excess of the exemption amount and 28% on any
additional alternative minimum taxable income. Prospective trust
unitholders are urged to consult with their tax advisors as to
the impact of an investment in trust units on their liability
for the alternative minimum tax.
Tax
Rates
Under current law, the highest marginal U.S. federal income
tax rate applicable to ordinary income of individuals is 35% and
the highest marginal U.S. federal income tax rate
applicable to long-term capital gains (generally, capital gains
on certain assets held for more than 12 months) of
individuals is 15%. However, absent new legislation extending
the current rates, beginning January 1, 2011, the highest
marginal U.S. federal income tax rate applicable to
ordinary income and long-term capital gains of individuals will
increase to 39.6% and 20%, respectively. Moreover, these rates
are subject to change by new legislation at any time.
The recently enacted Health Care and Education Reconciliation
Act of 2010 will impose a 3.8% Medicare tax on certain
investment income earned by individuals for taxable years
beginning after December 31, 2012. For these purposes,
investment income generally includes a trust unitholders
allocable share of the trusts income and gain realized by
a trust unitholder from a sale of trust units. The tax will be
imposed on the lesser of (i) the trust unitholders
net income from all investments, and (ii) the amount by
which the trust unitholders adjusted gross income exceeds
$250,000 (if the trust unitholder is married and filing jointly)
or $200,000 (if the trust unitholder is not married).
Section 754
Election
The trust will make the election permitted by Section 754
of the Internal Revenue Code. That election is irrevocable
without the consent of the IRS. The election will generally
permit the trust to adjust a subsequent trust unit
purchasers tax basis in the trusts assets
(inside basis) under Section 743(b) of the
Internal Revenue Code to reflect his purchase price of trust
units acquired from another trust unitholder. The
Section 743(b) adjustment belongs to the purchaser and not
to other trust unitholders. For purposes of this discussion, a
trust unitholders inside basis in the trusts assets
will be considered to have two components: (1) his share of
tax basis in the trusts assets (common basis)
and (2) his Section 743(b) adjustment to that basis.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of the trusts
assets immediately prior to the transfer. In such a case, as a
result of the election, the transferee would have a higher tax
basis in his share of the trusts assets for purposes of
calculating, among other items, cost depletion deductions on the
Perpetual Royalties, and his share of any gain on a sale of the
trusts assets would be less. Conversely, a
Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
trust units share of the aggregate tax basis of the
trusts assets immediately prior to the transfer. Thus, the
fair market value of the trust units may be affected either
favorably or unfavorably by the election. A basis adjustment is
required regardless of whether a Section 754 election is
made in the case of a transfer of an interest in the trust if it
has a substantial built in
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loss immediately after the transfer. Generally a
built in loss or a basis reduction is substantial if
it exceeds $250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of the trusts assets and other matters. For example,
the allocation of the Section 743(b) adjustment among the
trusts assets must be made in accordance with the Internal
Revenue Code. The trust cannot assure unitholders that the
determinations it makes will not be successfully challenged by
the IRS and that the deductions resulting from them will not be
reduced or disallowed altogether. Should the IRS require a
different basis adjustment to be made, and should, in the
trusts opinion, the expense of compliance exceed the
benefit of the election, the trust may seek permission from the
IRS to revoke its Section 754 election. If permission is
granted, a subsequent purchaser of trust units may be allocated
more income than he would have been allocated had the election
not been revoked.
Initial
Tax Basis and Amortization
The initial tax basis of the portion of the PDP Royalty Interest
treated as a royalty interest in minerals and the portion
treated as a production payment, and the initial basis of the
portion of the PUD Royalty Interest treated as a royalty
interest in minerals and the portion treated as a production
payment will be effectively equal on a
per-unit
basis to the portion of the unit price allocated to each based
on each such portions relative fair market value.
The costs incurred in selling the trust units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon the trusts
termination. There are uncertainties regarding the
classification of costs as organization expenses, which may be
amortized by the trust, and as syndication expenses, which may
not be amortized by the trust. The underwriting discounts and
commissions the trust incurs will be treated as syndication
expenses.
Valuation
and Tax Basis of the Trusts Properties
The federal income tax consequences of the ownership and
disposition of trust units will depend in part on the
trusts estimates of the relative fair market values, and
the initial tax bases, of the trusts assets. Although the
trust may from time to time consult with professional appraisers
regarding valuation matters, the trust will make many of the
relative fair market value estimates itself. These estimates and
determinations of basis are subject to challenge and will not be
binding on the IRS or the courts. If the estimates of fair
market value or basis are later found to be incorrect, the
character and amount of items of income, gain, loss or
deductions previously reported by trust unitholders might
change, and trust unitholders might be required to adjust their
tax liability for prior years and incur interest and penalties
with respect to those adjustments.
DISPOSITION
OF TRUST UNITS
Recognition
of Gain or Loss
Gain or loss will be recognized on a sale of trust units equal
to the difference between the amount realized and the trust
unitholders tax basis for the trust units sold. A trust
unitholders amount realized will be measured by the sum of
the cash or the fair market value of other property received.
The amount realized should be reduced by the unused net negative
adjustments attributable to the trust units disposed of as
described above under Tax Consequences of
Trust Unit Ownership Tax Treatment of the Term
Royalties. A trust unitholders adjusted tax basis in
his trust units will be equal to the trust unitholders
original
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purchase price for the trust units, increased by income and
decreased by losses or deductions previously allocated to the
trust unitholder and by distributions to the trust unitholder
and depletion deductions claimed by the trust unitholder.
Prior distributions from the trust in excess of cumulative net
taxable income for a trust unit that decreased a
unitholders tax basis in that trust unit will, in effect,
become taxable income if the trust unit is sold at a price
greater than the trust unitholders tax basis in that trust
unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a trust
unitholder, other than a dealer in trust units, on
the sale or exchange of a trust unit will generally be taxable
as capital gain or loss. Capital gain recognized by an
individual on the sale of trust units held for more than twelve
months will generally be taxed at a maximum U.S. federal
income tax rate of 15% through December 31, 2010 and 20%
thereafter (absent new legislation extending or adjusting the
current rate). However, a portion, which will likely be
substantial, of this gain or loss will be separately computed
and taxed as ordinary income or loss under Section 751 of
the Internal Revenue Code to the extent attributable to assets
giving rise to unrealized receivables the trust
owns. The term unrealized receivables includes
potential recapture items, including depletion recapture.
Ordinary income attributable to unrealized receivables such as
depletion recapture may exceed net taxable gain realized upon
the sale of a trust unit and may be recognized even if there is
a net taxable loss realized on the sale of a trust unit. Thus, a
trust unitholder may recognize both ordinary income and a
capital loss upon a sale of trust units. Net capital losses may
offset capital gains and no more than $3,000 of ordinary income,
in the case of individuals, and may only be used to offset
capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling trust unitholder who can
identify trust units transferred with an ascertainable holding
period to elect to use the actual holding period of the trust
units transferred. Thus, according to the ruling discussed
above, a trust unitholder will be unable to select high or low
basis trust units to sell as would be the case with corporate
stock, but, according to the Treasury Regulations, he may
designate specific trust units sold for purposes of determining
the holding period of trust units transferred. A trust
unitholder electing to use the actual holding period of trust
units transferred must consistently use that identification
method for all subsequent sales or exchanges of trust units. A
trust unitholder considering the purchase of additional trust
units or a sale of trust units purchased in separate
transactions is urged to consult his tax advisor as to the
possible consequences of this ruling and application of the
Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract with respect to the partnership
interest or substantially identical property.
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Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
Between Transferors and Transferees
In general, the trusts taxable income and losses will be
determined annually, will be prorated on a monthly basis and
will be subsequently apportioned among the trust unitholders in
proportion to the number of trust units owned by each of them as
of the opening of the applicable exchange on which the trust
units are then traded on the first business day of the month,
which is referred to in this prospectus as the Allocation
Date. However, gain or loss realized on a sale or other
disposition of the trusts assets other than in the
ordinary course of business will be allocated among the trust
unitholders on the Allocation Date in the month in which that
gain or loss is recognized. As a result, a trust unitholder
transferring trust units may be allocated income, gain, loss and
deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code, and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Recently,
however, the Department of the Treasury and the IRS issued
proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Existing publicly
traded partnerships are entitled to rely on these proposed
Treasury Regulations; however, they are not binding on the IRS
and are subject to change until final Treasury Regulations are
issued. Accordingly, Vinson & Elkins L.L.P. is unable
to opine on the validity of this method of allocating income and
deductions between transferor and transferee trust unitholders.
If this method is not allowed under the Treasury Regulations, or
only applies to transfers of less than all of the trust
unitholders interest, the trusts taxable income or
losses might be reallocated among the trust unitholders. The
trust is authorized to revise its method of allocation between
transferor and transferee trust unitholders, as well as trust
unitholders whose interests vary during a taxable year, to
conform to a method permitted under future Treasury Regulations.
A trust unitholder who owns trust units at any time during a
quarter and who disposes of them prior to the record date set
for a cash distribution for that quarter will be allocated items
of the trusts income, gain, loss and deductions
attributable to that quarter but will not be entitled to receive
that cash distribution.
Notification
Requirements
A trust unitholder who sells any of his trust units is generally
required to notify the trust in writing of that sale within
30 days after the sale (or, if earlier, January 15 of the
year following the sale). A purchaser of trust units who
purchases trust units from another trust unitholder is also
generally required to notify the trust in writing of that
purchase within 30 days after the purchase. Upon receiving
such notifications, the trust is required to notify the IRS of
that transaction and to furnish specified information to the
transferor and transferee. Failure to notify
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the trust of a purchase may, in some cases, lead to the
imposition of penalties. However, these reporting requirements
do not apply to a sale by an individual who is a citizen of the
United States and who affects the sale or exchange through a
broker who will satisfy such requirements.
Constructive
Termination
The trust will be considered to have been terminated for tax
purposes if there are sales or exchanges which, in the
aggregate, constitute 50% or more of the total interests in the
trusts capital and profits within a twelve-month period.
For purposes of measuring whether the 50% threshold is reached,
multiple sales of the same interest are counted only once. A
constructive termination results in the closing of the
trusts taxable year for all trust unitholders. In the case
of a trust unitholder reporting on a taxable year other than a
calendar year, the closing of the trusts taxable year may
result in more than twelve months of the trusts taxable
income or loss being includable in his taxable income for the
year of termination. A constructive termination occurring on a
date other than December 31 will result in the trust filing two
tax returns (and trust unitholders may receive two
Schedule K-1s)
for one fiscal year and the cost of the preparation of these
returns will be borne by all trust unitholders. The trust would
be required to make new tax elections after a termination,
including a new election under Section 754 of the Internal
Revenue Code. A termination could also result in penalties if
the trust was unable to determine that the termination had
occurred. Moreover, a termination might either accelerate the
application of, or subject the trust to, any tax legislation
enacted before the termination.
TAX
EXEMPT ORGANIZATIONS AND OTHER INVESTORS
Ownership of trust units by employee benefit plans, other
tax-exempt organizations, non-resident aliens,
non-U.S. corporations
and other
non-U.S. persons
raises issues unique to those investors and, as described below,
may have substantially adverse tax consequences to them. If a
potential investor is a tax-exempt entity or a
non-U.S. person,
then it should consult a tax advisor before investing in the
trust units.
Tax
Exempt Organizations
Employee benefit plans and most other organizations exempt from
federal income tax including IRAs and other retirement plans are
subject to federal income tax on unrelated business taxable
income. Because all of the income of the trust is expected to be
royalty income, interest income, hedging income and gain from
the sale of real property, none of which is unrelated business
taxable income, any such organization exempt from federal income
tax is not expected to be taxable on income generated by
ownership of trust units so long as neither the property held by
the trust nor the trust units are debt-financed property within
the meaning of Section 514(b) of the Internal Revenue Code.
In general, trust property would be debt-financed if the trust
incurs debt to acquire the property or otherwise incurs or
maintains a debt that would not have been incurred or maintained
if the property had not been acquired and a trust unit would be
debt-financed if the trust unitholder incurs debt to acquire the
trust unit or otherwise incurs or maintains a debt that would
not have been incurred or maintained if the trust unit had not
been acquired.
Non-U.S.
Persons
The trust will be required to withhold (at a 30% rate or lower
applicable treaty rate) on interest and royalty income allocable
to
non-U.S. trust
unitholders.
Moreover, each of the PDP and PUD Royalty Interests will be
treated as a United States real property interest
for U.S. federal income tax purposes. However, as long as
the trust units are
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regularly traded on an established securities market, gain
realized by a
non-U.S. trust
unitholder on a sale of trust units will be subject to federal
income tax only if:
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the gain is, or is treated as, effectively connected with
business conducted by the
non-U.S. trust
unitholder in the United States, and in the case of an
applicable tax treaty, is attributable to a U.S. permanent
establishment maintained by the
non-U.S. trust
unitholder;
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the
non-U.S. trust
unitholder is an individual who is present in the United States
for at least 183 days in the year of the sale and certain
other conditions are met; or
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the
non-U.S. trust
unitholder owns currently, or owned at certain earlier times,
directly or by applying certain attribution rules, more than 5%
of the trust units.
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ADMINISTRATIVE
MATTERS
Trust Information
Returns and Audit Procedures
The trust intends to furnish to each trust unitholder, within
90 days after the close of each calendar year, specific tax
information, including a
Schedule K-1,
which describes his share of the trusts income, gain, loss
and deduction for the trusts preceding taxable year. In
preparing this information, which will not be reviewed by
counsel, the trust will take various accounting and reporting
positions, some of which have been mentioned earlier, to
determine each trust unitholders share of income, gain,
loss and deduction. The trust cannot assure unitholders that
those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither the trust
nor Vinson & Elkins L.L.P. can assure prospective
trust unitholders that the IRS will not successfully contend in
court that those positions are impermissible. Any challenge by
the IRS could negatively affect the value of the units.
The IRS may audit the trusts federal income tax
information returns. Adjustments resulting from an IRS audit may
require each trust unitholder to adjust a prior years tax
liability, and possibly may result in an audit of his return.
Any audit of a trust unitholders return could result in
adjustments not related to the trusts returns as well as
those related to the trusts returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. The trust agreement names ECA as the trusts Tax
Matters Partner.
The Tax Matters Partner has made and will make some elections on
behalf of the trust and the trust unitholders. In addition, the
Tax Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against trust unitholders for
items in the trusts returns. The Tax Matters Partner may
bind a trust unitholder with less than a 1% profits interest in
the trust to a settlement with the IRS unless that trust
unitholder elects, by filing a statement with the IRS, not to
give that authority to the Tax Matters Partner. The Tax Matters
Partner may seek judicial review, by which all the trust
unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any trust
unitholder having at least a 1% interest in profits or by any
group of trust unitholders having in the aggregate at least a 5%
interest in profits. However, only one action for
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judicial review will go forward, and each trust unitholder with
an interest in the outcome may participate.
A trust unitholder must file a statement with the IRS
identifying the treatment of any item on his federal income tax
return that is not consistent with the treatment of the item on
the trusts return. Intentional or negligent disregard of
this consistency requirement may subject a trust unitholder to
substantial penalties.
Nominee
Reporting
Persons who hold an interest in the trust as a nominee for
another person are required to furnish to the trust:
(a) the name, address and taxpayer identification number of
the beneficial owner and the nominee;
(b) whether the beneficial owner is:
1. a person that is not a United States person;
2. a
non-U.S. government,
an international organization or any wholly owned agency or
instrumentality of either of the foregoing; or
3. a tax-exempt entity;
(c) the amount and description of units held, acquired or
transferred for the beneficial owner; and
(d) specific information including the dates of
acquisitions and transfers, means of acquisitions and transfers
and acquisition cost for purchases, as well as the amount of net
proceeds from sales.
Brokers and financial institutions are required to furnish
additional information, including whether they are United States
persons and specific information on units they acquire, hold or
transfer for their own account. A penalty of $50 per failure, up
to a maximum of $100,000 per calendar year, is imposed by the
Internal Revenue Code for failure to report that information to
the trust. The nominee is required to supply the beneficial
owner of the trust units with the information furnished to the
trust.
Accuracy-Related
Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000. The amount of any
understatement subject to penalty generally is reduced if any
portion is attributable to a position adopted on the return:
(1) for which there is, or was, substantial
authority; or
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(2) as to which there is a reasonable basis and the
pertinent facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the
distributive shares of trust unitholders might result in that
kind of an understatement of income for which no
substantial authority exists, the trust must
disclose the pertinent facts on its return. In addition, the
trust will make a reasonable effort to furnish sufficient
information for trust unitholders to make adequate disclosure on
their returns and to take other actions as may be appropriate to
permit trust unitholders to avoid liability for this penalty.
More stringent rules apply to tax shelters, which
the trust does not believe includes it, or any of the
trusts investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the tax basis of any property, claimed
on a tax return is 150% or more of the amount determined to be
the correct amount of the valuation or tax basis, (b) the
price for any property or services (or for the use of property)
claimed on any such return with respect to any transaction
between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts.
No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). The penalty is increased
to 40% in the event of a gross valuation misstatement. The trust
does not anticipate making any valuation misstatements.
Reportable
Transactions
If the trust were to engage in a reportable
transaction, the trust (and possibly the unitholders)
would be required to make a detailed disclosure of the
transaction to the IRS. A transaction may be a reportable
transaction based upon any of several factors, including the
fact that it is a type of tax avoidance transaction publicly
identified by the IRS as a listed transaction or
that it produces certain kinds of losses for partnerships,
individuals, S corporations, and trusts in excess of
$2 million in any single year, or $4 million in any
combination of 6 successive tax years. The trusts
participation in a reportable transaction could increase the
likelihood that the trusts federal income tax information
return (and possibly the unitholders tax return) would be
audited by the IRS. Please read
Trust Information Returns and Audit
Procedures.
Moreover, if the trust were to participate in a reportable
transaction with a significant purpose to avoid or evade tax, or
in any listed transaction, unitholders may be subject to the
following provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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The trust does not expect to engage in any reportable
transactions.
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STATE TAX
CONSIDERATIONS
The following is intended as a brief summary of certain
information regarding state income taxes and other state tax
matters affecting individuals who are trust unitholders. Trust
unitholders are urged to consult their own legal and tax
advisors with respect to these matters.
Prospective investors should consider state and local tax
consequences of an investment in the common units. The trust
will own the royalty interests burdening specified gas
properties located in Greene County, Pennsylvania. The state of
Pennsylvania has income taxes applicable to individuals, but
currently does not require the trust to withhold taxes from
distributions made to nonresident unitholders. If withholding
were required under current Pennsylvanian law, the rate would be
3.07% of taxable income attributable to Pennsylvania. A trust
unitholder may be required to file state income tax returns
and/or
pay
taxes in Pennsylvania and may be subject to penalties for
failure to comply with such requirements. Taxes withheld by the
trust would be treated as deductions against state income taxes
otherwise payable.
The trust units may constitute real property or an interest in
real property under the inheritance, estate and probate laws of
Pennsylvania.
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ERISA
CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended,
regulates pension, profit-sharing and other employee benefit
plans to which it applies. ERISA also contains standards for
persons who are fiduciaries of those plans. In addition, the
Internal Revenue Code provides similar requirements and
standards which are applicable to qualified plans, which include
these types of plans, and to individual retirement accounts,
whether or not subject to ERISA.
A fiduciary of a qualified plan should carefully consider
fiduciary standards under ERISA regarding the qualified
plans particular circumstances before authorizing an
investment in trust units. A fiduciary should consider:
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whether the investment satisfies the prudence requirements of
Section 404(a)(1)(B) of ERISA;
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whether the investment satisfies the diversification
requirements of Section 404(a)(1)(C) of ERISA; and
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whether the investment is in accordance with the documents and
instruments governing the qualified plan as required by
Section 404(a)(1)(D) of ERISA.
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A fiduciary should also consider whether an investment in common
units might result in direct or indirect nonexempt prohibited
transactions under Section 406 of ERISA and Internal
Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must
determine whether there are plan assets in the transaction. The
Department of Labor has published final regulations concerning
whether or not a qualified plans assets would be deemed to
include an interest in the underlying assets of an entity for
purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of
the Internal Revenue Code. These regulations provide that the
underlying assets of an entity will not be considered plan
assets if the equity interests in the entity are a
publicly offered security. ECA expects that at the time of the
sale of the trust units in this offering, they will be publicly
offered securities. Fiduciaries, however, will need to determine
whether the acquisition of trust units is a nonexempt prohibited
transaction under the general requirements of ERISA
Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons
involved in prohibited transactions are subject to penalties.
For that reason, potential qualified plan investors should
consult with their counsel to determine the consequences under
ERISA and the Internal Revenue Code of their acquisition and
ownership of trust units.
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SELLING
TRUST UNITHOLDER
Prior to the closing of the offering made hereby, ECA will
convey the royalty interests to the trust in exchange for cash,
3,186,117 common units and 4,500,000 subordinated units.
Additionally, at the closing of this offering, ECA will purchase
from the Private Investors a total of 209,316 common units at
the initial offering price. If the underwriters exercise the
option to purchase an additional 1,350,000 common units at the
initial public offering price, then ECA will offer 1,350,000 of
its common units to cover the over-allotment option of those
common units. ECA and the Private Investors have agreed,
however, not to sell any trust units for period of 180 days
after the date of this prospectus without the prior written
consent of Raymond James & Associates, Inc. and
Citigroup Global Markets Inc. acting as representatives of the
several underwriters, subject to specified exceptions and other
than the sale of common units to ECA by the Private Investors.
See Underwriting.
The following table provides information regarding the selling
trust unitholders ownership of the trust units. This table
assumes the underwriters over-allotment option is
exercised.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership of Trust Units
|
|
|
Ownership of
|
|
|
|
After Offering (Assuming
|
|
|
Trust Units
|
|
|
|
Full Exercise
|
|
|
Before Exercise
|
|
Number of
|
|
of Underwriters
|
|
|
of Underwriters Over-Allotment Option
|
|
Common Units
|
|
Over-Allotment)
|
Selling Trust Unitholder
|
|
Number
|
|
Percentage
|
|
Being Offered
|
|
Number
|
|
Percentage
|
|
Energy Corporation of America
|
|
|
7,895,433
|
|
|
|
43.9%
|
|
|
|
1,350,000
|
|
|
|
6,545,433
|
|
|
|
36.4%
|
|
Prior to this offering there has been no public market for the
common units. Therefore, if ECA disposes of its remaining trust
units, it cannot predict the effect of such disposal on future
market prices, if any, of market sales of such remaining trust
units or the availability of trust units for sale. Nevertheless,
sales of substantial amounts of trust units in the public market
could adversely affect future market prices.
114
UNDERWRITING
Subject to the terms and conditions in an underwriting agreement
dated ,
2010, the underwriters named below, for whom Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc. are acting as representatives, have severally agreed to
purchase from ECA the common of trust units set forth opposite
their names:
|
|
|
|
|
|
|
Number of
|
|
Name of Underwriter
|
|
Common Units
|
|
|
Raymond James & Associates, Inc.
|
|
|
|
|
Citigroup Global Markets Inc.
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
9,000,000
|
|
|
|
|
|
|
The underwriting agreement provides that the obligations of the
underwriters to purchase and accept delivery of the common units
offered by this prospectus are subject to the satisfaction of
the conditions contained in the underwriting agreement,
including:
|
|
|
|
|
the representations and warranties made by ECA to the
underwriters are true;
|
|
|
|
there is no material adverse change in the financial
market; and
|
|
|
|
ECA delivers customary closing documents and legal opinions to
the underwriters.
|
The underwriters are obligated to purchase and accept delivery
of all of the trust units offered by this prospectus, if any of
the units are purchased, other than those covered by the option
to purchase additional common units described below.
The underwriters propose to offer the common units directly to
the public at the public offering price indicated on the cover
page of this prospectus and to various dealers at that price
less a concession not in excess of
$ per unit. If all of the common
units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The common units are offered by the underwriters
as stated in this prospectus, subject to receipt and acceptance
by them. The underwriters reserve the right to reject an order
for the purchase of the common units in whole or in part.
OPTION TO
PURCHASE ADDITIONAL COMMON UNITS
The trust has granted the underwriters an option, exercisable
for 30 days after the date of this prospectus, to purchase
from time to time up to an aggregate of
1,350,000 additional common units to cover over-allotments,
if any, at the public offering price less the underwriting
discounts and commissions set forth on the cover page of this
prospectus. The net proceeds of any exercise of the
underwriters over-allotment option will be used to redeem
an equal number of common units held by ECA. If the underwriters
exercise this option, each underwriter, subject to certain
conditions, will become obligated to purchase its pro rata
portion of these additional units based on the
underwriters percentage purchase commitment in this
offering as indicated in the table above. The underwriters may
exercise the option to purchase additional common units only to
cover over-allotments made in connection with the sale of the
common units offered in this offering.
115
DISCOUNTS
AND EXPENSES
The following table shows the amount per unit and total
underwriting discounts ECA will pay to the underwriters (dollars
in thousands, except per unit). The amounts are shown assuming
both no exercise and full exercise of the underwriters
option to purchase additional common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total without
|
|
|
Total with
|
|
|
|
|
|
|
Over-Allotment
|
|
|
Over-Allotment
|
|
|
|
Per Unit
|
|
|
Exercise
|
|
|
Exercise
|
|
|
Price to the public
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Underwriting discount and commissions
|
|
$
|
|
|
|
|
|
|
|
|
|
|
Proceeds, to the trust (before expenses)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
The other expenses of this offering that are payable by the
trust are estimated to be
$ million (exclusive of
underwriting discounts and commissions). In no event will the
maximum amount of compensation to be paid to members of the
Financial Industry Regulatory Authority, or the
FINRA, in connection with this offering exceed 10%
plus 0.5% for bona fide due diligence expenses.
INDEMNIFICATION
ECA has agreed to indemnify the underwriters and persons who
control the underwriters against certain liabilities that may
arise in connection with this offering, including liabilities
under the Securities Act of 1933 and liabilities arising from
breaches of representations and warranties contained in the
underwriting agreement.
LOCK-UP
AGREEMENTS
Subject to specified exceptions, including the sale of 209,316
common units to ECA by the Private Investors at the closing of
this offering, ECA and the Private Investors have agreed with
the underwriters, for a period of 180 days after the date
of this prospectus, without the prior written consent of Raymond
James & Associates, Inc. and Citigroup Global Markets
Inc.:
|
|
|
|
|
not to offer, sell, contract to sell, announce the intention to
sell or pledge any of the trust units;
|
|
|
|
not to grant or sell any option or contract to purchase any of
the trust units;
|
|
|
|
not to enter into any swap or other agreement that transfers any
of the economic consequences of ownership of or otherwise
transfer or dispose of, directly or indirectly, any of the trust
units; and
|
|
|
|
not to enter into any hedging, collar or other transaction or
arrangement that is designed or reasonably expected to lead to
or result in a transfer, in whole or in part, of any of the
economic consequences of ownership of the trust units, whether
or not such transfer would be for any consideration.
|
These agreements also prohibit ECA and the Private Investors
from entering into any of the foregoing transactions with
respect to any securities that are convertible into or
exchangeable for the trust units.
116
Raymond James & Associates, Inc. and Citigroup Global
Markets Inc. may, in their discretion and at any time without
notice, release all or any portion of the securities subject to
these agreements. Raymond James & Associates, Inc. and
Citigroup Global Markets Inc. do not have any present intent or
any understanding to release all or any portion of the
securities subject to these agreements.
The
180-day
period described in the preceding paragraphs will be extended if:
|
|
|
|
|
during the last 17 days of the
180-day
period, the trust issues a release concerning distributable cash
or announces material news or a material event relating to the
trust occurs; or
|
|
|
|
prior to the expiration of the
180-day
period, the trust announces that it will release distributable
cash results during the
16-day
period beginning on the last day of the
180-day
period, in which case the restrictions described in the
preceding paragraphs will continue to apply until the expiration
of the
18-day
period beginning on the issuance of the earnings release, the
announcement of the material news or the occurrence of the
material event.
|
STABILIZATION
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters and various selling group members to
bid for and purchase the common units. As an exception to these
rules, the underwriters may engage in activities that stabilize,
maintain or otherwise affect the price of the common units,
including:
|
|
|
|
|
short sales,
|
|
|
|
syndicate covering transactions,
|
|
|
|
imposition of penalty bids, and
|
|
|
|
purchases to cover positions created by short sales.
|
Stabilizing transactions consist of bids or purchases made for
the purpose of preventing or retarding a decline in the market
price of the common units while this offering is in progress.
Stabilizing transactions may include making short sales of
common units, which involve the sale by the underwriters of a
greater number of common units than it is required to purchase
in this offering and purchasing common units from ECA or in the
open market to cover positions created by short sales. Short
sales may be covered shorts, which are short
positions in an amount not greater than the underwriters
option to purchase additional common units referred to above, or
may be naked shorts, which are short positions in
excess of that amount.
Each underwriter may close out any covered short position either
by exercising its option to purchase additional common units, in
whole or in part, or by purchasing common units in the open
market. In making this determination, each underwriter will
consider, among other things, the price of common units
available for purchase in the open market compared to the price
at which the underwriter may purchase common units pursuant to
the option to purchase additional common units.
A naked short position is more likely to be created if the
underwriters are concerned that there may be downward pressure
on the price of the common units in the open market that could
adversely affect investors who purchased in this offering. To
the extent that the underwriters
117
create a naked short position, they will purchase common units
in the open market to cover the position.
The underwriters also may impose a penalty bid on selling group
members. This means that if the underwriters purchase common
units in the open market in stabilizing transactions or to cover
short sales, the underwriters can require the selling group
members that sold those common units as part of this offering to
repay the selling concession received by them.
As a result of these activities, the price of the common units
may be higher than the price that otherwise might exist in the
open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The
underwriters may carry out these transactions on the New York
Stock Exchange or otherwise.
CONFLICTS/AFFILIATES
Certain of the underwriters and their affiliates may provide in
the future investment banking, financial advisory or other
financial services for ECA and its affiliates, for which they
may receive advisory or transaction fees, as applicable, plus
out-of-pocket expenses, of the nature and in amounts customary
in the industry for these financial services.
DISCRETIONARY
ACCOUNTS
The underwriters may confirm sales of the common units offered
by this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total common units offered by this prospectus.
LISTING
The common units have been approved for listing on the New York
Stock Exchange under the symbol ECT, subject to
official notice of issuance. In connection with the listing of
the common units on the New York Stock Exchange, the
underwriters will undertake to sell round lots of 100 units
or more to a minimum of 400 beneficial owners.
DETERMINATION
OF INITIAL OFFERING PRICE
Prior to this offering, there has been no public market for the
common units. Consequently, the initial public offering price
for the common units will be determined by negotiations among
ECA and the underwriters. The primary factors to be considered
in determining the initial public offering price will be:
|
|
|
|
|
estimates of distributions to trust unitholders,
|
|
|
|
overall quality of the natural gas properties attributable to
the Underlying Properties,
|
|
|
|
industry and market conditions prevalent in the energy industry,
|
|
|
|
the information set forth in this prospectus and otherwise
available to the representatives, and
|
|
|
|
the general conditions of the securities markets at the time of
this offering.
|
118
The initial offering price may not correspond to the price at
which the common units will trade in the public market
subsequent to this offering, and an active trading market may
develop and continue after this offering.
ELECTRONIC
PROSPECTUS
A prospectus in electronic format may be available on the
Internet sites or through other online services maintained by
one or more of the underwriters and selling group members
participating in this offering, or by their affiliates. In those
cases, prospective investors may view offering terms online and,
depending upon the underwriter or the selling group member,
prospective investors may be allowed to place orders online. The
underwriters may agree with ECA to allocate a specific number of
common units for sale to online brokerage account holders. Any
such allocation for online distributions will be made by the
underwriters on the same basis as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters or any selling group members
website and any information contained in any other website
maintained by the underwriters or any selling group member is
not part of this prospectus or the registration statement of
which this prospectus forms a part, has not been approved or
endorsed by ECA or any underwriters or any selling group member
in its capacity as underwriter or selling group member and
should not be relied upon by investors.
FINRA
RULES
Because the FINRA is expected to view the common units offered
hereby as interests in a direct participation program, this
offering is being made in compliance with Rule 2310 of the
FINRA Rules. Investor suitability with respect to the common
units should be judged similarly to the suitability with respect
to other securities that are listed for trading on a national
securities exchange.
119
CERTAIN
TRANSACTIONS
Certain officers, directors and employees of ECA and members of
their families (the Private Investors) regularly
participate in ECAs annual drilling programs. Under such
drilling programs, ECA has the right to select the wells to be
drilled, and the Private Investors cannot selectively choose the
wells in which they participate. For so long as (i) a
Private Investor remains a director or employee of ECA (or, in
the case of a family member, for so long as the family member
remains a director or employee of ECA) and (ii) such
Private Investor has participated in the prior years
drilling program, such Private Investor has the right to
participate in ECAs future drilling programs. The Private
Investors listed below participated in ECAs 2009 drilling
program (the Drilling Program), and based on the
success of this program, are entitled to participate in future
drilling programs.
The following table sets forth with respect to those Private
Investors that are beneficial holders of more than 5% of either
class of ECAs securities, directors of ECA or executive
officers of ECA, and their immediate family members; all other
Private Investors as a group; and all the Private Investors as a
group: (i) the purchase price paid by such Private Investor
for his or her interest in the Drilling Program and
(ii) such Private Investors percentage interest in
the Drilling Program.
|
|
|
|
|
|
|
|
|
|
|
Purchase Price for
|
|
|
Percentage
|
|
|
|
Participation
|
|
|
Interest in the
|
|
|
|
in Drilling
|
|
|
Drilling
|
|
Private Investors
|
|
Program
|
|
|
Program
|
|
|
W. Gaston Caperton, III
|
|
$
|
116,259
|
|
|
|
1.89%
|
|
Peter H. Coors
|
|
|
290,646
|
|
|
|
4.72%
|
|
L.B. Curtis
|
|
|
67,430
|
|
|
|
1.10%
|
|
John J. Dorgan
|
|
|
58,129
|
|
|
|
0.94%
|
|
John S. Fischer
|
|
|
290,646
|
|
|
|
4.72%
|
|
Michael S. Fletcher
|
|
|
29,065
|
|
|
|
0.47%
|
|
J. Michael Forbes
|
|
|
40,458
|
|
|
|
0.66%
|
|
Thomas R. Goodwin
|
|
|
174,388
|
|
|
|
2.83%
|
|
F.H. McCullough III (1)
|
|
|
453,408
|
|
|
|
7.36%
|
|
John Mork (2)
|
|
|
3,573,790
|
|
|
|
58.05%
|
|
Julie M. Mork (2)
|
|
|
3,573,790
|
|
|
|
58.05%
|
|
Kyle M. Mork (3)
|
|
|
337,150
|
|
|
|
5.48%
|
|
Arthur C. Nielsen, Jr.
|
|
|
29,065
|
|
|
|
0.47%
|
|
George OMalley
|
|
|
29,669
|
|
|
|
0.48%
|
|
Jay S. Pifer
|
|
|
29,065
|
|
|
|
0.47%
|
|
Donald C. Supcoe
|
|
|
58,129
|
|
|
|
0.94%
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
5,577,297
|
|
|
|
90.59%
|
|
Other Private Investors
|
|
|
549,043
|
|
|
|
8.92%
|
|
|
|
|
|
|
|
|
|
|
Private Investor Total
|
|
$
|
6,126,339
|
|
|
|
99.51%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Includes investments by the
Katherine F. McCullough Trust, the Lesley McCullough Trust and
the Kristin McCullough Trust.
|
|
(2)
|
|
Includes investments by John and
Julie Mork as joint tenants, and investments by the Alison Mork
Trust.
|
|
(3)
|
|
Includes investments by the Kyle
Mork Trust.
|
120
Immediately prior to the closing of this offering, the Private
Investors will convey to ECA the working interest each such
Private Investor holds in the Producing Wells, retaining a
perpetual royalty interest identical in nature to the Perpetual
PDP Royalty to be contributed by ECA to the trust (individually,
a Private Investor Royalty and collectively, the
Private Investors Royalties). At the closing of this
offering, the Private Investors will convey the Private
Investors Royalties to the trust and agree to forgo his or her
ability to participate in future drilling programs with respect
to the portion of PUD Wells being conveyed to the trust in
exchange for the common units described below. Certain Private
Investors have elected for ECA to purchase at the closing of the
offering a portion of their common units to be received as
described above at the initial public offering price. Pursuant
to such election, ECA will purchase a total of 209,316 common
units from the Private Investors at the closing of this
offering. Upon completion of the transactions described above,
ECA will hold 3,395,433 common units (2,045,433 if the
underwriters exercise their over-allotment option in full) and
4,500,000 subordinated units, representing 43.9% of the trust
units (36.4% if the underwriters exercise their over-allotment
option in full), and the Private Investors will hold 1,104,567
common units, representing 6.1% of the trust units.
The table below sets forth with respect to those Private
Investors that are beneficial holders of more than 5% of either
class of ECAs securities, directors of ECA or executive
officers of ECA, and their immediate family members; all other
Private Investors and all Private Investors as a group:
(i) the value of the Private Investors interest in
the Drilling Program, including relinquishment of the right to
participate in the portion of the PUD Wells being conveyed to
the trust; (ii) the Private Investors percentage
interest in the Drilling Program; (iii) the number of
common units to be owned by the Private Investor after the
purchase by ECA of a portion of the common units as described
above; and (iv) the cash proceeds to be received by such
Private Investor upon the purchase by ECA of such common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Cash Proceeds
|
|
|
|
Value of
|
|
|
Percentage
|
|
|
Common Units
|
|
|
Upon Sale to
|
|
|
|
Interest in the
|
|
|
Interest in the
|
|
|
After Purchase
|
|
|
ECA of
|
|
Private Investors
|
|
Drilling Program
|
|
|
Drilling Program
|
|
|
by ECA
|
|
|
Common Units
|
|
|
W. Gaston Caperton, III
|
|
$
|
496,209
|
|
|
|
1.89%
|
|
|
|
24,933
|
|
|
$
|
|
|
Peter H. Coors
|
|
|
1,240,522
|
|
|
|
4.72%
|
|
|
|
62,333
|
|
|
|
|
|
L.B. Curtis
|
|
|
287,801
|
|
|
|
1.10%
|
|
|
|
13,000
|
|
|
|
|
|
John J. Dorgan
|
|
|
248,104
|
|
|
|
0.94%
|
|
|
|
12,467
|
|
|
|
|
|
John S. Fischer
|
|
|
1,240,522
|
|
|
|
4.72%
|
|
|
|
56,100
|
|
|
|
|
|
Michael S. Fletcher
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
3,233
|
|
|
|
|
|
J. Michael Forbes
|
|
|
172,681
|
|
|
|
0.66%
|
|
|
|
8,677
|
|
|
|
|
|
Thomas R. Goodwin
|
|
|
744,314
|
|
|
|
2.83%
|
|
|
|
37,400
|
|
|
|
|
|
F.H. McCullough III (1)
|
|
|
1,935,215
|
|
|
|
7.36%
|
|
|
|
78,000
|
|
|
|
|
|
John Mork (2)
|
|
|
15,253,477
|
|
|
|
58.05%
|
|
|
|
616,451
|
|
|
|
|
|
Julie M. Mork (2)
|
|
|
15,253,477
|
|
|
|
58.05%
|
|
|
|
616,451
|
|
|
|
|
|
Kyle M. Mork (3)
|
|
|
1,439,007
|
|
|
|
5.48%
|
|
|
|
72,307
|
|
|
|
|
|
Arthur C. Nielsen, Jr.
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
6,233
|
|
|
|
|
|
George OMalley
|
|
|
126,633
|
|
|
|
0.48%
|
|
|
|
2,000
|
|
|
|
|
|
Jay S. Pifer
|
|
|
124,052
|
|
|
|
0.47%
|
|
|
|
6,233
|
|
|
|
|
|
Donald C. Supcoe
|
|
|
248,104
|
|
|
|
0.94%
|
|
|
|
6,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,804,748
|
|
|
|
90.59%
|
|
|
|
1,005,601
|
|
|
$
|
|
|
Other Private Investors
|
|
|
2,343,397
|
|
|
|
8.92%
|
|
|
|
98,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private Investor Total
|
|
$
|
26,148,144
|
|
|
|
99.51%
|
|
|
|
1,104,567
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
121
|
|
|
(1)
|
|
Includes investments by the
Katherine F. McCullough Trust, the Lesley McCullough Trust and
the Kristin McCullough Trust.
|
|
(2)
|
|
Includes investments by John and
Julie Mork as joint tenants, and investments by the Alison Mork
Trust.
|
|
(3)
|
|
Includes investments by the Kyle
Mork Trust.
|
122
LEGAL
MATTERS
, as special Delaware counsel to
ECA, will give a legal opinion as to the validity of the trust
units. Vinson & Elkins L.L.P., Houston, Texas, will
give opinions as to certain other matters relating to the
offering, including the tax opinion described in the section of
this prospectus captioned Federal income tax
considerations. Certain legal matters in connection with
the common units offered hereby will be passed upon for the
underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
Certain information appearing in this prospectus regarding the
March 31, 2010 estimated quantities of reserves of the
Underlying Properties and royalty interests owned by the trust,
the future net revenues from those reserves and their present
value is based on estimates of the reserves and present values
prepared by or derived from estimates prepared by Ryder Scott
Company, L.P., independent petroleum engineers.
The consolidated financial statements of Energy Corporation of
America as of June 30, 2009 and 2008 and for each of three
years in the period ended June 30, 2009 and the statement
of historical revenues and direct operating expenses of the
Underlying PDP Properties, for the period ended
December 31, 2009 appearing in this prospectus have been
audited by Ernst & Young LLP, independent registered
public accounting firm, as set forth in their reports thereon
appearing elsewhere herein, and are included in reliance upon
such reports given on the authority of such firm as experts in
accounting and auditing.
The statement of assets and trust corpus of ECA Marcellus Trust
I as of March 19, 2010, included in this Registration
Statement has been audited by Ernst & Young LLP, an
independent registered public accounting firm, as stated in
their report appearing elsewhere herein, and is included in
reliance upon such report given on the authority of such firm as
experts in accounting and auditing.
WHERE YOU
CAN FIND MORE INFORMATION
The trust and ECA have filed with the SEC a registration
statement on
Form S-1
regarding the common units. This prospectus does not contain all
of the information found in the registration statement. For
further information regarding the trust, ECA and the common
units offered by this prospectus, you may desire to review the
full registration statement, including its exhibits and
schedules, filed under the Securities Act. The registration
statement of which this prospectus forms a part, including its
exhibits and schedules, may be inspected and copied at the
public reference room maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. Copies of the materials may also be
obtained from the SEC at prescribed rates by writing to the
public reference room maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. You may obtain information on the
operation of the public reference room by calling the SEC at
1-800-SEC-0330.
The SEC maintains a web site on the Internet at
http://www.sec.gov.
The trusts and ECAs registration statement, of which
this prospectus constitutes a part, can be downloaded from the
SECs web site.
We intend to furnish the trusts unitholders annual reports
containing our audited consolidated financial statements and to
furnish or make available to the trusts unitholders
quarterly reports containing the trusts unaudited interim
financial information for the first three fiscal quarters of
each of our fiscal years.
123
GLOSSARY
OF CERTAIN OIL AND NATURAL GAS TERMS AND
TERMS RELATED TO THE TRUST
In this prospectus the following terms have the meanings
specified below.
AMI
The Marcellus Shale formation of the
proved undeveloped natural gas properties presently consisting
of approximately 9,300 net acres held by ECA excluding
existing well bores on which ECA has agreed to drill PUD Wells
for the benefit of the trust by March 31, 2013 subject to a
one year extension to complete drilling in the case of delays.
The AMI will consist of approximately 121 square miles and
is depicted by the area identified on the inside front cover of
this prospectus.
Bbl
One stock tank barrel, or 42
U.S. gallons liquid volume, of crude oil or other liquid
hydrocarbons.
Bcf
One billion standard cubic feet of
natural gas.
Bcfe
One billion standard cubic feet of
natural gas equivalent, computed on an approximate energy
equivalent basis that one Bbl equals six Mcf.
Btu
A British Thermal Unit, a common unit of
energy measurement.
ECAs retained interest
ECAs
retained interest in 10% of the proceeds from the sale of
production from the 14 producing Marcellus Shale natural gas
wells located in Greene County, Pennsylvania as well as
ECAs retained interest in 50% of the proceeds from the
sale of production from the PUD Wells to be drilled in the AMI.
Estimated future net revenues
Also referred
to as estimated future net cash flows. The result of
applying current prices of natural gas to estimated future
production from natural gas proved reserves, reduced by
estimated future expenditures, based on current costs to be
incurred, in developing and producing the proved reserves,
excluding overhead.
Farmout agreement
A farmout agreement is
typically an agreement under which a lessee under an oil and gas
lease agrees to grant to another party the right to drill wells
on the tract covered by such lease and to earn certain acreage
for drilling such wells.
Fractional well
Wells with a horizontal
lateral (measured from the midpoint of the curve) of less than
2,500 feet in proportion to total length divided by 2,500
count as fractional wells while wells with a horizontal lateral
of more than 2,500 feet in proportion to total lateral
length divided by 2,500 count as multiple fractional wells.
MBbl
One thousand Bbl.
Mcf
One thousand standard cubic feet of
natural gas.
Mcfe
One thousand standard cubic feet of
natural gas equivalent, computed on an approximate energy
equivalent basis that one Bbl equals six Mcf.
MMBtu
One million British Thermal Units
(Btus).
MMcf
One million standard cubic feet of
natural gas.
124
MMcfe
One million standard cubic feet of
natural gas equivalent, computed on an approximate energy
equivalent basis that one Bbl equals six Mcf.
PDP Royalty Interest
royalty interests
entitling the trust to receive an aggregate of 90% of the
proceeds (net of post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs working interest in the 14 producing horizontal
Marcellus Shale natural gas wells located in Greene County,
Pennsylvania for 20 years, and 45% of such proceeds
thereafter (pending a sale thereof by the trust).
Proved developed reserves
Proved reserves
that can be expected to be recovered through existing wells with
existing equipment and operating methods.
Proved reserves
The estimated quantities of
natural gas and natural gas liquids which, upon analysis of
geological and engineering data, appear with reasonable
certainty to be recoverable in the future from known natural gas
reservoirs under existing economic and operating conditions.
The Securities and Exchange Commission definition of proved oil
and gas reserves, per
Article 4-10(a)(2)
of
Regulation S-X,
is as follows:
Proved oil and gas reserves.
Proved oil and gas
reserves are the estimated quantities of crude oil, natural gas,
and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but
not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (A) that portion delineated by drilling and
defined by gas-oil
and/or
oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the proved classification
when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the
following: (A) oil that may become available from known
reservoirs but is classified separately as indicated
additional reserves; (B) crude oil, natural gas, and
natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil,
natural gas, and natural gas liquids, that may occur in
undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales,
coal, gilsonite and other such sources.
Proved undeveloped reserves
Proved reserves
that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is required.
125
PUD Royalty Interest
royalty interests
entitling the trust to receive an aggregate of 50% of the
proceeds (net of post-production costs and any applicable taxes)
from the sale of production of natural gas attributable to
ECAs interest in 52 horizontal Marcellus Shale natural gas
wells to be drilled in the AMI and 25% of such proceeds
thereafter (pending a sale thereof by the trust).
Tcf
One trillion standard cubic feet of
natural gas.
Working interest
A property interest
entitling the owner to receive a specified percentage of the
proceeds of the sale of oil and natural gas production or a
percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and
produce such oil and natural gas. A working interest owner who
owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or
disapprove the appointment of an operator and certain activities
in connection with the development and operation of a property.
126
Report of
Independent Registered Public Accounting Firm
To the Board
of Directors and Stockholders
Energy Corporation of America:
We have audited the accompanying statement of historical
revenues and direct operating expenses of the Underlying PDP
Properties (the Properties) of Energy Corporation of
America (the Company) for the six month period ended
December 31, 2009. This financial statement is the
responsibility of the Companys management. Our
responsibility is to express an opinion on this financial
statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of historical
revenues and direct operating expenses of the Properties is free
of material misstatement. We were not engaged to perform an
audit of the Companys internal control over financial
reporting. Our audit included consideration of internal control
over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of
the Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the statement of historical revenues and direct
operating expenses, assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall statement of historical revenues and direct
operating expenses presentation. We believe that our audit
provides a reasonable basis for our opinion.
The accompanying statement was prepared for the purpose of
complying with the rules and regulations of the Securities and
Exchange Commission as described in the notes to the financial
statement and is not intended to be a complete presentation of
the Companys interests in the Properties.
In our opinion, the statement referred to above presents fairly,
in all material respects, the historical revenues and direct
operating expenses of the Properties for the six month period
ended December 31, 2009, in conformity with
U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 12, 2010
F-2
|
|
|
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
Gas Sales
|
|
$
|
3,623
|
|
|
|
|
|
|
Total Revenues
|
|
|
3,623
|
|
Operating Expenses:
|
|
|
|
|
Taxes on Production and Property
|
|
|
|
|
Lease Operation Expenses
|
|
|
22
|
|
Field Operation Expenses
|
|
|
2
|
|
Marketing Fee
|
|
|
132
|
|
Gathering and Transportation
|
|
|
458
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
614
|
|
|
|
|
|
|
Excess of revenues over operating expenses
|
|
$
|
3,009
|
|
|
|
|
|
|
See accompanying notes to the
Statement of Historical Revenues and Direct Operating Expenses.
F-3
FOR THE
SIX MONTHS ENDED DECEMBER 31, 2009
The Underlying PDP Properties, as of December 31, 2009,
consist of working interests owned by Energy Corporation of
America (ECA) in four producing properties in the
Marcellus Shale Formation located in Greene County, Pennsylvania.
Eastern Marketing Corporation, a wholly owned subsidiary of ECA,
has purchased the natural gas production from these wells at
prices substantially equivalent to prices paid by unaffiliated
purchasers in the marketing area.
The accompanying statement of historical revenues and direct
operating expenses was derived from the historical accounting
records of ECA and reflects the historical revenues and
operating expenses directly attributable to the Underlying PDP
Properties for the period described herein. Such amounts may not
be representative of future operations. The statement does not
include depreciation, depletion and amortization, general and
administrative expenses, interest expense, federal and state
income taxes or other expenses of an indirect nature. The
amounts represent 100% of ECAs interest.
Historical financial statements reflecting financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the Underlying PDP Properties.
Accordingly, the statement of historical revenue and direct
operating expenses is presented in accordance with Staff
Accounting Bulletin Topic
2-D,
Financial Statements of Oil and Gas Exchange Offers.
The accompanying statement of historical revenues and direct
operating expenses included herein was prepared on an accrual
basis. Revenue from gas sales is recognized when the gas is
produced and sold.
The process of preparing the financial statements in conformity
with generally accepted accounting principles requires the use
of estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
|
|
3.
|
SUPPLEMENTAL
DISCLOSURES OF GAS PRODUCING ACTIVITIES (UNAUDITED)
|
Information with respect to gas producing activities of the
Underlying PDP Properties is presented in the following tables.
The information was derived from reserve reports which were
prepared by independent reserve engineers as of
December 31, 2009, in accordance with ASU
F-4
UNDERLYING
PDP PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
2010-03
Extractive Activities Oil and Gas (Topic 932):
Oil and Gas Reserve Estimation and Disclosures.
Gas
Reserves
Estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history,
results of additional exploration and development, price changes
and other factors.
The following table summarizes the estimated quantities of the
proved developed natural gas reserves (MMcfs) of the Underlying
PDP Properties:
|
|
|
|
|
|
|
Natural Gas
|
|
|
(Mmcf)
|
|
Proved reserves:
|
|
|
|
|
June 30, 2009
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
|
|
Extensions and discoveries
|
|
|
10,580
|
|
Sales of reserves in place
|
|
|
|
|
Purchases of reserves in place
|
|
|
|
|
Production
|
|
|
(841
|
)
|
|
|
|
|
|
December 31, 2009
|
|
|
9,739
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
December 31, 2009
|
|
|
9,739
|
|
|
|
|
|
|
Proved reserves are estimated quantities of natural gas which
geological and engineering data indicated with reasonable
certainty to be recoverable in future years from known reserves
under existing economic and operating conditions. Proved
developed reserves are proven reserves, which are expected to be
recovered through existing wells with existing equipment and
operation methods.
Estimated
Present Value of Future Net Cash Flows
Standardized Measure of Discounted Future Net Cash
Flows
Estimated discounted future net cash
flows and changes therein were determined in accordance with ASC
932, Disclosures About Oil and Gas Producing
Activities. Certain information concerning the assumptions
used in computing the valuation of proved developed reserves and
their inherent limitations are discussed below. ECA believes
such information is essential for a proper understanding and
assessment of the data presented.
Future cash inflows are computed by applying the average prices
of gas during the
12-month
period ending December 31, 2009, determined using the
unweighted arithmetic average of the prices in effect on the
first-day-of-the-month
for each month within the period relating to the Underlying PDP
Properties proved developed reserves to the period-end
quantities of those
F-5
UNDERLYING
PDP PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
reserves. Future price changes are considered only to the extent
provided by contractual arrangements in existence at period-end.
The assumptions used to compute estimated future net revenues do
not necessarily reflect ECAs expectations of actual
revenues or costs or their present worth. In addition,
variations from the expected production rates also could result
directly or indirectly from factors outside of ECAs
control, such as unintentional delays in development, changes in
prices or regulatory controls. The reserve valuation further
assumes that all reserves will be disposed of by production.
However, if reserves are sold in place, this could affect the
amount of cash eventually realized.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and gas reserves at December 31,
2009, based on period-end costs and assuming continuation of
existing economic conditions.
Future income tax expenses are computed by applying the
appropriate period-end statutory tax rates and existing tax
credits, with consideration of future tax rates already
legislated, to the future pretax net cash flows relating to the
Underlying PDP Properties proved developed gas reserves.
An annual discount rate of 10% was used to reflect the timing of
the future net cash flows relating to proved developed gas
reserves.
Information with respect to the Underlying PDP Properties
estimated discounted future net cash flows related to its proved
developed gas reserves as of December 31 is as follows (in
thousands):
|
|
|
|
|
|
|
2009
|
|
|
Future cash in flows
|
|
$
|
38,821
|
|
Future production and development costs
|
|
|
(6,305
|
)
|
Future income tax expense
|
|
|
|
|
|
|
|
|
|
Future net cash flows before discount
|
|
|
32,516
|
|
10% discount to present value
|
|
|
(15,128
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved oil and gas reserves
|
|
$
|
17,388
|
|
|
|
|
|
|
F-6
UNDERLYING
PDP PROPERTIES
Notes to the Statement of Historical Revenues and
Direct Operating Expenses (Continued)
The changes in the standardized measure of discounted future net
cash flows relating to proved developed gas reserves as of
December 31 is as follows (in thousands):
|
|
|
|
|
|
|
2009
|
|
|
Standardized measure of discounted future net cash flow at
beginning of period
|
|
$
|
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(3,009
|
)
|
Net changes in prices and production costs
|
|
|
1,500
|
|
Changes in production rates and other
|
|
|
|
|
Extensions, discoveries and other additions, net of future
production and development costs
|
|
|
18,897
|
|
Changes in estimated future development costs
|
|
|
|
|
Development costs incurred
|
|
|
|
|
Revisions of previous quantity estimates
|
|
|
|
|
Purchase of reserves in place
|
|
|
|
|
Accretion of discount
|
|
|
|
|
Net change in income taxes
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows at end
of period
|
|
$
|
17,388
|
|
|
|
|
|
|
F-7
ECA
MARCELLUS TRUST I
To the Trustee
ECA Marcellus Trust I:
We have audited the accompanying statement of assets and trust
corpus of ECA Marcellus Trust I (the Trust) as of
March 19, 2010. This financial statement is the
responsibility of the Trusts management. Our
responsibility is to express an opinion on this financial
statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of assets and
trust corpus is free of material misstatement. We were not
engaged to perform an audit of the Trusts internal control
over financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Trusts internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the statement of
assets and trust corpus, assessing the accounting principles
used and significant estimates made by management, as well as
evaluating the overall statement of assets and trust corpus
presentation. We believe that our audit provides a reasonable
basis for our opinion.
As described in Note 2 to the statement of assets and trust
corpus, this statement has been prepared on a modified cash
basis of accounting, which is a comprehensive basis of
accounting other than U.S. generally accepted accounting
principles.
In our opinion, the statement of assets and trust corpus
presents fairly, in all material respects, the financial
position of ECA Marcellus Trust I as of March 19, 2010, on
the basis of accounting described in Note 2.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 22, 2010
F-8
ECA
MARCELLUS TRUST I
|
|
|
|
|
|
|
As of
|
|
|
|
March 19, 2010
|
|
|
Assets
:
|
|
|
|
|
Cash
|
|
$
|
10
|
|
|
|
|
|
|
Total
|
|
$
|
10
|
|
|
|
|
|
|
Trust Corpus
:
|
|
|
|
|
Trust corpus
|
|
$
|
10
|
|
|
|
|
|
|
Total
|
|
$
|
10
|
|
|
|
|
|
|
See notes to the statement of
assets and trust corpus.
F-9
ECA
MARCELLUS TRUST I
|
|
1.
|
ORGANIZATION
OF THE TRUST
|
The ECA Marcellus Trust I (the Trust) is a
statutory trust formed in March 2010 under the Delaware
Statutory Trust Act pursuant to a Trust Agreement (the
Trust Agreement) among by Energy Corporation of
America (ECA), as trustor, The Bank of New York
Mellon Trust Company, N.A., as Trustee (the
Trustee), and Corporation Trust Company, as Delaware
Trustee (the Delaware Trustee).
The Trust was created to acquire and hold royalty interests for
the benefit of Trust unitholders pursuant to an agreement
between ECA, the Trustee and the Delaware Trustee. These royalty
interests are interests in underlying producing properties
consisting of ECAs interests in specified gas properties
located in the Marcellus Shale Formation in Greene County,
Pennsylvania. These properties consist of 14 Underlying PDP
Properties and 52 proved undeveloped well locations that ECA
will be obligated to drill in an area of mutual interest.
The royalty interests are passive in nature and neither the
Trust nor the Trustee has any control over, or responsibility
for, costs relating to the operation of the Underlying
Properties. After the conveyance of royalty interests, ECA will
retain interest in each of the Underlying PDP Properties and
Underlying PUD Properties. The trust agreement will provide that
the Trusts business activities will be limited to owning
the royalty interests and any activity reasonably related to
such ownership including activities of a portion of certain
natural gas floor price contracts which relate to a portion of
the natural gas production attributable to the trusts
royalty interest. The Trust will not be permitted to acquire
other oil and gas properties or royalty interests.
The Trust will begin to liquidate on March 31, 2030 (the
Termination Date) and will soon thereafter wind up
its affairs and terminate. Fifty percent of the royalty
interests will automatically revert to ECA at the Termination
Date, while the Perpetual Royalties will be sold and the
proceeds will be distributed to the unitholders at the
Termination Date or soon thereafter. ECA will have a first right
of refusal to purchase the remaining fifty percent of the
royalty interests at the Termination Date.
|
|
2.
|
SIGNIFICANT
ACCOUNTING POLICIES
|
The following is a summary of the significant accounting
policies followed by the Trust.
Basis of Accounting
The financial statements
of the Trust are prepared on the following basis:
|
|
|
|
|
Royalty income recorded is the amount computed to be paid by ECA
to the Trustee on behalf of the Trust for the corresponding
quarter.
|
|
|
|
Trust expenses are recorded when paid.
|
|
|
|
Distributable income is reduced by cash reserves established for
liabilities and contingencies.
|
|
|
|
Distributions to unitholders are recorded in the quarter to
which they apply.
|
F-10
ECA
MARCELLUS TRUST I
Notes to
Statement of Assets and
Trust Corpus (Continued)
The financial statements of the trust differ from financial
statements prepared in accordance with accounting principles
generally accepted in the United States of America
(GAAP) because certain cash reserves may be
established for contingencies, which would not be accrued in
financial statements prepared in accordance with GAAP.
Amortization of the investment in overriding royalty interests
calculated on a
unit-of-production
basis is charged directly to trust corpus. This comprehensive
basis of accounting other than GAAP corresponds to the
accounting permitted for royalty trusts by the
U.S. Securities and Exchange Commission as specified by
Staff Accounting Bulletin Topic 12:E, Financial Statements
of Royalty Trusts.
Cash
Cash consists of highly liquid
instruments with maturities at the time of acquisition of three
months or less.
Use of Estimates in the Preparation of Financial
Statements
The preparation of financial
statements requires the trust to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those
estimates.
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes.
|
|
4.
|
DISTRIBUTIONS
TO UNITHOLDERS
|
The trust will make quarterly cash distributions of the cash
received from Energy Corporation of America, after deducting
trust administrative expenses paid on or about 60 days
after the completion of each quarter through (and including) the
quarter ending March 31, 2030 (the Termination
Date). The first quarterly distribution is expected to be
made on or about August 31, 2010 to record unitholders as
of August 15, 2010. The trust will begin to liquidate on
the Termination Date and will soon thereafter wind up its
affairs and terminate. Upon termination of the trust, 50% of
each of the PDP Royalty Interest and the PUD Royalty Interest
will revert automatically to ECA. The remaining 50% of each of
the PDP Royalty Interest and the PUD Royalty Interest will be
sold, and the net proceeds therefrom will be distributed pro
rata to the unitholders soon after the Termination Date. Because
payments to the trust will be generated by depleting assets and
the trust has a finite life with the production from the
Underlying Properties diminishing over time, a portion of each
distribution will represent a return of your original investment.
F-11
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Financial Information
The following unaudited pro forma statement of asset and trust
corpus and unaudited pro forma statements of distributable
income for the Trust have been prepared to illustrate the
conveyance of royalty interests in certain Underlying Properties
to the trust by ECA. The unaudited pro forma statement of asset
and trust corpus presents the beginning statement of assets,
liabilities and trust corpus of the Trust as of March 19,
2010, giving effect to the royalty interests conveyance as if it
occurred on that date. The unaudited pro forma statement of
distributable income presents the statements of historical
revenue and direct operating expenses of the Underlying PDP
Properties for the six months ended December 31, 2009,
giving effect to the royalty interests conveyance as if it
occurred as of July 1, 2009, reflecting only pro forma
adjustments expected to have a continuing impact on the combined
results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the royalty
interests conveyance been completed on the assumed dates or for
the periods presented, or which may be realized in the future.
To produce the pro forma financial information, management made
certain estimates. The accompanying unaudited pro forma
statement of assets, liabilities and trust corpus assumes a
March 19, 2010 issuance of 18,000,000 trust units at
$ per unit. The accompanying unaudited pro
forma statements of distributable income for the six months
ended December 31, 2009 have been prepared assuming Trust
formation and royalty interests conveyance at the beginning of
the period presented.
These estimates are based on the most recently available
information. To the extent there are significant changes in
these amounts, the assumptions and estimates herein could change
significantly. The statements of distributable income should be
read in conjunction with the Managements Discussion
and Analysis of Financial Condition and Results of Operations of
Energy Corporation of America included in the ECA Annex to
this prospectus and the historical statements of the trust, ECA
and the Underlying Properties, including the related notes,
included in this prospectus.
F-12
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Statements of Assets, Liabilities, and
Trust Corpus
As of
March 19, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
Assets
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
10
|
|
|
$
|
|
|
|
$
|
10
|
|
Investment in Royalty Interest
|
|
|
|
|
|
|
360,000,000
|
(a)
|
|
|
360,000,000
|
|
Floor price contracts
|
|
|
|
|
|
|
4,957,920
|
(a)
|
|
|
4,957,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
10
|
|
|
$
|
364,957,920
|
|
|
$
|
364,957,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor premiums payable
|
|
$
|
|
|
|
$
|
4,957,920
|
(b)
|
|
$
|
4,957,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
$
|
|
|
|
$
|
4,957,920
|
|
|
$
|
4,957,920
|
|
Trust Corpus
:
|
|
|
|
|
|
|
|
|
|
|
|
|
18,000,000 Trust Units Issued and Outstanding at Formation
|
|
$
|
10
|
|
|
$
|
360,000,000
|
|
|
$
|
360,000,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Trust Corpus
|
|
$
|
10
|
|
|
$
|
364,957,920
|
|
|
$
|
364,957,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are integral
part of the unaudited pro forma financial information
F-13
ECA
MARCELLUS TRUST I
Unaudited
Pro Forma Statement of Distributable Income
For the
Six Month Period Ended December 31, 2009
(In
thousands, except per unit)
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
Historical results:
|
|
|
|
|
Revenue from gas sales
|
|
$
|
3,623
|
|
Direct operating expenses:
|
|
|
|
|
Production and property taxes
|
|
|
|
|
Production expenses
|
|
|
24
|
|
Marketing fee
|
|
|
132
|
|
Gathering and transportation
|
|
|
458
|
|
|
|
|
|
|
Total
|
|
|
614
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses before pro
forma adjustments
|
|
$
|
3,009
|
|
Pro Forma adjustments:
|
|
|
|
|
Historical production expenses
|
|
|
24
|
(c)
|
Marketing fee
|
|
|
132
|
(c)
|
|
|
|
|
|
Total pro forma adjustments
|
|
|
156
|
|
|
|
|
|
|
Pro forma gross net proceeds
|
|
$
|
3,165
|
|
Overriding royalty interest percentage
|
|
|
90
|
%
|
|
|
|
|
|
Net proceeds to trust
|
|
$
|
2,849
|
|
Less trust general and administrative expenses and state
franchise taxes
|
|
|
550
|
(d)
|
|
|
|
|
|
Distributable income
|
|
$
|
2,299
|
(e)
|
|
|
|
|
|
Distributable income per unit
|
|
$
|
0.13
|
|
|
|
|
|
|
The accompanying notes are integral
part of the unaudited pro forma financial information
F-14
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial Information
|
|
NOTE 1.
|
BASIS OF
PRESENTATION
|
ECA Marcellus Trust I is a Delaware statutory trust formed
in March 2010 by Energy Corporation of America to own royalty
interests in 14 producing horizontal natural gas wells producing
from the Marcellus Shale formation and located in Greene County,
Pennsylvania (the Producing Wells) and royalty
interests in 52 horizontal natural gas development wells to be
drilled in the Marcellus Shale formation (the PUD
Wells) within the area of mutual interest, or
AMI, comprised of approximately 9,300 net acres
held by ECA in Greene County, Pennsylvania. The royalty
interests will be conveyed from ECAs working interest in
the Producing Wells limited to the Marcellus Shale formation
(approximately 93%) and the PUD Wells (the underlying
properties). The royalty interest in the Producing Wells
(the PDP Royalty Interest) entitles the trust to
receive 90% of the proceeds (after deducting post-production
costs and any applicable taxes) from the sale of production of
natural gas attributable to ECAs interest in the Producing
Wells. The royalty interest in the PUD Wells (the PUD
Royalty Interest) entitles the trust to receive 50% of the
proceeds (after deducting post-production costs and applicable
taxes) from the sale of production of natural gas attributable
to ECAs interest in the PUD Wells. Approximately 50% of
the estimated natural gas production attributable to the
trusts royalty interests will be hedged from April 1,
2010 to March 31, 2014. These hedging contracts will be
transferred to the trust by ECA, and ECA will be entitled to
recoup the costs of establishing the hedging contracts to the
extent cash available for distribution by the trust exceeds
certain levels.
The unaudited pro forma financial information assumes the
issuance of 18,000,000 trust units at
$ per unit.
In order to provide support for cash distributions on the common
units, ECA has agreed to subordinate 4,500,000 of the trust
units it will retain following this offering, which will
comprise 25% of the outstanding trust units. While the
subordinated units will be entitled to receive pro rata
distributions from the trust if and to the extent there is
sufficient cash to provide a cash distribution on the common
units which is no less than the applicable quarterly
subordination threshold, if there is not sufficient cash to fund
such a distribution on all trust units, the distribution to be
made with respect to the subordinated units will be reduced or
eliminated in order to make a distribution, to the extent
possible, of up to the subordination threshold amount on the
common units. Each applicable quarterly subordination threshold
is equal to 80% of the target cash distribution level for the
corresponding quarter as reflected on Annex B (each, a
subordination threshold). In exchange for agreeing
to subordinate these trust units, and in order to provide
additional financial incentive to ECA to perform its drilling
obligation and operations in the Underlying Properties in an
efficient and cost-effective manner, ECA will be entitled to
receive incentive distributions (the incentive
distributions) equal to 50% of the amount by which the
cash available for distribution on all of the trust units in any
quarter exceeds 150% of the subordination threshold for such
quarter (which is 120% of the target cash distribution) (each,
an incentive threshold). ECAs right to receive
this incentive distribution will terminate upon the expiration
of the subordination period. Additionally and notwithstanding
the foregoing, in exchange for the transfer by ECA to the trust
of the natural gas hedging contracts, until the earlier of the
expiration of the subordination period (as defined below) or
such time as the costs associated with establishing the natural
gas hedging contracts (the reimbursement amount)
have been paid in full, the trust will pay ECA an amount equal
to 50% of the amount by which the cash receipts in respect of
the royalties in any quarter exceeds the applicable incentive
threshold. Such obligation includes interest on the
reimbursement amount accruing at 10% per
F-15
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
year. ECA bears the risk that the subordination period will end
before it is reimbursed in full for establishing the hedging
contracts.
ECA has incurred costs of approximately $5 million in
securing the hedging contracts to be transferred to the trust.
ECA will be entitled to reimbursement for these expenditures
only if and to the extent distributions to trust unitholders
would otherwise exceed the incentive threshold. This
reimbursement will be deducted, over time, from the 50% of cash
available for distribution in excess of the incentive thresholds
otherwise payable to the trust unitholders. ECAs right to
receive the remaining 50% of such cash in the form of incentive
distributions would not be affected.
The subordinated units will automatically convert into common
units on a
one-for-one
basis and ECAs right to receive incentive distributions
and to recoup the reimbursement amount will terminate, at the
end of the fourth full calendar quarter following ECAs
satisfaction of its drilling obligation to the trust.
Accordingly, ECA bears the risk that it will not be partially or
fully reimbursed for the hedging contracts it is transferring to
the trust. The trust currently expects that ECA will complete
this drilling obligation on or before March 31, 2013 and
that, accordingly, the subordinated units will convert into
common units on or before March 31, 2014. In the event of
delays, ECA will have until March 31, 2014 to drill all the
PUD Wells, in which event the subordinated units will convert
into common units on or before March 31, 2015. The period
during which the subordinated units are outstanding is referred
to as the subordination period.
|
|
NOTE 2.
|
TRUST ACCOUNTING
POLICIES
|
The Unaudited Pro Forma Statement of Distributable Income was
derived from the historical accounting records of the Underlying
Properties.
Income determined on the basis of generally accepted accounting
principles would include all expenses incurred for the period
presented. However, the Trust serves as a pass-through entity,
with expenses for depreciation, depletion, and amortization,
interest and income taxes being based on the status and
elections of the trust unitholders. In addition, the royalty
interest will not be burdened by field and lease operating
expenses. Thus, the statement purports to show distributable
income, defined as income of the Trust available for
distribution to the trust unitholders before application of
those additional unitholders additional expenses, if any,
for depreciation, depletion, and amortization, interest and
income taxes. The revenues are reflected net of existing
royalties and overriding royalties and have been reduced by
gathering/post-production expenses. Actual cash receipts may
vary due to timing delays of actual cash receipts from the
property purchasers and due to wellhead and pipeline volume
balancing agreements or practices.
Investment in royalty interest is periodically assessed to
determine whether its aggregate value has been impaired below
its total capitalized cost based on the Underlying Properties.
The Trust will provide a write-down to its investment in the
royalty interests to the extent the total capitalized costs,
less accumulated depreciation, depletion and amortization,
exceed undiscounted future net revenues attributable to the
proved natural gas reserves of the Underlying Properties.
ECA believes that the assumptions used provide a reasonable
basis for presenting the significant effects directly
attributable to this transaction.
F-16
ECA
MARCELLUS TRUST I
Notes to
Unaudited Pro Forma Financial
Information (Continued)
The unaudited pro forma financial information should be read in
conjunction with the Statement of Assets and Trust Corpus and
the Statement of Historical Revenues and Direct Operating Costs
for Underlying PDP Properties and related notes for the period
presented.
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes. Accordingly, no provision for
federal or state income taxes has been made.
|
|
NOTE 4.
|
PRO FORMA
ADJUSTMENTS
|
(a) Reflects ECAs transfer of certain natural gas
floor price contracts and the conveyance of the royalty
interests to the Trust in exchange for 18,000,000 trust
units.
(b) Until the earlier of the expiration of the
subordination period (as defined in Note 1) or such time as
the reimbursement amount has been paid in full, the trust will
pay ECA an amount equal to 50% of the amount by which the cash
receipts in respect of the royalties in any quarter exceeds the
applicable incentive threshold. Such obligation includes
interest on the reimbursement amount accruing at 10% per annum.
ECA bears the risk that the subordination period will end before
it is reimbursed in full.
(c) Historical well production and lease production
expenses and marketing fee are not deducted in determining net
revenue attributable to the royalty interests and in determining
distributable income. Royalty interests, as defined in the
conveyance, will bear a pro rata share of taxes on production
and property, if any, and applicable gathering/post-production
expenses relating to make the gas saleable.
(d) The Trusts general and administrative expenses
are estimated at $800,000 annually. Such expenses include
trustee fees, administrative service fees and costs associated
with being a public entity. Pennsylvania state franchise taxes
are estimated at $150,000.
(e) Assumes that no incentive threshold was reached during
the period.
F-17
Business
of Energy Corporation of America
General
Energy Corporation of America (ECA or the
Company) is a privately held energy company engaged
in the exploration, development, production, gathering,
aggregation and sale of natural gas and oil, primarily in the
Appalachian Basin, Gulf Coast and Rocky Mountain regions in the
United States and in New Zealand. ECA or its predecessors have
owned and operated natural gas properties in the Appalachian
Basin for more than 45 years, and ECA is one of the largest
natural gas operators in the Appalachian Basin. As of
December 31, 2009, ECA operated approximately
5,100 wells in the Appalachian Basin and had an aggregate
net leasehold position of approximately one million acres, with
85% of this acreage held by production. ECA sells gas from its
own wells as well as third-party wells to local gas distribution
companies, industrial end users located in the Northeast, other
gas marketing entities and into the spot market for gas
delivered into interstate pipelines. ECA owns and operates
approximately 5,000 miles of gathering lines and intrastate
pipelines that are used in connection with its gas aggregation
activities. During the fiscal year ended June 30, 2009, ECA
aggregated and sold 22.5 Bcf of gas for an average of
62 MMcf of gas per day, of which 20.7 Bcf, or
57 MMcf per day, represented sales of gas produced from
wells operated by ECA.
ECA was formed in September 1992 as a Colorado corporation and
subsequently reincorporated in West Virginia through a merger in
June 1995. ECAs predecessor began operating in the
Appalachian Basin in 1963. ECAs principal offices are
located at 4643 South Ulster Street, Suite 1100, Denver,
Colorado 80237, and its telephone number is
(303) 694-2667.
Gas
And Oil Development And Production
Operations
and Significant Developments
The Companys proved developed net natural gas and oil
reserves are estimated as of July 1, 2009 at
143,167 MMcf and 322 MBbls, respectively. For the
fiscal year ended June 30, 2009, the Companys net
natural gas production was 9,364 MMcf and net oil
production was 47 MBbls, for a total of 9,646 net
MMcfe.
Development
Activity
During the fiscal year ended June 30, 2009, the Company
drilled 26 productive gross wells (20.9 net) and recompleted
four wells. The average first month gross production rate
for the four horizontal Marcellus Shale wells that the Company
drilled in Greene County, Pennsylvania in fiscal year 2009 was
2,334 Mcf per day per well. The average first month gross
production rate for the seven vertical Marcellus Shale wells
that the Company drilled in Greene County, Pennsylvania in
fiscal year 2009 was 193.4 Mcf per day per well. The average
first month gross production rate for the other 15 wells
that the Company drilled in fiscal year 2009 was 162.3 Mcf per
day per well. The average initial increase in gross production
rate for the four wells that the Company recompleted in fiscal
year 2009 in Fort Bend County, Texas was 1,777 Mcf per day
per well.
Competition
Given the increased activity in the Marcellus Shale formation,
the Company will encounter substantial competition in acquiring
properties, aggregating oil and natural gas, securing drilling
equipment and personnel and operating its properties. The
competitors in acquisitions,
ECA-2
development, exploration and production include major oil
companies, numerous independent oil and natural gas companies,
natural gas marketers, individual proprietors and others.
Natural gas competes with other forms of energy available to
customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of natural gas or other forms of energy,
as well as business conditions, conservation, legislation,
regulations and the ability to convert to alternate fuels and
other forms of energy may affect the demand for natural gas.
Regulations
Affecting Operations
The Companys operations are affected by extensive
regulation pursuant to various federal, state and local laws and
regulations relating to the exploration for and development,
production, gathering, aggregation, transportation and storage
of oil and natural gas. These regulations, among other things,
can affect the rate of oil and natural gas production. The
Companys operations are subject to numerous laws and
regulations governing plugging and abandonment, the discharge of
materials into the environment or otherwise relating to
environmental protection. These laws and regulations require the
acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that
can be released into the environment in connection with drilling
activities on certain lands lying within wilderness, wetlands
and other protected areas, and impose substantial liabilities
for pollution which might result from the Companys
operations. The Company believes it is in substantial compliance
with applicable regulations.
Gas
Aggregation and Pipelines
The Company, primarily through its wholly owned subsidiary
Eastern Marketing Corporation (Eastern Marketing),
aggregates natural gas through the purchase of production from
properties in the Appalachian Basin, including the Marcellus
Shale, in which the Company has an interest, the purchase of
natural gas delivered through the Companys gathering
pipelines located in the Appalachian Basin, and the purchase of
natural gas in the spot market. The Company sells natural gas to
local natural gas distribution companies, industrial end users
located in the Northeast, other natural gas marketing entities
and into the spot market for natural gas delivered into
interstate pipelines.
The Company owns and operates approximately 5,000 miles of
gathering lines and intrastate pipelines that are used in
connection with its gas aggregation activities. During the
fiscal year ended June 30, 2009, ECA and its affiliates
aggregated and sold 22.5 Bcf of natural gas for an average
of 62 MMcf of natural gas per day, of which 20.7 Bcf,
or 57 MMcf per day, represented sales of natural gas
produced from wells operated by ECA. Substantially all of the
production subject to the PDP Royalty Interest and PUD Royalty
Interest will be gathered by ECAs Greene County Gathering
System. This system currently accesses two separate
interconnects with the Texas Eastern Transmission, L.P. and
Columbia Gas Transmission, L.L.C. interstate pipeline systems
and includes (6) compressors (with 8,860 total horsepower)
together with associated processing equipment. ECA will add
additional compression and related facilities as the field is
developed. ECAs interconnect agreements with these
interstate pipelines currently allow it to deliver at the
interconnections between ECAs facilities and the
interstate pipelines, up to 110,000 MMBtu per day for
transportation by the interstate pipelines to ECAs
customers (approximately 16,000 MMBtu per day is currently being
utilized), on these two interstate pipeline systems, which is in
excess of its current and expected volumes from the Underlying
Properties. To the extent necessary, ECA will add additional
compression and related facilities to this System at no cost to
the trust, other than potential increases in gathering rates as
a result of capital expenditures.
ECA-3
Regulations
Affecting Marketing and Transportation
As a purchaser of natural gas, the Company depends on the
transportation, gathering and storage services offered by
various interstate and intrastate pipeline companies for the
delivery and sale of its own natural gas supplies as well as
those it processes
and/or
markets for others. Both the performance of transportation and
storage services by interstate pipelines and the rates charged
for such services are subject to the jurisdiction of the Federal
Energy Regulatory Commission. In addition, the performance of
transportation, gathering and storage services by intrastate
pipelines and the rates charged for such services are subject to
the jurisdiction of state regulatory agencies.
Oil
and Gas Reserves
The following information relating to estimated reserve
quantities, reserve values and discounted future net revenues is
derived from, and qualified in its entirety by reference to, the
more complete reserve and revenue information and assumptions
included in the Companys Supplemental Oil and Gas
Disclosures in the Companys financial statements. The
Companys estimates of proved reserve quantities of its
properties have been subject to review by Ryder Scott Company,
independent petroleum engineers. In December 2008, the
Securities and Exchange Commission (the SEC)
announced that it had approved revisions to modernize its oil
and gas reserves reporting requirements. The following reserve
information was calculated based on the SEC reserve reporting
requirements in effect for the periods presented, which do not
give effect to the new SEC requirements. Accordingly, the
reserve information presented below is calculated based on
year-end pricing information. There are numerous uncertainties
inherent in estimating quantities of proved reserves and
projecting future rates of production and timing of development
expenditures. The following reserve information represents
estimates only and should not be construed as being exact.
Future reserve values are based on fiscal year-end prices except
in those instances where the sale of natural gas and oil is
covered by contract terms. Operating costs, production and ad
valorem taxes and future development costs are based on current
costs with no escalations. The table below does not give effect
to derivative transactions.
The following table sets forth the Companys estimated
proved and proved developed reserves and the related estimated
future value, as of June 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net proved developed:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (MMcf)
|
|
|
170,625
|
|
|
|
174,396
|
|
|
|
143,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
475
|
|
|
|
379
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
173,474
|
|
|
|
176,672
|
|
|
|
145,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Price ($/Mcf)
|
|
|
7.43
|
|
|
|
14.41
|
|
|
|
3.88
|
|
Future net cash flows before discount (in thousands)
|
|
$
|
737,309
|
|
|
$
|
1,362,849
|
|
|
$
|
370,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows related to proved developed oil
and gas reserves (in thousands) (1)
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
153,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Discounted using an annual discount
rate of 10%.
|
ECA-4
The following table sets forth the Companys estimated
proved reserves and the related estimated present value by
region, as of June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Percent of Proved
|
|
|
Present Value
|
|
Region
|
|
(MMcf)
|
|
|
(Mbbls)
|
|
|
Equivalent (MMcfe)
|
|
|
Developed Reserves
|
|
|
(Thousands)
|
|
|
Appalachian Basin
|
|
$
|
140,080
|
|
|
|
249
|
|
|
|
141,574
|
|
|
|
97.6
|
%
|
|
$
|
147,129
|
|
Western
|
|
|
3,087
|
|
|
|
73
|
|
|
|
3,525
|
|
|
|
2.4
|
%
|
|
|
6,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
143,167
|
|
|
|
322
|
|
|
|
145,099
|
|
|
|
100.0
|
%
|
|
$
|
153,646
|
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Estimated future net revenue
represents the estimated future gross revenue to be generated
from the production of proved developed reserves, net of
estimated production and future development costs, using prices
and costs under existing economic conditions at June 30,
2009. Prices were determined by applying period-end prices of
oil and natural gas relating to the Company in accordance with
the SECs ruling in effect as of June 30, 2009, and do
not give effect to any derivative transactions. This price
should not be interpreted as a prediction of future prices, nor
does it reflect the value of commodity hedges in place at
June 30, 2009. The amounts shown do not give effect to
non-property related expenses, such as corporate general and
administrative expenses and debt service, or to depreciation,
depletion and amortization.
|
Producing
Wells
The following table sets forth certain information relating to
productive wells at June 30, 2009. Wells are classified as
oil or natural gas according to their predominant production
stream.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Wells
|
|
|
Net Wells
|
|
Region
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Appalachian Basin
|
|
|
50
|
|
|
|
5,094
|
|
|
|
5,144
|
|
|
|
35.4
|
|
|
|
3,527.9
|
|
|
|
3,563.3
|
|
Western
|
|
|
|
|
|
|
24
|
|
|
|
24
|
|
|
|
0
|
|
|
|
11.3
|
|
|
|
11.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
50
|
|
|
|
5,118
|
|
|
|
5,168
|
|
|
|
35.4
|
|
|
|
3,539.2
|
|
|
|
3,574.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acreage
The following table sets forth the developed and undeveloped
gross and net acreage held at June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage
|
|
|
Undeveloped Acreage
|
|
Region
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Appalachian Basin
|
|
|
836,277
|
|
|
|
766,676
|
|
|
|
189,405
|
|
|
|
163,993
|
|
Western
|
|
|
21,709
|
|
|
|
9,356
|
|
|
|
22,892
|
|
|
|
15,248
|
|
New Zealand
|
|
|
|
|
|
|
|
|
|
|
1,732,209
|
|
|
|
1,555,776
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
857,986
|
|
|
|
776,032
|
|
|
|
1,944,506
|
|
|
|
1,735,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-5
Production
The following table sets forth certain net production data and
average wellhead sales prices attributable to the Companys
properties for the years ended June 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
2008
|
|
2009
|
|
Production data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
83
|
|
|
|
65
|
|
|
|
47
|
|
Natural gas (MMcf)
|
|
|
9,138
|
|
|
|
10,294
|
|
|
|
9,364
|
|
Average sales price (before the effect of hedging):
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$
|
60.10
|
|
|
$
|
92.37
|
|
|
$
|
64.98
|
|
Natural gas per Mcf
|
|
$
|
7.01
|
|
|
$
|
8.53
|
|
|
$
|
6.76
|
|
Drilling
Activities
The Companys natural gas and oil exploratory and
developmental drilling activities are as follows for the years
ended June 30. The number of wells drilled refers to the
number of wells commenced at any time during the respective
fiscal year. A well is considered productive if it justifies the
installation of permanent equipment for the production of
natural gas or oil.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
93
|
|
|
|
80.3
|
|
|
|
93
|
|
|
|
82.1
|
|
|
|
24
|
|
|
|
19.5
|
|
Western/New Zealand
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
95
|
|
|
|
82.1
|
|
|
|
95
|
|
|
|
83.9
|
|
|
|
24
|
|
|
|
19.5
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western/New Zealand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
5
|
|
|
|
4.5
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.4
|
|
Western/New Zealand
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5
|
|
|
|
4.5
|
|
|
|
2
|
|
|
|
1.8
|
|
|
|
2
|
|
|
|
1.4
|
|
Nonproductive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Appalachian
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western/New Zealand
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
101
|
|
|
|
87.6
|
|
|
|
98
|
|
|
|
86.4
|
|
|
|
26
|
|
|
|
20.9
|
|
ECA-6
Selected
Consolidated Financial Data of Energy Corporation Of
America
The following selected consolidated statements of operations
data of Energy Corporation of America and its subsidiaries for
each of the three years in the period ended June 30, 2009
and the selected consolidated balance sheet data for Energy
Corporation of America and its subsidiaries as of June 30,
2008 and 2009 are derived from the audited consolidated
financial statements of Energy Corporation of America and its
subsidiaries included elsewhere in this prospectus. The
following selected consolidated statement of operations data for
the six months ended December 31, 2008 and 2009 and the
selected consolidated balance sheet data as of December 31,
2008 and 2009 are derived from the unaudited consolidated
financial statements of Energy Corporation of America and its
subsidiaries included elsewhere in this prospectus. The selected
consolidated balance sheet data presented as of June 30,
2008 has been derived from the audited consolidated financial
statements of Energy Corporation of America and its
subsidiaries, which are not included in this prospectus. The
information in the table should be read in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations of Energy Corporation of
America beginning on
page ECA-8
of this prospectus and the consolidated financial statements of
Energy Corporation of America and its subsidiaries, related
notes and other financial information included elsewhere in this
prospectus.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
Six Months Ended December 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share data)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
|
$
|
45,703
|
|
|
$
|
44,012
|
|
Gas aggregation and pipeline sales
|
|
|
120,549
|
|
|
|
142,825
|
|
|
|
116,730
|
|
|
|
75,655
|
|
|
|
37,240
|
|
Well operations and service revenues
|
|
|
6,976
|
|
|
|
7,732
|
|
|
|
7,228
|
|
|
|
3,752
|
|
|
|
3,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,954
|
|
|
|
247,071
|
|
|
|
216,220
|
|
|
|
125,110
|
|
|
|
85,040
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
17,700
|
|
|
|
18,234
|
|
|
|
18,772
|
|
|
|
9,754
|
|
|
|
9,085
|
|
Gas aggregation and pipeline cost of sales
|
|
|
110,226
|
|
|
|
131,051
|
|
|
|
104,685
|
|
|
|
68,678
|
|
|
|
31,867
|
|
General and administrative
|
|
|
17,742
|
|
|
|
17,933
|
|
|
|
18,858
|
|
|
|
9,417
|
|
|
|
8,678
|
|
Taxes, other than income
|
|
|
4,519
|
|
|
|
5,406
|
|
|
|
4,629
|
|
|
|
3,022
|
|
|
|
395
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
|
|
11,496
|
|
|
|
17,179
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
|
|
2,999
|
|
|
|
3,148
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
|
|
9,878
|
|
|
|
10,460
|
|
(Gain) on sale of assets
|
|
|
(10,454
|
)
|
|
|
(7,287
|
)
|
|
|
(9,114
|
)
|
|
|
(5,612
|
)
|
|
|
(7,761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,296
|
|
|
|
195,159
|
|
|
|
185,870
|
|
|
|
109,632
|
|
|
|
73,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
40,658
|
|
|
|
51,912
|
|
|
|
30,350
|
|
|
|
15,478
|
|
|
|
11,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
Six Months Ended December 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands, except per share data)
|
|
|
Other (income) and expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
|
|
5,366
|
|
|
|
4,796
|
|
Interest income (expense) and other
|
|
|
8,547
|
|
|
|
21,884
|
|
|
|
(18,722
|
)
|
|
|
(17,317
|
)
|
|
|
3,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,792
|
|
|
|
32,572
|
|
|
|
(8,736
|
)
|
|
|
(11,951
|
)
|
|
|
8,452
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations before income taxes
|
|
|
23,866
|
|
|
|
19,340
|
|
|
|
39,086
|
|
|
|
27,429
|
|
|
|
3,537
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
|
|
12,513
|
|
|
|
1,868
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
$
|
14,916
|
|
|
$
|
1,669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted:
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
$
|
25.39
|
|
|
$
|
2.85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
$
|
347,617
|
|
|
$
|
451,742
|
|
|
$
|
479,722
|
|
|
$
|
455,876
|
|
|
$
|
478,768
|
|
Total assets
|
|
|
413,321
|
|
|
|
557,980
|
|
|
|
543,719
|
|
|
|
538,501
|
|
|
|
534,025
|
|
Working capital deficiency
|
|
|
(41,155
|
)
|
|
|
(78,179
|
)
|
|
|
(23,997
|
)
|
|
|
(10,165
|
)
|
|
|
(17,515
|
)
|
Long term debt excluding current maturities
|
|
|
135,166
|
|
|
|
197,125
|
|
|
|
218,134
|
|
|
|
213,490
|
|
|
|
237,779
|
|
Stockholders equity
|
|
|
69,891
|
|
|
|
24,666
|
|
|
|
100,935
|
|
|
|
99,645
|
|
|
|
89,859
|
|
ECA-8
Managements
Discussion and Analysis of Financial Condition
and Results of Operation of Energy Corporation of
America
The following discussion should be read in conjunction with the
consolidated financial statements and the related notes thereto
of Energy Corporation of America and its subsidiaries appearing
elsewhere in this prospectus.
Safe
Harbor Statement Under the Private Securities Litigation Reform
Act of 1995
This discussion and analysis of financial condition and results
of operations, and other sections of this prospectus, contain
forward-looking statements that are based on managements
beliefs, assumptions, current expectations, estimates,
intentions and projections about the oil and natural gas
industry, the economy and about the Company itself. Words such
as anticipates, believes,
estimates, expects,
forecasts, intends, is
likely, plans, predicts,
projects, variations of such words and similar
expressions are intended to identify such forward-looking
statements under the Private Securities Litigation Reform Act of
1995. The Company cautions that these statements are not
guarantees of future performance and involve certain risks,
uncertainties and assumptions that are difficult to predict with
regard to timing, extent, likelihood and degree of occurrence.
Therefore, actual results and outcomes may materially differ
from what may be expressed or forecasted in such forward-looking
statements. Furthermore, the Company undertakes no obligation to
update, amend or clarify forward-looking statements, whether as
a result of new information, future events or otherwise.
Important factors that could cause actual results to differ
materially from the forward-looking statements include, but are
not limited to, weather conditions, changes in production
volumes, worldwide demand and commodity prices for petroleum
natural resources, the timing and extent of the Companys
success in discovering, acquiring, developing and producing oil
and natural gas reserves, risks incident to the drilling and
operation of oil and natural gas wells, future production and
development costs, foreign currency exchange rates, the effect
of existing and future laws, governmental regulations and the
political and economic climate of the United States and New
Zealand, the effect of hedging activities, and conditions in the
capital markets.
The following should be read in conjunction with the
Companys selected consolidated financial statements and
the related notes (including the segment information) beginning
on
page ECA-23
of this prospectus.
Critical
Accounting Policies And Estimates
The discussion of financial condition and results of operation
are based upon the information reported in the consolidated
financial statements. The preparation of these financial
statements requires the Company to make assumptions and
estimates that affect the reported amounts of assets,
liabilities, revenues and expenses as well as the disclosure of
contingent assets and liabilities at the date of the financial
statements. Decisions are based on historical experience and
various other sources that are believed to be reasonable under
the circumstances. Actual results may differ from the estimates
due to changing business conditions or unexpected circumstances.
The Company believes the following policies are critical to
understanding our business and results of operations. For
additional information on significant accounting policies, see
Notes to Consolidated Financial Statements, particularly
Note 2.
Revenue Recognition
The Company is engaged in
the exploration, development, acquisition, production and
aggregation of natural gas and crude oil. The revenue
recognition policy is significant because it is a key component
of the results of operations and forward looking statements
contained in Liquidity and Capital Resources below.
Revenue is derived
ECA-9
primarily from the sale of produced natural gas and crude oil.
Revenue is recorded in the month production is delivered to the
purchaser, but payment is generally received between 30 and
90 days after the date of production. Monthly, the Company
makes estimates of the amount of production delivered to the
purchaser and the price to be received. The Company uses its
knowledge of properties, historical performance, NYMEX and local
spot market prices, and other factors as the basis for these
estimates. Variances between the estimates and the actual
amounts received, which historically have not been significant,
are recorded in the month revenue is distributed.
Derivative Instruments
The estimated fair
values of all derivative instruments are recorded on the
consolidated balance sheet. All of the derivative instruments
are entered into to mitigate risks related to the prices to be
received for future natural gas and oil production. Derivative
instruments are not used for trading purposes. Although
derivatives are reported on the balance sheet at fair value, to
the extent that instruments qualify for hedge accounting
treatment, changes in fair value are recorded, net of taxes,
directly to stockholders equity as a component of other
comprehensive income until the hedged oil or natural gas
quantities are produced. To the extent changes in the fair
values of derivatives relate to instruments not qualifying for
hedge accounting treatment, such changes are recorded in
operations in the period they occur. In determining the amounts
to be recorded, the Company is required to estimate the fair
values of derivatives. The estimates are based upon various
factors that include contract volumes and prices, contract
settlement dates, quoted closing prices on the NYMEX or
over-the-counter,
volatility and the time value of options. The estimated future
prices are compared to the prices fixed by the derivatives
agreements and the resulting estimated future cash inflows or
outflows over the lives of the hedges are discounted to
calculate the fair value of the derivative contracts. These
pricing and discounting variables are sensitive to market
volatility as well as changes in future price forecasts and
regional price differences. Periodically the valuations are
validated using independent third party quotations.
Reserve Estimates
The Companys estimate
of natural gas and oil reserves are projections based on
geologic and engineering data. There are uncertainties inherent
in the interpretation of such data as well as the projection of
future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of natural gas and oil that
are difficult to measure. The accuracy of any reserve estimate
is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of
economically recoverable natural gas and oil reserves and future
net cash flows depend upon a number of variable factors and
assumptions, such as expected future production rates, natural
gas and oil prices, operating costs, severance taxes, and
development costs, all of which may vary considerably from
actual results. Expected cash flows are reduced to present value
using a discount rate of 10%, as required by accounting
standards. Reserve estimates are inherently imprecise and
estimates of new discoveries are more imprecise than those of
proved producing oil and natural gas properties. Reserve
estimates are calculated based on the SEC reserve reporting
requirements in effect for the periods presented, which do not
give effect to the new SEC reserve reporting requirements.
Accordingly, reserve estimates are based on year-end pricing
information. The future drilling costs associated with reserves
assigned to proved undeveloped locations may ultimately increase
to an extent that these reserves may be determined to be
uneconomic. Any significant variance in the assumptions could
materially affect the estimated quantity and value of the
reserves, which could affect the carrying value of the
Companys natural gas and oil properties and their rates of
depletion. Changes in these calculations, caused by changes in
reserve quantities or net cash flows are recorded on a
prospective basis. Actual production, revenues and expenditures
with respect to the Companys reserves will likely vary
from estimates and such variances may be material.
ECA-10
Valuation Of Long-Lived and Intangible Assets
Property and equipment are recorded at cost. The carrying value
of property and equipment is reviewed for possible impairment
whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. Assets are determined to
be impaired if a forecast of undiscounted estimated future net
operating cash flows directly related to the asset, including
disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is
measured as the amount by which the carrying amount of the asset
exceeds its fair value. An estimate of fair value is based on
the best information available, including prices for similar
assets. Different pricing assumptions or discount rates would
result in a different calculated impairment.
Income Taxes
The Company provides for
deferred income taxes on the difference between the tax basis of
an asset or liability and its carrying amount in the financial
statements. This difference will result in taxable income or
deductions in future years when the reported amount of the asset
or liability is recovered or settled, respectively. Federal and
state income tax returns are generally not filed before the
consolidated financial statements are prepared, therefore an
estimate of the tax basis of assets and liabilities is
determined at the end of each period as well as the effects of
tax rate changes, tax credits and net operating loss
carryforwards. Adjustments related to differences between the
estimates and actual amounts are recorded in the period the
income tax returns are filed.
Comparison
of Results of Operations for the Years Ended June 30, 2009
and 2008
The Company realized net income of $21.7 million for the
year ended June 30, 2009 compared to net income of
$11.5 million for the year ended June 30, 2008. The
increase of $10.2 million was primarily attributable to the
net effect of a $30.9 million decrease in revenue, a
$9.3 million decrease in costs and expenses, a
$0.7 million decrease in interest expense, a
$40.6 million increase in interest and other income and a
$9.5 million increase in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the years ended June 30 and their
related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
10,294
|
|
|
|
9,364
|
|
|
|
(930
|
)
|
|
|
(9.0
|
)%
|
Average sales price received ($/Mcf)
|
|
$
|
8.53
|
|
|
$
|
6.76
|
|
|
$
|
(1.77
|
)
|
|
|
(20.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
87,816
|
|
|
$
|
63,339
|
|
|
$
|
(24,477
|
)
|
|
|
(27.9
|
)%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
65
|
|
|
|
47
|
|
|
|
(18
|
)
|
|
|
(27.7
|
)%
|
Average sales price received ($/Bbl)
|
|
$
|
92.37
|
|
|
$
|
64.98
|
|
|
$
|
(27.39
|
)
|
|
|
(29.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
6,004
|
|
|
$
|
3,054
|
|
|
$
|
(2,950
|
)
|
|
|
(49.1
|
)%
|
Hedging
|
|
|
2,417
|
|
|
|
25,602
|
|
|
|
23,185
|
|
|
|
959.2
|
%
|
Other
|
|
|
277
|
|
|
|
267
|
|
|
|
(10
|
)
|
|
|
(3.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales (in thousands)
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
|
$
|
(4,252
|
)
|
|
|
(4.4
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,607
|
|
|
|
13,165
|
|
|
|
558
|
|
|
|
4.4
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
8.73
|
|
|
$
|
6.99
|
|
|
$
|
(1.74
|
)
|
|
|
(19.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
110,029
|
|
|
$
|
92,003
|
|
|
$
|
(18,026
|
)
|
|
|
(16.4
|
)%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,863
|
|
|
|
11,906
|
|
|
|
(957
|
)
|
|
|
(7.4
|
)%
|
Average sales price received ($/MMBtu)
|
|
$
|
2.55
|
|
|
$
|
2.08
|
|
|
$
|
(0.47
|
)
|
|
|
(18.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
32,796
|
|
|
$
|
24,727
|
|
|
$
|
(8,069
|
)
|
|
|
(24.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
142,825
|
|
|
$
|
116,730
|
|
|
$
|
(26,095
|
)
|
|
|
(18.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,607
|
|
|
|
13,165
|
|
|
|
558
|
|
|
|
4.4
|
%
|
Average price paid ($/MMBtu)
|
|
$
|
8.49
|
|
|
$
|
6.74
|
|
|
$
|
(1.75
|
)
|
|
|
(20.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
107,058
|
|
|
$
|
88,767
|
|
|
$
|
(18,291
|
)
|
|
|
(17.1
|
)%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
3,407
|
|
|
|
2,828
|
|
|
|
(579
|
)
|
|
|
(17.0
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
7.04
|
|
|
$
|
5.63
|
|
|
$
|
(1.41
|
)
|
|
|
(20.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
23,993
|
|
|
$
|
15,918
|
|
|
$
|
(8,075
|
)
|
|
|
(33.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
131,051
|
|
|
$
|
104,685
|
|
|
$
|
(26,366
|
)
|
|
|
(20.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
.
Total revenues decreased
$30.9 million or 12.5% between the years. The decrease was
due to a 4.4% decrease in oil and natural gas sales, an 18.3%
decrease in natural gas aggregation and pipeline sales, and a
6.5% decrease in well operations and service revenues.
Revenues from oil and natural gas sales decreased
$4.2 million from $96.5 million for the year ended
June 30, 2008 to $92.3 million for the year ended
June 30, 2009. Natural gas sales decreased
$24.5 million and oil sales decreased $3.0 million
between such periods. The decreases are a result of a decrease
in both the average sales price received and production. The
price decline corresponds with the change in related indexes.
The decrease in production is primarily the result of the shut
in of certain properties due to low pricing conditions in
Montana and equipment failure on certain producing properties in
Texas. The decrease in production revenue was largely offset by
an increase in recognized gains on related derivative instrument
hedging transactions on natural gas and oil production which
totaled $25.6 million for the year ended June 30, 2009
as compared to a gain of $2.4 million for the year ended
June 30, 2008. The average price per Mcfe, after hedging,
was $9.56 and $9.03 for the years ended June 30, 2009 and
2008, respectively.
Revenues from natural gas aggregation and pipeline sales
decreased $26.1 million from $142.8 million during the
period ended June 30, 2008 to $116.7 million for the
period ended June 30, 2009. Gas aggregation revenue
decreased $18.0 million while pipeline revenue, which has a
sales and a transportation component, decreased
$8.1 million. The decrease in natural gas aggregation and
pipeline sales is attributable to the decline in average sales
price received and a decrease in pipeline volumes. The price
decrease corresponds with the decline in the related index price
of natural gas.
ECA-12
COSTS AND EXPENSES
.
The Companys costs
and expenses decreased $9.3 million or 4.8% between the
years. The net decrease was due to a 3.0% increase in field and
lease operating expenses, a 20.1% decrease in natural gas
aggregation and pipeline costs, a 5.2% increase in general and
administrative expenses, a 14.4% decrease in taxes other than
income, a 12.0% increase in oil and natural gas related
depletion, a 4.6% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 509.1% increase
in exploration and impairment costs, and an increase in the gain
on sale of property of 25.1%.
Field and lease operating expenses increased $0.5 million.
The increase is primarily related to an increase in utilities
and compressor rentals related to upgraded and new facilities
and natural gas transmission costs for recently drilled
properties.
Gas aggregation and pipeline costs decreased $26.4 million.
Gas aggregation cost decreased $18.3 million while pipeline
cost decreased by $8.1 million. The decrease in natural gas
aggregation cost is attributable to the decline in average
purchase price partially offset by an increase in volumes
aggregated during the period. The decrease in pipeline costs is
a result of a decrease in price and volumes. The decline in
price corresponds with the decrease in related indexes.
General and administrative expenses increased $0.9 million
primarily as a result of an increase in payroll and associated
tax costs.
Taxes other than income decreased $0.8 million primarily as
a result of decreased wellhead oil and natural gas sales.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $2.5 million due to an
increase in depletion rates recognized by the Company.
Exploration and impairment costs increased $15.4 million.
The increase is a result of higher expenses primarily related to
dry hole costs in New Zealand and various other geological and
geophysical costs.
Gain on sale of property increased $1.8 million primarily
as a result of an increase in incentive distributions related to
a certain term royalty conveyance.
INTEREST EXPENSE
.
Interest expense decreased
$0.7 million due to lower interest rates, offset partially
by an increase in outstanding borrowings.
INTEREST INCOME AND OTHER
.
Other
non-operating income increased by $40.6 million primarily
as a result of an increase in derivative
mark-to-market
adjustments and settlement gains.
INCOME TAX
.
Income tax expense increased
$9.5 million primarily as a result of the increase in
income before tax and due to the expiration of certain deferred
tax carryovers that could no longer be utilized.
Comparison
of Results of Operations for the Years Ended June 30, 2008
and 2007
The Company realized net income of $11.5 million for the
year ended June 30, 2008 compared to net income of
$19.1 million for the year ended June 30, 2007. The
decrease of $7.6 million was primarily attributable to the
net effect of a $35.1 million increase in revenue, a
ECA-13
$23.9 million increase in costs and expenses, a
$2.4 million increase in interest expense, a
$13.3 million increase in other expenses and a
$3.0 million increase in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the years ended June 30 and their
related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
|
|
|
|
|
June 30,
|
|
|
Variance
|
|
|
|
2007
|
|
|
2008
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
9,138
|
|
|
|
10,294
|
|
|
|
1,156
|
|
|
|
12.7
|
%
|
Average sales price received ($/Mcf)
|
|
$
|
7.01
|
|
|
$
|
8.53
|
|
|
$
|
1.52
|
|
|
|
21.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
64,024
|
|
|
$
|
87,816
|
|
|
$
|
23,792
|
|
|
|
37.2
|
%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
83
|
|
|
|
65
|
|
|
|
(18
|
)
|
|
|
(21.7
|
)%
|
Average sales price received ($/Bbl)
|
|
$
|
60.10
|
|
|
$
|
92.37
|
|
|
$
|
32.27
|
|
|
|
53.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
4,988
|
|
|
$
|
6,004
|
|
|
$
|
1,016
|
|
|
|
20.4
|
%
|
Hedging
|
|
|
15,201
|
|
|
|
2,417
|
|
|
|
(12,784
|
)
|
|
|
(84.1
|
)%
|
Other
|
|
|
216
|
|
|
|
277
|
|
|
|
61
|
|
|
|
28.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales (in thousands)
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
12,085
|
|
|
|
14.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,724
|
|
|
|
12,607
|
|
|
|
(117
|
)
|
|
|
(0.9
|
)%
|
Average sales price received ($/MMBtu)
|
|
$
|
7.27
|
|
|
$
|
8.73
|
|
|
$
|
1.46
|
|
|
|
20.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
92,500
|
|
|
$
|
110,029
|
|
|
$
|
17,529
|
|
|
|
19.0
|
%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
11,800
|
|
|
|
12,863
|
|
|
|
1,063
|
|
|
|
9.0
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
2.38
|
|
|
$
|
2.55
|
|
|
$
|
0.17
|
|
|
|
7.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
28,049
|
|
|
$
|
32,796
|
|
|
$
|
4,747
|
|
|
|
16.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
120,549
|
|
|
$
|
142,825
|
|
|
$
|
22,276
|
|
|
|
18.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
12,724
|
|
|
|
12,607
|
|
|
|
(117
|
)
|
|
|
(0.9
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
7.20
|
|
|
$
|
8.49
|
|
|
$
|
1.29
|
|
|
|
17.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
91,669
|
|
|
$
|
107,058
|
|
|
$
|
15,389
|
|
|
|
16.8
|
%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
4,422
|
|
|
|
3,407
|
|
|
|
(1,015
|
)
|
|
|
(23.0
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
4.20
|
|
|
$
|
7.04
|
|
|
$
|
2.84
|
|
|
|
67.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
18,557
|
|
|
$
|
23,993
|
|
|
$
|
5,436
|
|
|
|
29.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
110,226
|
|
|
$
|
131,051
|
|
|
$
|
20,825
|
|
|
|
18.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
.
Total revenues increased
$35.1 million or 16.6% between the years. The increase was
due to a 14.3% increase in oil and natural gas sales, an 18.5%
increase in natural gas aggregation and pipeline sales, and a
10.8% increase in well operations and service revenues.
Revenues from oil and natural gas sales increased
$12.1 million from $84.4 million for the year ended
June 30, 2007 to $96.5 million for the year ended
June 30, 2008. Natural gas sales increased
$23.8 million and oil sales $1.0 million. The increase
is a result of an increase in both average sales price received
and production. The price increase corresponds with the change
in related indexes. The increase in production is primarily the
result of new wells drilled and the reduction of shut-in volumes
compared to the prior period. The recognized gains on related
derivative instrument hedging transactions on natural gas and
oil production decreased by
ECA-14
$12.8 million from $15.2 million for the year ended
June 30, 2007 as compared to $2.4 million for the year
ended June 30, 2008. The average price per Mcfe, after
hedging, was $9.03 and $8.76 for the years ended June 30,
2008 and 2007, respectively.
Revenues from natural gas aggregation and pipeline sales
increased $22.3 million from $120.6 million during the
period ended June 30, 2007 to $142.8 million for the
period ended June 30, 2008. Gas aggregation revenue
increased $17.5 million while pipeline revenue, which has a
sales and a transportation component, increased
$4.8 million. The increase in natural gas aggregation and
pipeline sales is attributable to the increase in average sales
price received and an increase in pipeline volumes. The price
increase corresponds with the increase in the related index
price of natural gas.
COSTS AND EXPENSES
.
The Companys costs
and expenses increased $23.9 million or 13.9% between the
years. The net increase was due to a 3.0% increase in field and
lease operating expenses, an 18.9% increase in natural gas
aggregation and pipeline costs, a 1.1% increase in general and
administrative expenses, a 19.6% increase in taxes other than
income, a 15.6% increase in oil and natural gas related
depletion, an 18.0% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 64.3% decrease
in exploration and impairment costs, and a decrease in the gain
on sale of property of 30.3%.
Field and lease operating expenses increased $0.5 million.
The increase is primarily related to an increase in payroll and
associated tax costs and land delay rentals for newly acquired
acreage.
Gas aggregation and pipeline costs increased $20.8 million.
Gas aggregation cost increased $15.4 million while pipeline
cost increased by $5.4 million. The increase in natural gas
aggregation cost is attributable to the increase in average
purchase price during the period. The increase in pipeline costs
is a result of the increase in price and volumes. The increase
in price corresponds with the increase in related indexes.
Taxes other than income increased $0.9 million primarily as
a result of increased wellhead oil and natural gas sales.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $2.8 million as a result of
increased production and a higher depletion rate.
Depletion, depreciation and amortization of pipelines, property
and equipment expense increased $0.9 million due to a
change in the estimated useful life for certain pipeline assets
and the acquisition of other fixed assets.
Exploration and impairment costs decreased $5.5 million.
The decrease is a result of a reduction in impairment expense
and various other geological and geophysical costs.
Gain on sale of property decreased $3.2 million primarily
due to the sale of certain properties during the year ended
June 30, 2007.
INTEREST EXPENSE
.
Interest expense increased
$2.4 million primarily due to an increase in outstanding
borrowings for the year ended June 30, 2008.
INTEREST INCOME AND OTHER
.
Other
non-operating expense increased by $13.3 million primarily
as a result of an increase in derivative
mark-to-market
adjustments and settlement losses for the year ended
June 30, 2008.
ECA-15
INCOME TAX
.
Income tax expense increased
$3.0 million primarily as a result of recording a tax
benefit during the year ended June 30, 2007 for expiring
tax contingency items.
Comparison
of Results of Operations for the Six Months Ended
December 31, 2009 and 2008
The Company realized net income of $1.7 million for the six
months ended December 31, 2009 compared to net income of
$14.9 million for the six months ended December 31,
2008. The decrease of $13.2 million was primarily
attributable to the net effect of a $40.1 million decrease
in revenue, a $36.6 million decrease in costs and expenses,
a $0.6 decrease in interest expense, a $21.0 million
decrease in interest and other income and a $10.6 million
decrease in income tax expense.
Production, aggregation and pipeline volumes, revenue and
average sales prices for the six months ended December 31 and
their related variances are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMcf)
|
|
|
4,709
|
|
|
|
5,314
|
|
|
|
605
|
|
|
|
12.8
|
%
|
Average sales price received ($/Mcf)
|
|
$
|
9.14
|
|
|
$
|
3.78
|
|
|
$
|
(5.36
|
)
|
|
|
(58.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
43,047
|
|
|
$
|
20,076
|
|
|
$
|
(22,971
|
)
|
|
|
(53.4
|
)%
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MBbl)
|
|
|
23
|
|
|
|
25
|
|
|
|
2
|
|
|
|
8.7
|
%
|
Average sales price received ($/Bbl)
|
|
$
|
85.43
|
|
|
$
|
63.88
|
|
|
$
|
(21.55
|
)
|
|
|
(25.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
1,965
|
|
|
$
|
1,572
|
|
|
$
|
(393
|
)
|
|
|
(20.0
|
)%
|
Hedging
|
|
|
558
|
|
|
|
22,249
|
|
|
|
21,691
|
|
|
|
3887.3
|
%
|
Other
|
|
|
133
|
|
|
|
115
|
|
|
|
(18
|
)
|
|
|
(13.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales ($ in thousands)
|
|
$
|
45,703
|
|
|
$
|
44,012
|
|
|
$
|
(1,691
|
)
|
|
|
(3.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregation revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
6,481
|
|
|
|
6,924
|
|
|
|
443
|
|
|
|
6.8
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
9.14
|
|
|
$
|
4.30
|
|
|
$
|
(4.84
|
)
|
|
|
(53.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
59,245
|
|
|
$
|
29,768
|
|
|
$
|
(29,477
|
)
|
|
|
(49.8
|
)%
|
Pipeline revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
5,949
|
|
|
|
6,773
|
|
|
|
824
|
|
|
|
13.9
|
%
|
Average sales price received ($/MMBtu)
|
|
$
|
2.76
|
|
|
$
|
1.10
|
|
|
$
|
(1.66
|
)
|
|
|
(60.1
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales (in thousands)
|
|
$
|
16,410
|
|
|
$
|
7,472
|
|
|
$
|
(8,938
|
)
|
|
|
(54.5
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
75,655
|
|
|
$
|
37,240
|
|
|
$
|
(38,415
|
)
|
|
|
(50.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Variance
|
|
|
|
2008
|
|
|
2009
|
|
|
Amount
|
|
|
Percent
|
|
|
Aggregation gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
6,481
|
|
|
|
6,924
|
|
|
|
443
|
|
|
|
6.8
|
%
|
Average price paid ($/MMBtu)
|
|
$
|
8.87
|
|
|
$
|
4.05
|
|
|
$
|
(4.82
|
)
|
|
|
(54.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
57,463
|
|
|
$
|
28,034
|
|
|
$
|
(29,429
|
)
|
|
|
(51.2
|
)%
|
Pipeline gas cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Million MMBtu)
|
|
|
1,489
|
|
|
|
1,239
|
|
|
|
(250
|
)
|
|
|
(16.8
|
)%
|
Average price paid ($/MMBtu)
|
|
$
|
7.53
|
|
|
$
|
3.09
|
|
|
$
|
(4.44
|
)
|
|
|
(59.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost (in thousands)
|
|
$
|
11,215
|
|
|
$
|
3,833
|
|
|
$
|
(7,382
|
)
|
|
|
(65.8
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total aggregation and pipeline sales (in thousands)
|
|
$
|
68,678
|
|
|
$
|
31,867
|
|
|
$
|
(36,811
|
)
|
|
|
(53.6
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
REVENUES
.
Total revenues decreased
$40.1 million or 32.0% between the periods. The decrease
was due to a 3.7% decrease in oil and natural gas sales, a 50.8%
decrease in natural gas aggregation and pipeline sales, and a
1.0% increase in well operations and service revenues.
Revenues from oil and natural gas sales decreased
$1.7 million from $45.7 million for the six months
ended December 31, 2008 to $44.0 million for the six
months ended December 31, 2009. Natural gas sales decreased
$23.0 million and oil sales decreased $0.4 million.
The decrease in natural gas sales is a result of a decrease in
the average sales price received and was partially offset by an
increase in production. The price decline corresponds with the
change in related indexes. The increase in production is
primarily the result of new wells drilled and the reduction of
shut-in volumes compared to the prior period. The decrease in
production revenue was largely offset by an increase in
recognized gains on related derivative instrument hedging
transactions on natural gas and oil production which totaled
$22.2 million for the six months ended December 31,
2009 as compared to a gain of $0.6 million for the six
months ended December 31, 2008. The average price per Mcfe,
after hedging, was $7.95 and $9.38 for the six months ended
December 31, 2009 and 2008, respectively.
Revenues from natural gas aggregation and pipeline sales
decreased $38.4 million from $75.7 million during the
period ended December 31, 2008 to $37.2 million for
the period ended December 31, 2009. Gas aggregation revenue
decreased $29.5 million while pipeline revenue, which has a
sales and a transportation component, decreased
$8.9 million. The decrease in natural gas aggregation and
pipeline sales is attributable to the decline in average sales
price received and was partially offset by an increase volumes.
The price decrease corresponds with the decline in the related
index price of natural gas.
COSTS AND EXPENSES
.
The Companys costs
and expenses decreased $36.6 million or 33.4% between the
periods. The net decrease was due to a 6.9% decrease in field
and lease operating expenses, a 53.6% decrease in natural gas
aggregation and pipeline costs, a 7.9% decrease in general and
administrative expenses, an 86.9% decrease in taxes other than
income, a 49.4% increase in oil and natural gas related
depletion, a 5.0% increase in depreciation and amortization
expenses of pipelines, property and equipment, a 5.9% increase
in exploration and impairment costs, and an increase in the gain
on sale of property of 38.3%.
Field and lease operating expenses decreased $0.7 million.
The decrease is primarily related to the elimination of certain
compressors and related equipment and the dismantling of an
amine plant previously operated by the Company.
ECA-17
Gas aggregation and pipeline costs decreased $36.8 million.
Gas aggregation cost decreased $29.4 million while pipeline
cost decreased by $7.4 million. The decrease in natural gas
aggregation cost is attributable to the decline in average
purchase price partially offset by an increase in volumes
aggregated during the period. The decrease in pipeline costs is
a result of a decrease in price and volumes. The decline in
price corresponds with the decrease in related indexes.
General and administrative expenses decreased $0.7 million
primarily as a result of a decrease in employee related benefits
as well as a reduction in legal fees.
Taxes other than income decreased $2.6 million primarily as
a result of decreased wellhead oil and natural gas sales and
certain wells being classified as exempt from severance taxes.
Depletion, depreciation and amortization of oil and natural gas
properties expense increased $5.7 million due to an
increase in production and depletion rates recognized by the
Company.
Exploration and impairment costs increased $0.6 million.
The increase is a result of higher expenses primarily related to
lease expirations which was partially offset by a decrease in
dry hole cost and geological and geophysical cost.
Gain on sale of property increased $2.1 million primarily
as a result of the sale of a working interest in certain New
Zealand properties. This increase was partially offset by a
decrease in incentive distributions related to a certain term
royalty conveyance.
INTEREST EXPENSE
.
Interest expense decreased
$0.6 million due to lower interest rates, offset partially
by an increase in outstanding borrowings.
INTEREST INCOME AND OTHER
.
Other
non-operating income decreased by $21.0 million primarily
as a result of an increase in derivative
mark-to-market
and settlement gains.
INCOME TAX
.
Income tax expense decreased
$10.6 million primarily as a result of the decrease in
income before tax.
Liquidity
and Capital Resources
Stockholders equity has decreased from $100.9 million
at June 30, 2009 to $89.9 million at December 31,
2009. The Companys cash decreased from $2.0 million
at June 30, 2009 to $(0.1) million at
December 31, 2009. The change in cash during the six months
of approximately $2.1 million resulted from various
operating, investing and financing activities of the Company.
The activities were primarily comprised of the net borrowing of
$19.6 million under the Companys revolving credit
facility; the investment of approximately $29.6 million;
proceeds from the sale of assets of approximately
$4.9 million; payments of approximately $3.7 million
for the payment of dividends; and approximately
$6.7 million of cash provided by operations during the six
months.
The Company entered into a First Amendment to Second Amended and
Restated Credit Agreement effective August 4, 2008 (the
Credit Agreement), with Wells Fargo Foothill, Inc.
(Foothill), Bank of America, N.A. and U.S. Bank
National Association. The credit facility provides for a Maximum
Loan Amount of $250 million, consisting of a revolving
facility of $150 million and a single advance term loan of
$100 million, which is an increase of $50 million on
the revolving facility from June 30, 2008. The term loan
contains requirements for principal payments of $1 million
each at July 10, 2009, 2010, and 2011 and the Maturity Date
of the Credit
ECA-18
Agreement is July 10, 2012. At December 31, 2009, the
Company classified $1 million of the term loan that is due
on July 10, 2010 as long-term debt as a result of having a
Credit Agreement in place that allowed the Company to refinance
the debt on a long-term basis. Depending on the Companys
level of borrowing under the Credit Agreement, the applicable
interest rates for base rates are based on Wells Fargos
prime rate minus 0.25% to plus 0.25%. The Company also has the
ability under the Credit Agreement to designate certain loans as
LIBOR Rate Loans at interest rates based upon the rate at which
dollar deposits are offered to major banks in the London
interbank market plus 1.50% to 2.00%.
The obligations under the Credit Agreement are secured by
certain of the existing proved producing oil and natural gas
assets of the Company. The Credit Agreement, among other things,
restricts the ability of the Company and its subsidiaries to
incur new debt, grant additional security interests in its
collateral, engage in certain merger or reorganization
activities, or dispose of certain assets.
The Company has an unsecured revolving line of credit totaling
$2.0 million with a financial institution with a variable
interest rate equal to 3.50% in excess of the LIBOR
Rate the interest rate fixed by the British Bankers
Association at 11:00 a.m., London time, relating to
quotations for the one month London InterBank Offered Rates on
U.S. Dollar deposits as published on Bloomberg LP (or any
successor). As of December 31, 2009, there was no
outstanding balance on this line of credit.
At December 31, 2009, the Companys principal source
of liquidity consisted of $2.0 million available under an
unsecured credit facility currently in place, plus amounts
available under the revolving loan of the Credit Agreement. At
December 31, 2009, no amounts were outstanding or committed
through letters of credit under the credit facility,
$120.2 million was outstanding on the revolving loan and
$99.0 million was outstanding on the term loan under the
Credit Agreement.
As of March 17, 2010, there was $99.0 million in
outstanding borrowings under the term loan, $124.6 million
in outstanding borrowings under the revolving loan, and
$1.0 million in outstanding borrowings under the unsecured
revolving line of credit. Additional borrowings must comply with
the terms of the Credit Agreement.
Management utilizes earnings before interest, taxes,
depreciation, depletion, amortization and exploration and
impairment cost (EBITDAX) to evaluate the operation
of each business segment.
ECA-19
Reconciliation of the non-GAAP financial measure is as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Depreciation of property, plant and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
Unrealized (gain) loss on financial instruments
|
|
|
923
|
|
|
|
16,887
|
|
|
|
(18,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
64,597
|
|
|
$
|
76,737
|
|
|
$
|
78,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys net cash requirements will fluctuate based on
timing and the extent of the interplay of capital expenditures,
cash generated by operations, cash generated by the sale of
assets and interest expense. Management believes that cash
generated from oil and natural gas operations, together with the
liquidity provided by existing cash balances and permitted
borrowings, will be sufficient to satisfy commitments for
capital expenditures of $83.0 million, debt service
obligations, working capital needs and other cash requirements
for the current fiscal year.
The Company believes that its existing capital resources and its
expected results of operations and cash flows from operating
activities will be sufficient for the Company to remain in
compliance with the requirements of its Credit Agreement.
The Credit Agreement requires the Company to maintain certain
financial covenants. The Company is required to maintain a
minimum EBITDAX (as defined in the Credit Agreement) of
$55.0 million at the close of each fiscal quarter.
Compliance with the EBITDAX covenant is tested quarterly on a
rolling four quarter basis. The Company also is required to
maintain a Net Book Worth (as defined in the Credit Agreement)
of at least $37.0 million at the close of each fiscal
quarter (excluding all unrealized losses over all unrealized
profits arising under hedging agreements). Compliance with the
Book Net Worth covenant is tested quarterly.
At December 31, 2009 EBITDAX was $76,400,000. At
December 31, 2009 Book Net Worth was $90,800,000. However,
since future results of operations, cash flow from operating
activities, debt service capability, levels and availability of
capital resources and continuing liquidity are dependent on
future weather patterns, oil and natural gas prices and
production volume levels, future exploration and development
drilling success and successful acquisition transactions, no
assurance can be given that the Company will remain in
compliance with the requirements of its Credit Agreement.
ECA-20
Quantitative
and Qualitative Disclosures about Market Risk
Commodity
Risk
The Companys operations consist primarily of exploring
for, producing, gathering, aggregating and selling natural gas
and oil. Contracts to deliver natural gas at pre-established
prices mitigate the risk to the Company of falling prices but at
the same time limit the Companys ability to benefit from
the effects of rising prices. The Company strategically uses
derivative instruments to hedge commodity price risk. The
Company hedges a portion of its projected natural gas production
through a variety of financial and physical arrangements
intended to support natural gas prices at targeted levels and to
manage its exposure to price fluctuations. The Company may use
futures contracts, swaps, options and fixed price physical
contracts to hedge commodity prices. Realized gains and losses
from the Companys price risk management activities are
recognized in oil and natural gas sales when the associated
production occurs. Unrecognized gains and losses are included as
a component of other comprehensive income. Ineffectiveness is
recorded in current earnings. The Company does not hold or issue
derivative instruments for trading purposes. The Company
currently has elected to enter into derivative hedge
transactions on its estimated production covering approximately
20% to 30% for the fiscal year ending June 30, 2011 and 20%
to 30% for the fiscal year ending June 30, 2012. As of
December 31, 2009, the Companys open natural gas
derivative instruments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Total Volumes
|
|
|
Contract/Strike
|
|
|
Unrealized
|
|
|
|
Market Index
|
|
|
(MMBtu)
|
|
|
Price
|
|
|
(Gain)
|
|
|
Time period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2010 March 2010
|
|
|
NYMEX
|
|
|
|
540,000
|
|
|
$
|
8.68
|
|
|
$
|
(1,627,977
|
)
|
January 2010 March 2010
|
|
|
NYMEX
|
|
|
|
360,000
|
|
|
|
9.03
|
|
|
|
(1,210,363
|
)
|
January 2010 March 2010
|
|
|
NYMEX
|
|
|
|
540,000
|
|
|
|
9.04
|
|
|
|
(1,820,904
|
)
|
January 2010 June 2010
|
|
|
NYMEX
|
|
|
|
1,357,500
|
|
|
|
8.83
|
|
|
|
(4,311,174
|
)
|
April 2010 June 2010 (1)
|
|
|
NYMEX
|
|
|
|
728,000
|
|
|
|
9.20
|
|
|
|
(2,582,934
|
)
|
April 2010 June 2010 (1)
|
|
|
NYMEX
|
|
|
|
227,500
|
|
|
|
10.00
|
|
|
|
(984,306
|
)
|
July 2010 June 2011 (2)
|
|
|
NYMEX
|
|
|
|
547,500
|
|
|
|
6.59
|
|
|
|
(220,075
|
)
|
July 2010 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
2,193,000
|
|
|
|
6.54
|
|
|
|
(485,848
|
)
|
July 2010 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
2,193,000
|
|
|
|
7.03
|
|
|
|
(1,449,050
|
)
|
July 2011 June 2012 (2)
|
|
|
NYMEX
|
|
|
|
549,000
|
|
|
|
6.94
|
|
|
|
(238,058
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Hedged Production
|
|
|
|
|
|
|
9,235,500
|
|
|
|
|
|
|
$
|
(14,930,689
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Natural gas swaps attributable to
approximately 682,500 MMBtu of gas will be conveyed to the
trust at the closing of this offering at an average contract
price of $6.75 per MMBtu.
|
|
(2)
|
|
All such natural gas swaps will be
conveyed to the trust at the closing of this offering.
|
Notwithstanding the above, the Companys future cash flows
from natural gas and oil production are exposed to significant
volatility as commodity prices change. Assuming total oil and
natural gas production, pricing, and the percentage of natural
gas production hedged under physical delivery contracts and
derivative instruments remain at December 2009 levels, a 10%
change in the average unhedged prices realized would change the
Companys natural gas and oil revenues by approximately
$0.3 million on a quarterly basis.
ECA-21
Interest
Rate Risk
Interest rate risk is attributable to the Companys debt.
The Company utilizes United States dollar denominated borrowings
to fund working capital and investment needs. There is inherent
rollover risk for borrowings as they mature and are renewed at
current market rates. The extent of this risk is not predictable
because of the variability of future interest rates and the
Companys future financing needs. During November 2007 and
January 2008, the Company entered into three interest rate swap
agreements with Foothill, in an effort to reduce the potential
impact of increases in interest rates on floating-rate long-term
debt. The three-year agreements cover $100 million in
long-term debt and fix the one-month London Interbank Offered
Rate (LIBOR) over a range of 3.67%
4.05%. The Company has partially hedged its exposure to the
variability in future cash flows through January 2011. Assuming
the variable interest debt remain at the December 31, 2009
level, a 10% change in rates would have a $0.03 million
impact on interest expense on an annual basis.
Foreign
Currency Exchange Risk
Some of the Companys transactions are denominated in New
Zealand dollars. For foreign operations with the local currency
as the functional currency, assets and liabilities are
translated at the period end exchange rates, and statements of
income are translated at the average exchange rates during the
period. Gains and losses resulting from foreign currency
translation are included as a component of other comprehensive
income.
LEGAL
PROCEEDINGS
The Company is involved in legal actions and claims arising in
the ordinary course of business. While the outcome of these
lawsuits against the Company cannot be predicted with certainty,
management does not expect these matters to have a material
adverse effect on the Companys operations or financial
position.
ECA-22
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Pages
|
HISTORICAL CONSOLIDATED FINANCIAL STATEMENTS OF ENERGY
CORPORATION OF AMERICA
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
ECA-24
|
|
Consolidated Balance Sheets as of June 30, 2008 and 2009
|
|
|
ECA-25
|
|
Consolidated Statements of Operations for the Years Ended
June 30, 2007, 2008 and 2009
|
|
|
ECA-27
|
|
Consolidated Statements of Stockholders Equity for the
Years Ended June 30, 2007, 2008 and 2009
|
|
|
ECA-28
|
|
Consolidated Statements of Cash Flows for the Years Ended
June 30, 2007, 2008 and 2009
|
|
|
ECA-29
|
|
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended June 30, 2007, 2008 and 2009
|
|
|
ECA-30
|
|
Notes to Consolidated Financial Statements
|
|
|
ECA-31
|
|
UNAUDITED INTERIM FINANCIAL STATEMENTS OF ENERGY CORPORATION OF
AMERICA
|
|
|
|
|
Consolidated Balance Sheets as of June 30, 2009 and
December 31, 2009 (unaudited)
|
|
|
ECA-54
|
|
Unaudited Consolidated Statements of Operations for the Six
Months Ended December 31, 2008 and 2009
|
|
|
ECA-56
|
|
Unaudited Consolidated Statements of Cash Flows for the Six
Months Ended December 31, 2008 and 2009
|
|
|
ECA-57
|
|
Unaudited Consolidated Statements of Comprehensive Income (Loss)
for the Six Months Ended December 31, 2008 and 2009
|
|
|
ECA-58
|
|
Notes to Unaudited Consolidated Financial Statements for the
Periods Ended December 31, 2008 and 2009
|
|
|
ECA-59
|
|
ECA-23
Report of
Independent Registered Public Accounting Firm
The Board of
Directors and Stockholders
Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of
Energy Corporation of America and subsidiaries (the Company) as
of June 30, 2009 and 2008, and the related consolidated
statements of operations, stockholders equity, cash flows,
and comprehensive income (loss) for each of the three years in
the period ended June 30, 2009. These financial statements
are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards of
the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement. We were not
engaged to perform an audit of the Companys internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Companys internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
financial position of Energy Corporation of America and
subsidiaries at June 30, 2009 and 2008, and the
consolidated results of their operations and cash flows for each
of the three years in the period ended June 30, 2009 in
conformity with U.S. generally accepted accounting
principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 12, 2010
ECA-24
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Financial Statements for the Years Ended June 30, 2009,
2008 and 2007
CONSOLIDATED
BALANCE SHEETS
AS OF JUNE 30
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
6,988
|
|
|
$
|
1,979
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
13,488
|
|
|
|
3,110
|
|
Gas aggregation and pipeline
|
|
|
27,054
|
|
|
|
8,040
|
|
Other
|
|
|
13,319
|
|
|
|
5,140
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
53,861
|
|
|
|
16,290
|
|
Less allowances for doubtful accounts
|
|
|
(833
|
)
|
|
|
(737
|
)
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net of allowances
|
|
|
53,028
|
|
|
|
15,553
|
|
Inventory
|
|
|
1,883
|
|
|
|
4,752
|
|
Income taxes receivable
|
|
|
1,973
|
|
|
|
1,884
|
|
Deferred income tax asset
|
|
|
2,440
|
|
|
|
1,359
|
|
Deferred taxes other comprehensive loss
|
|
|
25,307
|
|
|
|
|
|
Notes receivable, related party
|
|
|
172
|
|
|
|
70
|
|
Derivatives
|
|
|
593
|
|
|
|
30,640
|
|
Prepaid and other current assets
|
|
|
1,041
|
|
|
|
574
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
93,425
|
|
|
|
56,811
|
|
NET PROPERTY, PLANT AND EQUIPMENT (Note 2)
|
|
|
451,742
|
|
|
|
479,722
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS:
|
|
|
|
|
|
|
|
|
Deferred financing costs, less accumulated amortization of
$2,111 and $2,583
|
|
|
1,033
|
|
|
|
1,057
|
|
Deferred taxes other comprehensive loss
|
|
|
5,994
|
|
|
|
237
|
|
Notes receivable, related party
|
|
|
350
|
|
|
|
262
|
|
Derivatives
|
|
|
154
|
|
|
|
651
|
|
Other
|
|
|
5,282
|
|
|
|
4,979
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
12,813
|
|
|
|
7,186
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
557,980
|
|
|
$
|
543,719
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-25
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF
JUNE 30
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands, except share amounts)
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
46,982
|
|
|
$
|
32,417
|
|
Current portion of long-term debt
|
|
|
198
|
|
|
|
212
|
|
Current portion of non-recourse debt
|
|
|
442
|
|
|
|
470
|
|
Funds held for future distribution
|
|
|
36,293
|
|
|
|
13,620
|
|
Accrued taxes, other than income
|
|
|
13,042
|
|
|
|
10,838
|
|
Deferred taxes other comprehensive income
|
|
|
|
|
|
|
11,052
|
|
Deferred revenue
|
|
|
304
|
|
|
|
262
|
|
Deferred gain
|
|
|
7,483
|
|
|
|
6,992
|
|
Derivatives
|
|
|
66,037
|
|
|
|
3,331
|
|
Other current liabilities
|
|
|
823
|
|
|
|
1,614
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
171,604
|
|
|
|
80,808
|
|
LONG-TERM OBLIGATIONS:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
180,347
|
|
|
|
201,826
|
|
Non-recourse debt
|
|
|
16,778
|
|
|
|
16,308
|
|
Deferred revenue
|
|
|
919
|
|
|
|
655
|
|
Deferred gain
|
|
|
75,122
|
|
|
|
68,277
|
|
Deferred income tax liability
|
|
|
37,210
|
|
|
|
53,609
|
|
Derivatives
|
|
|
30,145
|
|
|
|
1,237
|
|
Other long-term obligations
|
|
|
21,189
|
|
|
|
20,064
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
533,314
|
|
|
|
442,784
|
|
COMMITMENTS AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Common stock, par value $1.00; 2,000 shares authorized;
730,039 shares issued and 520,712 outstanding
|
|
|
730
|
|
|
|
730
|
|
Class A non-voting common stock, no par value;
100,000 shares authorized; 91,982 and 91,224 shares
issued and 64,276 and 65,895 shares outstanding
|
|
|
9,452
|
|
|
|
9,787
|
|
Additional paid-in capital
|
|
|
5,503
|
|
|
|
5,503
|
|
Retained earnings
|
|
|
82,043
|
|
|
|
96,414
|
|
Treasury stock
|
|
|
(26,140
|
)
|
|
|
(25,892
|
)
|
Accumulated other comprehensive (loss) income
|
|
|
(46,030
|
)
|
|
|
15,645
|
|
Notes receivable from the issuance of Class A stock
|
|
|
(892
|
)
|
|
|
(1,252
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
24,666
|
|
|
|
100,935
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
557,980
|
|
|
$
|
543,719
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-26
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Operations
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands,
|
|
|
|
except per share data)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
Gas aggregation and pipeline sales
|
|
|
120,549
|
|
|
|
142,825
|
|
|
|
116,730
|
|
Well operation and service revenues
|
|
|
6,976
|
|
|
|
7,732
|
|
|
|
7,228
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
211,954
|
|
|
|
247,071
|
|
|
|
216,220
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
17,700
|
|
|
|
18,234
|
|
|
|
18,772
|
|
Gas aggregation and pipeline cost of sales
|
|
|
110,226
|
|
|
|
131,051
|
|
|
|
104,685
|
|
General and administrative
|
|
|
17,742
|
|
|
|
17,933
|
|
|
|
18,858
|
|
Taxes, other than income
|
|
|
4,519
|
|
|
|
5,406
|
|
|
|
4,629
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Depreciation of pipelines, other property and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Gain on sale of assets
|
|
|
(10,454
|
)
|
|
|
(7,287
|
)
|
|
|
(9,114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171,296
|
|
|
|
195,159
|
|
|
|
185,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
40,658
|
|
|
|
51,912
|
|
|
|
30,350
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER (INCOME) AND EXPENSE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
Other
|
|
|
8,547
|
|
|
|
21,884
|
|
|
|
(18,722
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,792
|
|
|
|
32,572
|
|
|
|
(8,736
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
23,866
|
|
|
|
19,340
|
|
|
|
39,086
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-27
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Stockholders Equity
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
|
|
|
|
|
|
|
|
|
|
|
Class A
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Received /
|
|
|
Accum. Other
|
|
|
Total
|
|
|
|
Common
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Treasury
|
|
|
Issuance of
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Stock
|
|
|
Income (Loss)
|
|
|
Equity
|
|
|
|
(Amounts in thousands)
|
|
|
Balance, June 30, 2006
|
|
$
|
730
|
|
|
$
|
8,081
|
|
|
$
|
5,503
|
|
|
$
|
65,105
|
|
|
$
|
(28,274
|
)
|
|
$
|
|
|
|
$
|
1,339
|
|
|
$
|
52,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,051
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,051
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(124
|
)
|
|
|
(124
|
)
|
Unrealized gain on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,256
|
|
|
|
12,256
|
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9,201
|
)
|
|
|
(9,201
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,982
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,347
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,347
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
429
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
429
|
|
Issuance of stock Common
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
Restricted stock amortization
|
|
|
|
|
|
|
463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
463
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2007
|
|
$
|
730
|
|
|
$
|
8,921
|
|
|
$
|
5,503
|
|
|
$
|
77,809
|
|
|
$
|
(27,342
|
)
|
|
$
|
|
|
|
$
|
4,270
|
|
|
|
69,891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,485
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(146
|
)
|
|
|
(146
|
)
|
Unrealized loss on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized losses arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48,906
|
)
|
|
|
(48,906
|
)
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,248
|
)
|
|
|
(1,248
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,815
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,233
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,233
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
89
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
1,594
|
|
|
|
|
|
|
|
|
|
|
|
1,664
|
|
Restricted stock amortization
|
|
|
|
|
|
|
475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
475
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
(392
|
)
|
|
|
|
|
|
|
|
|
|
|
(425
|
)
|
Issuance of notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(892
|
)
|
|
|
|
|
|
|
(892
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2008
|
|
$
|
730
|
|
|
$
|
9,452
|
|
|
$
|
5,503
|
|
|
$
|
82,043
|
|
|
$
|
(26,140
|
)
|
|
$
|
(892
|
)
|
|
$
|
(46,030
|
)
|
|
$
|
24,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,731
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(200
|
)
|
|
|
(200
|
)
|
Unrealized gains on derivatives (net of tax):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains arising during period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75,510
|
|
|
|
75,510
|
|
Reclassification adjustment for losses included in net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,635
|
)
|
|
|
(13,635
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,360
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,360
|
)
|
Issuance of stock Class A
|
|
|
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
906
|
|
|
|
|
|
|
|
|
|
|
|
973
|
|
Restricted stock amortization
|
|
|
|
|
|
|
301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
301
|
|
Purchase of stock Class A
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
(658
|
)
|
|
|
59
|
|
|
|
|
|
|
|
(632
|
)
|
Issuance of notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(452
|
)
|
|
|
|
|
|
|
(452
|
)
|
Notes receivable principal payments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2009
|
|
$
|
730
|
|
|
$
|
9,787
|
|
|
$
|
5,503
|
|
|
$
|
96,414
|
|
|
$
|
(25,892
|
)
|
|
$
|
(1,252
|
)
|
|
$
|
15,645
|
|
|
$
|
100,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-28
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Cash Flows
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
23,076
|
|
|
|
26,789
|
|
|
|
29,564
|
|
Gain on sale of assets
|
|
|
(10,454
|
)
|
|
|
(10,981
|
)
|
|
|
(9,114
|
)
|
Deferred income taxes
|
|
|
4,638
|
|
|
|
7,844
|
|
|
|
17,480
|
|
Exploration and impairment
|
|
|
8,047
|
|
|
|
2,896
|
|
|
|
17,863
|
|
Derivatives
|
|
|
922
|
|
|
|
16,888
|
|
|
|
(18,166
|
)
|
Other, net
|
|
|
(722
|
)
|
|
|
35
|
|
|
|
(570
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
44,558
|
|
|
|
54,956
|
|
|
|
58,788
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(4,145
|
)
|
|
|
(26,153
|
)
|
|
|
37,477
|
|
Inventory
|
|
|
(227
|
)
|
|
|
(332
|
)
|
|
|
(2,869
|
)
|
Income taxes receivable
|
|
|
176
|
|
|
|
150
|
|
|
|
89
|
|
Income taxes payable
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
Prepaid and other assets
|
|
|
101
|
|
|
|
(521
|
)
|
|
|
465
|
|
Accounts payable and accrued expenses
|
|
|
10,613
|
|
|
|
10,390
|
|
|
|
(14,571
|
)
|
Funds held for future distributions
|
|
|
3,082
|
|
|
|
10,983
|
|
|
|
(22,673
|
)
|
Other
|
|
|
480
|
|
|
|
928
|
|
|
|
(2,764
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
54,538
|
|
|
|
50,401
|
|
|
|
53,942
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures for property, plant and equipment
|
|
|
(93,620
|
)
|
|
|
(100,810
|
)
|
|
|
(73,688
|
)
|
Proceeds from sale of assets, net of costs
|
|
|
10,173
|
|
|
|
5,489
|
|
|
|
1,788
|
|
Notes receivable and other
|
|
|
(12,198
|
)
|
|
|
(8,305
|
)
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities from operations
|
|
|
(95,645
|
)
|
|
|
(103,626
|
)
|
|
|
(71,772
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
113,490
|
|
|
|
160,396
|
|
|
|
99,201
|
|
Principal payment on long-term debt
|
|
|
(66,478
|
)
|
|
|
(97,919
|
)
|
|
|
(78,150
|
)
|
Purchase of treasury stock and other financing activities
|
|
|
202
|
|
|
|
(337
|
)
|
|
|
(876
|
)
|
Dividends paid
|
|
|
(5,917
|
)
|
|
|
(7,208
|
)
|
|
|
(7,354
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities from operations
|
|
|
41,297
|
|
|
|
54,932
|
|
|
|
12,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
190
|
|
|
|
1,707
|
|
|
|
(5,009
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
5,091
|
|
|
|
5,281
|
|
|
|
6,988
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
5,281
|
|
|
$
|
6,988
|
|
|
$
|
1,979
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-29
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Statements of Comprehensive Income (Loss)
FOR THE
YEARS ENDED JUNE 30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period change
|
|
|
(124
|
)
|
|
|
(146
|
)
|
|
|
(200
|
)
|
Oil and gas derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
12,127
|
|
|
|
(48,242
|
)
|
|
|
78,978
|
|
Reclassification to earnings
|
|
|
(8,960
|
)
|
|
|
(1,424
|
)
|
|
|
(15,034
|
)
|
Interest rate hedging:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
129
|
|
|
|
(664
|
)
|
|
|
(3,468
|
)
|
Reclassification to earnings
|
|
|
(241
|
)
|
|
|
176
|
|
|
|
1,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
2,931
|
|
|
|
(50,300
|
)
|
|
|
61,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
21,982
|
|
|
$
|
(38,815
|
)
|
|
$
|
83,406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial
statements
ECA-30
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and 2007
|
|
1.
|
NATURE OF
ORGANIZATION
|
Energy Corporation of America (the Company) was
formed in June 1993 through an exchange of shares with the
common stockholders of Eastern American Energy Corporation
(Eastern American), successor to Pacific States
Gas & Oil, Inc. which was incorporated on
September 9, 1964. The Company is an independent energy
company. All references to the Company include Energy
Corporation of America and its consolidated subsidiaries.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
The following is a summary of the significant accounting
policies followed by the Company.
Principles of Consolidation
The
consolidated financial statements include the accounts of the
Company and its subsidiaries. The Company has investments in oil
and natural gas limited partnerships and joint ventures and has
recognized its proportionate share of these entities
revenues, expenses, assets and liabilities. All significant
intercompany transactions have been eliminated in consolidation.
Cash and Cash Equivalents
Cash and
cash equivalents include short-term investments maturing in
three months or less from the date acquired.
Inventory
The Companys inventory
balance consists of natural gas stored underground and materials
and supplies recorded at the lower of cost or market. At
June 30, 2009, $0.4 million of the inventory balance
relates to natural gas inventory, $3.6 million to
production casing and $0.8 million to other materials and
supplies. At June 30, 2008, $0.3 million of the
inventory balance relates to natural gas inventory,
$0.6 million to production casing and $0.9 million to
other materials and supplies.
Property, Plant and Equipment
Oil and
natural gas properties are accounted for using the successful
efforts method of accounting. Under this method, certain
expenditures such as exploratory geological and geophysical
costs, exploratory dry hole costs, delay rentals and other costs
related to exploration are recognized currently as expenses. All
direct and certain indirect costs relating to property
acquisition, successful exploratory wells, development costs,
and support equipment and facilities are capitalized. The
Company computes depletion, depreciation and amortization of
capitalized oil and natural gas property costs on the
units-of-production
method. Direct production costs, production overhead and other
costs are charged against income as incurred. Gains and losses
on the sale of oil and natural gas property interests are
generally recognized in operating income.
Other property, equipment, pipelines and buildings are stated at
cost and are depreciated using straight-line and accelerated
methods over estimated useful lives ranging from three to forty
years.
Repair and maintenance costs are charged against income as
incurred; significant renewals and betterments are capitalized.
Gains and losses on dispositions of property, equipment,
pipelines and buildings are recognized in operating income.
ECA-31
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30 property, plant and equipment consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Oil and gas properties
|
|
$
|
546,029
|
|
|
$
|
585,376
|
|
Other property and equipment
|
|
|
41,341
|
|
|
|
41,894
|
|
Pipelines
|
|
|
50,853
|
|
|
|
53,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
638,223
|
|
|
|
680,946
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(186,481
|
)
|
|
|
(201,224
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
451,742
|
|
|
$
|
479,722
|
|
|
|
|
|
|
|
|
|
|
Long-Lived Assets
Statement of
Financial Accounting Standards (SFAS) No. 144,
Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of
, requires all companies
to assess long-lived assets and assets to be disposed of for
impairment. For the years ended June 30, 2009, 2008, and
2007, the impairments recognized by the Company primarily
consists of oil and natural gas property of $0.4 million,
$0.4 million, and $3.7 million, respectively.
Deferred Financing Costs
Certain
legal, underwriting fees and other direct expenses associated
with the issuance of credit agreements, lines of credit and
other financing transactions have been capitalized. These
financing costs are being amortized over the term of the related
credit agreements.
Foreign Currency Translation
The
translation of applicable foreign currencies into
U.S. dollars is performed for accounts using current
exchange rates in effect at the balance sheet date and for the
income statement as of the transaction date. The translation
adjustment is included in stockholders equity as a
component of other comprehensive income.
Income Taxes
Deferred income taxes
reflect the impact of temporary differences between assets and
liabilities recognized for financial reporting purposes and such
amounts as measured by tax laws. These temporary differences are
determined in accordance with SFAS No. 109,
Accounting
For Income Taxes
. A valuation allowance is established for
any portion of a deferred tax asset for which it is more likely
than not that a tax benefit will not be realized.
Deferred Revenue
In 1993, the Company
sold a net profits interest in certain Appalachian natural gas
properties in connection with the formation of the Eastern
American Natural Gas Trust (the Royalty Trust). A
portion of the proceeds from the sale of these interests,
representing term net profits interest, was accounted for as a
production payment and was classified as deferred trust revenue.
The deferred revenue is recognized as production occurs for the
term properties.
Deferred Gain
In 2005,
the Company consummated a Term Royalty Conveyance for a term of
twenty (20) years, in certain oil and natural gas
properties located in West Virginia, Kentucky, and Pennsylvania
to Black Stone Acquisitions Partners II, L.P., Black Stone
Acquisitions Partners II-B, L.P., and Hatfield Royalty, L.P.
(collectively referred to as Black Stone). The
proceeds, net of certain costs and expenses and the carrying
value of assets sold, were classified as a deferred gain and are
being recognized as production occurs related to the Black Stone
Term Royalty
ECA-32
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Conveyance. The Company recognized $8.9 million,
$7.1 million, and $5.9 million in gain on sale of
assets for the years ended June 30, 2009, 2008 and 2007,
respectively.
Revenues and Gas Costs
Oil and natural
gas sales, and aggregation and pipeline revenues are recognized
as income when the oil or natural gas is produced and sold.
Monthly, the Company makes estimates of the amount of production
delivered to the purchaser and the price to be received. The
Company uses its knowledge of properties, historical
performance, NYMEX and local spot market prices and other
factors as the basis for these estimates. Gas costs are expensed
as incurred.
Stock Compensation
During June 2008,
ECA granted all full-time employees the opportunity to purchase
a specified number of Class A stock shares at the then
current share price of $140 per share. The stock issued as a
result of this program has certain vesting restrictions that
expire over a specified period of time, with the last of those
restrictions expiring October 1, 2013. As a result of this
program, the Company issued 15,060 shares of stock.
During June 2006, ECA granted all full-time employees the
opportunity to purchase Class A stock having certain
restrictions that expire January 1, 2012. Employees were
awarded the right to purchase a specified number of shares and
were required to make an election prior to August 1, 2006.
As a result of this program, the Company issued
17,126 shares of stock with a $45 per share purchase price.
During October 2003, the Company offered its employees that were
participants in the 2003 Profit Sharing program, the opportunity
to purchase Class A stock having certain restrictions.
Employees were awarded the right to purchase a specified number
of shares, with the restrictions expiring over a specified
period of time. As of January 1, 2009 all restrictions
related to this stock offering have expired. As a result of this
program, 16,850 shares of restricted stock were issued for
$15 per share vesting over five years.
Compensation expense is recognized based on the fair value of
the stock at issuance and is being amortized over the applicable
vesting periods with $0.3 million of expense recognized for
the year ended June 30, 2009 and $0.5 million of
expense for each of the years ended June 30, 2008 and 2007.
As of June 30, 2009, unrecognized compensation expense
related to awards that will vest in future fiscal years
approximated $0.3 million.
The Company measures compensation costs related to stock
issuances to Company directors at fair value. Accordingly, stock
compensation of $0.3 million, $0.2 million, and
$0.1 million was recognized for the years ended
June 30, 2009, 2008, and 2007 respectively.
Use of Estimates
The preparation of
financial statements in conformity with U.S. generally
accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
The Companys financial statements are based on a number of
significant estimates including oil and natural gas reserve
quantities, which are the basis for the calculation of
depletion, depreciation, amortization and impairment of oil and
natural gas properties. Management
ECA-33
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
emphasizes that reserve estimates are inherently imprecise. In
addition, realization of deferred tax assets is based largely on
estimates of future taxable income.
Derivatives
In accordance with
SFAS No. 133,
Accounting for Derivative Instruments
and Hedging Activities
, as amended, all derivative
instruments are recorded as assets or liabilities in the
Companys balance sheet and measurement of those
instruments at its estimated fair value. The accounting
treatment of changes in fair value is dependent upon whether or
not a derivative instrument is designated as a hedge and if so,
the type of hedge. For derivatives designated as cash flow
hedges, changes in fair value are recognized in other
comprehensive income to the extent the hedge is effective, until
the hedged item is recognized in earnings. Hedge effectiveness
is measured monthly based on the relative changes in fair value
between the derivative contract and the hedged item over time.
Any change in fair value resulting from ineffectiveness and any
derivatives not qualifying as hedges are recognized immediately
in earnings in other income and expense. In the event the
Company has cash collateral held by a derivative counterparty as
a result of a margin call, the amount is reflected in other
accounts receivable.
Accumulated Other Comprehensive Income
(Loss)
At June 30, accumulated other
comprehensive income (loss) (net of tax) consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Foreign currency translation
|
|
$
|
(44
|
)
|
|
$
|
(243
|
)
|
Oil and gas hedging
|
|
|
(45,504
|
)
|
|
|
18,439
|
|
Interest rate hedging
|
|
|
(482
|
)
|
|
|
(2,551
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive (loss) income
|
|
$
|
(46,030
|
)
|
|
$
|
15,645
|
|
|
|
|
|
|
|
|
|
|
Concentration of Credit Risk
The
Company maintains its cash accounts primarily with a single bank
and invests cash in money market accounts, which the Company
believes to have minimal risk. As operator of jointly owned oil
and natural gas properties, the Company sells oil and natural
gas production to numerous U.S. oil and natural gas
purchasers, and pays vendors on behalf of joint owners for oil
and natural gas services. Both purchasers and joint owners are
located primarily in the northeastern United States and Texas.
The risk of nonpayment by the purchasers or joint owners is
considered minimal and has been considered in the Companys
allowance for doubtful accounts.
Environmental Concerns
The Company is
continually taking actions it believes necessary in its
operations to ensure conformity with applicable federal, state
and local environmental regulations. As of June 30, 2009,
2008 and 2007, the Company had not been fined or cited for any
environmental violations, which would have a material adverse
effect upon capital expenditures, operating results or the
competitive position of the Company.
Recent Accounting Pronouncements
In
June 2006, the Financial Accounting Standards Board
(FASB) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109, Accounting for
Income Taxes
(FIN 48), to create a single
model to address accounting for uncertainty in tax positions.
FIN 48 clarifies the accounting for income taxes by
prescribing a minimum recognition threshold that a tax position
is required to meet before being recognized in the financial
statements. FIN 48 also provides guidance on measurement
and derecognition of tax benefits, balance sheet classification
interest
ECA-34
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
and penalties, disclosure and transition. This Interpretation
initially was effective for fiscal years beginning after
December 15, 2006. In January 2008, the FASB approved the
deferral of the effective date of FIN 48 for certain
nonpublic companies to annual financial statements for fiscal
years beginning after December 15, 2007. In December 2008,
the FASB provided for an additional deferral of the effective
date of FIN 48 for certain nonpublic companies to annual
financial statements for fiscal years beginning after
December 15, 2008. The Company elected the initial and
additional deferrals and on July 1, 2009, the Company
adopted FIN 48. Adoption of this interpretation did not
have a material impact on the Companys financial position.
The Companys policy is to reflect potential interest and
penalties related to uncertain tax positions as part of interest
and penalty expense, respectively, when and if they become
applicable.
In March 2008, the FASB issued Statement of Financial Accounting
Standards No. 161, Disclosures about Derivative Instruments
and Hedging Activities an Amendment of FASB
Statement 133 which modifies and enhances required disclosures
regarding derivative and hedging activities related to how an
entity uses derivative instruments, as well as how these
instruments affect an entitys financial position,
performance, and cash flows. The statement requires disclosure
of the objectives for using derivative instruments, the fair
value of these instruments and their gains and losses (in
tabular format), and certain credit-risk-related features.
SFAS No. 161 is effective for fiscal years beginning after
November 15, 2008. The adoption of SFAS No. 161 as of
July 1, 2009 did not have a material impact on the
Companys financial statement disclosures.
Asset Retirement Obligations
The
Company accounts for its asset retirement obligations according
to SFAS No. 143, Accounting for Asset Retirement
Obligations. SFAS No. 143 provides the accounting
requirements for retirement obligations associated with tangible
long-lived assets. When the liability is initially recorded, the
entity capitalizes the cost, thereby increasing the carrying
amount of the related long-lived asset. Over time, the liability
is accreted, and the capitalized cost is depreciated over the
useful life of the related asset.
For the Company, asset retirement obligations primarily relate
to the abandonment of oil and natural gas producing facilities.
While assets such as pipelines and marketing assets may have
retirement obligations covered by SFAS No. 143,
certain of those obligations are not recognized since the fair
value cannot be estimated due to the uncertainty of the
settlement date of the obligation. Amounts reflected as
Change in estimate include revisions to the
Companys plugging assumptions, based upon the current
facts and circumstances associated with the Companys well
portfolio and with current market conditions.
ECA-35
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table presents a reconciliation of the beginning
and ending carrying amounts of the asset retirement obligations
for the year ended June 30, 2009 which is included in other
long-term obligations (in thousands):
|
|
|
|
|
Asset retirement obligation as of the beginning of the year
|
|
$
|
15,100
|
|
Accretion expense
|
|
|
825
|
|
Liabilities incurred
|
|
|
117
|
|
Liabilities settled
|
|
|
(65
|
)
|
Change in estimate
|
|
|
75
|
|
|
|
|
|
|
Asset retirement obligation as of the end of the year
|
|
$
|
16,052
|
|
|
|
|
|
|
Supplemental Disclosures of Cash Flow
Information
Supplemental cash flow
information for the years ended June 30 is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Cash paid for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
8,120
|
|
|
$
|
10,646
|
|
|
$
|
7,634
|
|
Income taxes, net of amounts refunded
|
|
|
100
|
|
|
|
54
|
|
|
|
4
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends declared and unpaid at year end
|
|
$
|
1,803
|
|
|
$
|
1,828
|
|
|
$
|
1,833
|
|
Notes receivable from the issuance of Class A stock
|
|
|
|
|
|
|
892
|
|
|
|
452
|
|
Liabilities settled through assignment
|
|
|
980
|
|
|
|
|
|
|
|
|
|
Natural
Gas & Oil Hedging Instruments
The Companys overall objective in its hedging program is
to assure a return on capital invested in long-lived assets in
excess of the Companys cost of capital. The various
derivative commodity instruments used by the Company to hedge
its exposure to variability in expected future cash flows
associated with the fluctuations in the price of oil and natural
gas related to the Companys forecasted sale of equity
production and forecasted natural oil and natural gas purchases
and sales have been designated and qualify as cash flow hedges.
Futures contracts obligate the Company to buy or sell a
designated commodity at a future date for a specified price and
quantity at a specified location.
Swap agreements involve payments to or receipts from
counterparties based on the differential between a fixed and
variable price for the commodity. Collar agreements require the
counterparty to pay the Company if the index price falls below
the floor price and the Company to pay the counterparty if the
index price rises above the cap price. Certain swap and option
instruments used by the Company do not qualify as cash flow
hedges. Exchange-traded instruments are generally settled with
offsetting positions. Over the counter (OTC)
arrangements require settlement in cash.
ECA-36
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The fair value of the Companys derivative commodity
instruments for the years ended June 30 is presented below (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Asset
|
|
$
|
593
|
|
|
$
|
31,291
|
|
Liability
|
|
|
(95,218
|
)
|
|
|
(282
|
)
|
|
|
|
|
|
|
|
|
|
Net asset (liability)
|
|
$
|
(94,625
|
)
|
|
$
|
31,009
|
|
|
|
|
|
|
|
|
|
|
These amounts are included in the Consolidated Balance Sheets as
derivatives at fair value. The net fair value of derivative
instruments changed during fiscal year 2009 primarily as a
result of a decrease in natural gas and oil prices. The absolute
quantities of the Companys derivative commodity
instruments that have been designated and qualify as cash flow
hedges totaled 10.3 million MMBtu for natural gas
derivatives and 18,000 Bbl for oil derivatives as of
June 30, 2009. As of June 30, 2008, the related
volumes were 19.1 million MMBtu and 108,400 Bbl. The
open positions at June 30, 2009 had maturities for natural
gas swaps extending through June 2012 and for oil swaps through
December 2009.
As of June 30, 2009, the Company deferred net gains of
$18.4 million in accumulated other comprehensive income,
net of tax, for derivatives associated with the effective
portion of the change in fair value of its derivative
instruments designated as cash flow hedges. As of June 30,
2008, net losses of $45.5 million for natural gas
derivatives were so deferred. Assuming no change in price or new
transactions, the Company estimates that approximately
$18.0 million of net unrealized gains on its derivatives
reflected in accumulated other comprehensive income, net of tax,
as of June 30, 2009 will be recognized in earnings during
the next twelve months due to the physical settlement of hedged
transactions.
Ineffectiveness associated with the Companys derivative
instruments designated as cash flow hedges increased earnings by
approximately $44,000 for the year ended June 30, 2009,
decreased earnings by approximately $95,000 for the year ended
June 30, 2008, and increased earnings by $29,000 for the
year ended June 30, 2007. These amounts are included in
other income and expense in the Consolidated Statements of
Operations.
Changes in fair value associated with derivative contracts that
do not qualify for hedge accounting treatment are recognized in
other income and expense. Accordingly, the Company recognized
net gains of approximately $18.1 million for derivatives
for the year ended June 30, 2009, and net losses of
approximately $16.8 million and $1.0 million for
derivatives for the years ended June 30, 2008 and 2007,
respectively. These amounts are included in other income and
expense in the Consolidated Statement of Operations.
Interest
Rate Swaps
During November 2007 and January 2008, Company entered into
three interest rate swap agreements with Wells Fargo Foothill,
Inc. (Foothill), in an effort to reduce the
potential impact of increases in interest rates on floating-rate
long-term debt. The three-year agreements cover
$100 million in long-term debt and fix the one-month London
Interbank Offered Rate (LIBOR) over a range of
3.67% 4.05%. The Company has partially hedged
its exposure to the variability in future cash flows through
January 2011.
ECA-37
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The interest rate swaps are included in the Consolidated Balance
Sheets as derivatives, at fair value. Fair values of
$3.1 million and $1.2 million were reported as current
and long-term liabilities, respectively, at June 30, 2009.
Fair values of $1.0 million and $0.2 million were
reported as current liabilities and long-term assets,
respectively, at June 30, 2008. The Company deferred net
losses of $2.6 million and $0.5 million in accumulated
other comprehensive loss, net of tax, as of June 30, 2009
and 2008, respectively and deferred net gains of $6,000 in
accumulated other comprehensive gain, net of tax, as of
June 30, 2007.
Long-Term Debt
At June 30 long-term
debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Term credit agreements, variable rates
|
|
$
|
100,000
|
|
|
$
|
100,000
|
|
Revolving credit agreements, variable rates
|
|
|
77,553
|
|
|
|
99,244
|
|
Non-recourse debt
|
|
|
17,220
|
|
|
|
16,778
|
|
Installment notes payable, at imputed interest rates ranging
from
6.0% to 8.0%
|
|
|
2,992
|
|
|
|
2,794
|
|
|
|
|
|
|
|
|
|
|
|
|
|
197,765
|
|
|
|
218,816
|
|
Less current portion
|
|
|
(640
|
)
|
|
|
(682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
197,125
|
|
|
$
|
218,134
|
|
|
|
|
|
|
|
|
|
|
Scheduled maturities of the Companys long-term debt at
June 30, 2009 for each of the next five years and
thereafter are as follows (in thousands):
|
|
|
|
|
2010
|
|
$
|
1,883
|
|
2011
|
|
|
1,883
|
|
2012
|
|
|
201,126
|
|
2013
|
|
|
1,883
|
|
2014
|
|
|
1,866
|
|
Thereafter
|
|
|
18,770
|
|
|
|
|
|
|
Total payments
|
|
|
227,411
|
|
Less: imputed interest
|
|
|
8,595
|
|
|
|
|
|
|
Present value of scheduled maturities
|
|
$
|
218,816
|
|
|
|
|
|
|
Revolving Credit and Term Loan
The
Company entered into a First Amendment to Second Amended and
Restated Credit Agreement effective August 4, 2008 (the
Credit Agreement), with Wells Fargo Foothill, Inc.
(Foothill), Bank of America, N.A. and U.S. Bank
National Association. The credit facility provides for a Maximum
Loan Amount of $250 million, consisting of a revolving
facility of $150 million and a single advance term loan of
$100 million, which is an increase of $50 million on
the revolving facility from June 30, 2008. The term loan
contains requirements for principal payments of $1 million
each at July 10, 2009, 2010, and 2011 and the Maturity Date
of the Credit Agreement is July 10, 2012. At June 30,
2009, the Company classified
ECA-38
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
$1 million of the term loan that was due on July 10,
2009 as long-term debt as a result of having a Credit Agreement
in place that allowed the Company to refinance the debt on a
long-term basis. Depending on the Companys level of
borrowing under the Credit Agreement, the applicable interest
rates for base rates are based on Wells Fargos prime rate
minus 0.25% to plus 0.25%. The Company also has the ability
under the Credit Agreement to designate certain loans as LIBOR
Rate Loans at interest rates based upon the rate at which dollar
deposits are offered to major banks in the London interbank
market plus 1.50% to 2.00%.
The obligations under the Credit Agreement are secured by
certain of the existing proved producing oil and natural gas
assets of the Company. The Credit Agreement, among other things,
restricts the ability of the Company and its subsidiaries to
incur new debt, grant additional security interests in its
collateral, engage in certain merger or reorganization
activities, or dispose of certain assets.
Other Credit Facilities
The Company
has an unsecured revolving line of credit totaling
$2.0 million with a financial institution with a variable
interest rate equal to the Prime Rate quoted in the
Wall Street Journal (or comparable source) plus 0.25% per annum,
except that upon presentment of any letter of credit, such rate
shall be equal to the prime rate plus 2%. As of June 30,
2009, there was no outstanding balance on this line of credit
while there was $30,000 committed through letters of credit at
June 30, 2008.
Other Notes
In August 2005 the Company
purchased an office building and associated land for
$3.5 million, which included the assumption of a note with
the principal balance of approximately $2.4 million. The
note stipulated that the Company will pay fifty-five consecutive
equal monthly payments with the first payment to be made by the
Company on September 15, 2005 and the final scheduled
payment on March 15, 2010 with the remaining balance due on
April 8, 2010. In March 2007 the Company remodeled the
existing office building and assumed a promissory note with a
principal balance of $0.3 million. The note stipulated that
the Company will pay thirty six consecutive equal monthly
payments with the first payment made by the Company on
April 15, 2007 and the final scheduled payment on
March 15, 2010 with the remaining balance due on
April 8, 2010. As of June 30, 2009 and June 30,
2008, the balance due was $2.4 million and
$2.5 million, respectively. The Company intends to
negotiate an extension of this note. As of June 30, 2009,
the Company has classified the loan as long-term debt as a
result of having a Credit Agreement in place that allows the
Company to refinance the debt on a long-term basis.
Non-Recourse Loan
The Company has
entered into a non-recourse loan for the purchase of certain
transportation equipment. The loan, in the aggregate principal
amount of $17.5 million, was disbursed to the Company in
four tranches. As of June 30, 2007 the first two tranches
totaling $11.8 million were funded. The third tranche of
$3.3 million was funded on August 15, 2007 and the
fourth and final tranche of $2.4 million was funded upon
delivery of the equipment to the Company, which occurred in
October 2007. The term of the loan will be 10 years from
the date of disbursement of the fourth tranche. The loan is
being repaid by a fixed monthly payment of principal and
interest which was calculated at the time of disbursement of the
fourth tranche based upon a 250 month amortization at an
interest rate equal to 6.22%. The first scheduled payment on
this loan was made in November 2007. The loan is secured by the
transportation equipment acquired by the Company. As of
June 30, 2009 and June 30, 2008, the balance due was
$16.8 million and $17.2 million, respectively.
ECA-39
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table summarizes components of the Companys
provision for income taxes for the years ended June 30 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(38
|
)
|
|
$
|
11
|
|
|
$
|
(125
|
)
|
State
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
177
|
|
|
|
11
|
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
3,207
|
|
|
|
6,643
|
|
|
|
13,627
|
|
State
|
|
|
1,431
|
|
|
|
1,201
|
|
|
|
3,853
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
4,638
|
|
|
|
7,844
|
|
|
|
17,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
4,815
|
|
|
$
|
7,855
|
|
|
$
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the provision for income taxes computed at
the statutory rate to the provision for income taxes as shown in
the consolidated statements of operations for the years ended
June 30 is summarized below (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Tax provision at the federal statutory rate
|
|
$
|
8,353
|
|
|
$
|
6,769
|
|
|
$
|
13,680
|
|
State taxes, net of federal tax benefit
|
|
|
1,476
|
|
|
|
806
|
|
|
|
2,376
|
|
State tax credits
|
|
|
152
|
|
|
|
|
|
|
|
|
|
Excess statutory depletion
|
|
|
(168
|
)
|
|
|
(103
|
)
|
|
|
(59
|
)
|
Non-deductible entertainment
|
|
|
53
|
|
|
|
224
|
|
|
|
134
|
|
Change in valuation allowance, net
|
|
|
|
|
|
|
|
|
|
|
1,342
|
|
Change in tax contingency
|
|
|
(5,013
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
(38
|
)
|
|
|
159
|
|
|
|
(118
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total provision for income taxes
|
|
$
|
4,815
|
|
|
$
|
7,855
|
|
|
$
|
17,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-40
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Components of the Companys deferred tax assets and
liabilities at June 30 were as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts
|
|
$
|
338
|
|
|
$
|
181
|
|
Profit sharing plan liability
|
|
|
2,008
|
|
|
|
2,007
|
|
Royalty Trust agreements
|
|
|
2,268
|
|
|
|
1,831
|
|
Derivative instruments
|
|
|
7,294
|
|
|
|
|
|
Restricted stock compensation
|
|
|
286
|
|
|
|
196
|
|
Asset retirement obligation
|
|
|
6,498
|
|
|
|
6,955
|
|
Litigation settlement liability
|
|
|
|
|
|
|
849
|
|
State and federal income tax benefit
|
|
|
2,048
|
|
|
|
3,327
|
|
Tax credits and carryforwards
|
|
|
15,934
|
|
|
|
22,432
|
|
Other
|
|
|
343
|
|
|
|
273
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
37,017
|
|
|
|
38,051
|
|
Valuation allowance
|
|
|
|
|
|
|
(1,342
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets net of valuation allowance
|
|
|
37,017
|
|
|
|
36,709
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
(50,110
|
)
|
|
|
(66,265
|
)
|
Black Stone Term Royalty Conveyance
|
|
|
(21,642
|
)
|
|
|
(21,342
|
)
|
Derivative instruments
|
|
|
|
|
|
|
(1,313
|
)
|
Other
|
|
|
(35
|
)
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(71,787
|
)
|
|
|
(88,959
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(34,770
|
)
|
|
$
|
(52,250
|
)
|
|
|
|
|
|
|
|
|
|
Current deferred tax asset
|
|
$
|
2,440
|
|
|
$
|
1,359
|
|
Long-term deferred tax liability
|
|
|
(37,210
|
)
|
|
|
(53,609
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
(34,770
|
)
|
|
$
|
(52,250
|
)
|
|
|
|
|
|
|
|
|
|
ECA-41
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30 the Company had the following federal and state tax
credits and carryforwards (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
|
|
|
Year of
|
|
|
|
|
|
Year of
|
|
|
|
Amount
|
|
|
Expiration
|
|
|
Amount
|
|
|
Expiration
|
|
|
AMT tax credits
|
|
$
|
2,082
|
|
|
|
None
|
|
|
$
|
1,957
|
|
|
|
None
|
|
Net operating loss carryforwards
|
|
|
5,711
|
|
|
|
2025-2028
|
|
|
|
10,567
|
|
|
|
2025-2029
|
|
Charitable contribution carryforwards
|
|
|
3,033
|
|
|
|
2009-2013
|
|
|
|
3,851
|
|
|
|
2009-2014
|
|
Percentage depletion carryforwards
|
|
|
2,173
|
|
|
|
None
|
|
|
|
2,318
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total federal credits and carryforwards
|
|
$
|
12,999
|
|
|
|
|
|
|
$
|
18,693
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State net operating loss carryforwards
|
|
$
|
2,035
|
|
|
|
2009-2028
|
|
|
$
|
2,701
|
|
|
|
2009-2029
|
|
State charitable contribution carryforwards
|
|
|
506
|
|
|
|
2009-2013
|
|
|
|
632
|
|
|
|
2009-2014
|
|
State percentage depletion carryforwards
|
|
|
394
|
|
|
|
None
|
|
|
|
406
|
|
|
|
None
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total state carryforwards
|
|
$
|
2,935
|
|
|
|
|
|
|
$
|
3,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total federal and state credits and carryforwards
|
|
$
|
15,934
|
|
|
|
|
|
|
$
|
22,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended June 30, 2009, the Company established a
valuation allowance of $1.3 million related to the
charitable contribution carryforwards as the Company does not
currently believe that it is more likely than not that all of
the federal and state charitable contribution carryforwards will
be fully utilized during their respective statutory carryforward
periods. The determination of the valuation allowance amount was
based on all positive and negative evidence available as of the
year-end. The Company will reassess the valuation allowance
annually and if future evidence allows for a decrease or
increase of the valuation allowance then a tax benefit or
expense, respectively, will be recorded.
In prior years, the State of West Virginia Department of Revenue
(WV DOR) notified the Company that it was initiating
an audit of the Companys state income/franchise tax
returns for the open tax years. As of June 30, 2009 and
2008, the WV DOR had not begun nor requested information from
the Company pertaining to the audit of the Companys state
income/franchise tax returns. The Company has not received any
notices of proposed adjustments pertaining to the audit and
believes that it has adequately provided for any potential tax
liability that may be assessed by the WV DOR.
The Company and its subsidiaries file income tax returns in the
U.S. federal jurisdiction, in various states, and in one
foreign jurisdiction, each with varying statutes of limitations.
The 2006 through 2009 tax years generally remain subject to
examination by the federal and state tax authorities. The 2005
through 2009 tax years generally remain subject to examination
by the foreign tax authority.
Though not included in the tables or discussion above, the
Company has a foreign net deferred tax asset of
$15.8 million in New Zealand. The foreign net deferred tax
asset is comprised of a $16.2 million foreign deferred tax
asset related to the Companys New Zealand net operating
loss carryforward (NZ NOL), net of a
$0.4 million foreign deferred tax liability related to
property, plant and equipment. The foreign tax benefit of this
NZ NOL that may be carried
ECA-42
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
forward indefinitely, subject to certain ownership restrictions,
is dependent on future New Zealand taxable income. Accordingly,
the Company established in prior years and continues to provide
a full valuation allowance equal to the $15.8 million
foreign net deferred tax asset as the Company does not currently
believe that it is more likely than not that the NZ NOL will be
fully utilized. The NZ NOL available to reduce future New
Zealand taxable income was approximately $49.2 million
($76.0 million NZD) and $48.5 million
($63.8 million NZD) at June 30, 2009 and 2008,
respectively.
|
|
6.
|
EMPLOYEE
BENEFIT PLANS
|
The Company and certain subsidiaries, have a Profit
Sharing/Incentive Stock Plan (the Plan) for the
stated purpose of expanding and improving profits and prosperity
and to assist the Company in attracting and retaining key
personnel. The Plan is noncontributory, and its continuance from
year to year is at the discretion of the Companys board of
directors. The annual profit sharing pool is based on
calculations set forth in the Plan. Generally, to be eligible to
participate, an employee must have been continuously employed
for two or more years; however, employees with less than two
years of employment may participate under certain circumstances.
The Company recognized $5.8 million and $5.4 million
of profit sharing expense in other income and expense during the
years ended June 30, 2009 and June 30, 2008,
respectively, and $5.6 million for the year ended
June 30, 2007.
The Company sponsors a Section 401(k) plan covering all
full-time employees who elect to participate. The plan provides
for matching, at various percentages of the employees
contribution, based on each participants length of service
with the Company. The Companys contributions are expensed
as incurred, which totaled approximately $0.7 million for
each of the years ended June 30, 2009 and June 30,
2008 and $0.6 million for the year ended June 30, 2007.
Voting Common Stock
In May 1995, the
Company was reincorporated in the State of West Virginia. As
part of this reincorporation, each outstanding share of then
existing no-par value common stock was converted to one share of
$1 par value common stock.
Class A Non-Voting Common Stock
In August 1998, the Company amended its articles of
incorporation authorizing the issuance of up to
100,000 shares of Class A non-voting common stock.
In June 2008, ECA granted all full-time employees the
opportunity to purchase a specified number of shares of
Class A stock at the then current share price of $140 per
share. The stock issued as a result of this program vests over a
specified period of time, with the full vesting to occur
October 1, 2013. Pursuant to this program, the Company
issued 15,060 shares of Class A stock.
In June 2006, ECA granted all full-time employees the
opportunity to purchase a specified number of shares of
Class A stock having certain restrictions that expire
January 1, 2012. The Company issued 17,126 shares of
stock with a $45 per share purchase price pursuant to this
program. The Company repurchased 740, 685, and 875 of the
Class A shares during the years ended June 30, 2009,
2008, and 2007, respectively.
ECA-43
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
During October 2003, ECA offered its employees that were
participants in the 2003 Profit Sharing program the opportunity
to purchase shares of Class A stock having certain
restrictions expiring over a specified period of time. As of
January 1, 2009 all restrictions related to these
Class A shares have expired. Pursuant to this program,
16,850 shares of restricted Class A Stock were issued for
$15 per share vesting over five years. The Company repurchased
18, 162, and 815 shares of the Class A Stock during
the years ended June 30, 2009, 2008, and 2007,
respectively. During the years ended June 30, 2009, 2008,
and 2007, 4,449 shares, 4,996 shares, and
5,249 shares, respectively, became fully vested.
Treasury Stock
At June 30, 2009,
the Company had 209,327 shares of voting common stock in
treasury, carried at cost. The Company did not purchase any
shares of voting common stock during the years ended
June 30, 2009 and 2007 and purchased 1,600 shares
during the year ended June 30, 2008. At June 30, 2009,
the Company had 25,329 shares of non-voting Class A
stock in treasury, carried at cost. The Company purchased 4,499,
1,524, and 462 shares of non-voting Class A stock
during the years ended June 30, 2009, 2008, and 2007,
respectively. The Company reissued 6,876 and 12,128 shares
of non-voting Class A stock during the years ended
June 30, 2009 and 2008, respectively. No shares of
non-voting Class A stock were reissued during the year
ended June 30, 2007.
In accordance with SFAS No. 128, Earnings Per
Share, basic earnings per share has been computed based
upon the weighted average shares outstanding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares, basic and diluted
|
|
|
566,070
|
|
|
|
576,313
|
|
|
|
587,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted net income per common share
|
|
$
|
33.66
|
|
|
$
|
19.93
|
|
|
$
|
36.98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company has noncancelable operating lease agreements for the
rental of office space, computers and other equipment. Certain
of these leases contain purchase options or renewal clauses.
Rental expense for operating leases was approximately
$2.4 million, $2.0 million, and $1.8 million for
the years ended June 30, 2009, 2008, and 2007, respectively.
ECA-44
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
At June 30, 2009 future minimum lease payments for each of
the next five years and thereafter are as follows (in thousands):
|
|
|
|
|
2010
|
|
$
|
752
|
|
2011
|
|
|
459
|
|
2012
|
|
|
217
|
|
2013
|
|
|
175
|
|
2014
|
|
|
116
|
|
Thereafter
|
|
|
280
|
|
|
|
|
|
|
|
|
$
|
1,999
|
|
|
|
|
|
|
|
|
10.
|
RELATED
PARTY TRANSACTIONS
|
The Company has advanced funds to a certain officer at 6.75% to
7.5% interest. Balances totaled $0.2 million and
$0.4 million for the years ended June 30, 2009 and
June 30, 2008, respectively. The balances are due in full,
unless sooner paid, ranging from two to five years, depending on
the agreement.
Certain directors and employees of the Company and members of
their families regularly participate in the wells drilled by the
Company on an actual cost basis and share in the costs and
revenues on the same basis as the Company. The Company has the
right to select the wells drilled and each participant is
involved in all wells included within a Company drilling program
and cannot selectively choose the wells in which to participate.
The Company has issued promissory notes to certain employees as
part of a Class A Stock Award Agreement, whereby employees
had the option to finance eighty percent of the cost of the
shares they elected to purchase at $140 per share. The carrying
value of the notes was $1.3 million and $0.9 million
as of June 30, 2009 and June 30, 2008, respectively.
The notes, which are full recourse, have an interest rate of
3.5% with a term of five years with principal payments due and
payable at the end of years three, four and five.
|
|
11.
|
COMMITMENTS
AND CONTINGENCIES
|
On June 10, 2005, the Company consummated a Term Royalty
Conveyance, pursuant to which Eastern American transferred a
term royalty interest, for a term of twenty years in certain oil
and natural gas properties located in West Virginia, Kentucky,
and Pennsylvania to Black Stone. The deferred gain related to
the sale is classified as current and long-term liabilities and
is being recognized as production occurs. The remaining deferred
gain in current and long-term liabilities totaled
$75.3 million and $82.6 million at June 30, 2009
and 2008, respectively. The transaction included interests in
312 producing properties. In addition, the Company entered into
a Development Agreement that obligated the Company to drill, or
cause to be drilled, 180 completed development wells by
March 31, 2008. As of June 30, 2008, the Company had
satisfied its drilling obligation under the Development
Agreement.
In connection with the transaction, the Company entered into a
Credit Line Deed of Trust in the amount of $24 million. The
indebtedness reduces proportionately under the terms of the
ECA-45
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Development Agreement and the lien was partially released as
completed development wells were drilled. As a result of the
Companys satisfaction of the drilling commitment, the
indebtedness under the terms of the Credit Line Deed of Trust
has been eliminated. The Company has obtained a full release
from Black Stone of the Credit Line Deed of Trust.
The Company is involved in various legal actions and claims
arising in the ordinary course of business. Management does not
expect that any matter pending against the Company will have a
material adverse effect on the Companys financial position
or results of operations and has established reserves that it
believes are adequate.
The Company was involved in a lawsuit filed by an individual on
behalf of himself and on behalf of a class of all similarly
situated individuals and entities, alleging that the Company
improperly deducted post-production expenses in calculating
royalty payments. The Company settled this lawsuit and is
distributing the settlement proceeds in five annual
distributions. As part of the settlement, the parties to the
litigation and the Company agreed upon a methodology for
calculating royalty payments in the future with respect to
natural gas produced from the wells subject to this lawsuit. The
first distribution of settlement proceeds occurred during the
fiscal year ended June 30, 2009 with the remaining
distributions scheduled to be funded over the next four years.
This settlement did not significantly impact the Companys
financial position or operating results and will not
significantly impact the Companys future cash flows.
|
|
12.
|
FINANCIAL
INSTRUMENTS
|
In September 2006, the Financial Accounting Standards Board
issued SFAS No. 157 which established a framework for
measuring fair value in accordance with generally accepted
accounting principles and expanded disclosures about fair value
measurements. The Company adopted the provisions of
SFAS No. 157 on July 1, 2008. The adoption of
SFAS No. 157 has had no impact on the Companys
financial statement measurements with respect to financial
instruments.
In accordance with SFAS No. 157, the Company has
categorized its financial instruments into a three-level fair
value hierarchy, based on the priority of the inputs to the
valuation technique. The fair value hierarchy gives the highest
priority to quoted prices in active markets for identical assets
and liabilities (Level 1) and the lowest priority to
unobservable inputs (Level 3).
Derivative
Financial Instruments
All of the Companys derivative contracts, consisting of
commodity and interest rate swaps, are included in Level 2.
The fair value of financial instruments included in Level 2
is based on industry models that use significant observable
inputs that, for the Company, include quoted NYMEX market prices
for commodity futures and one-month London Interbank Offering
Rate (LIBOR) futures. At June 30, 2009 and June 30,
2008, derivative assets and liabilities at fair values were
$31.1 million and $4.6 million and $0.7 million
and $96.2 million, respectively.
Gains and losses related to derivative commodity instruments
reported in the Consolidated Statements of Operations for the
period are included in oil and natural gas sales for those
instruments qualifying for hedge accounting, and in other income
and expense for other
ECA-46
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
contracts. Gains and losses related to interest rate swaps are
included in interest expense. There were no gains or losses for
the period included in earnings attributable to the change in
unrealized gains or losses relating to derivative assets and
liabilities still held as of June 30, 2009. See Note 3
for additional information regarding the Companys
derivative holdings.
Notes
Receivable
The notes receivable accrue interest at a fixed rate. The
carrying value approximates fair value which was estimated using
discounted cash flows based on current interest rates for notes
with similar credit characteristics and maturities.
Long-term
Debt
At June 30, 2009 the Companys long-term debt is
primarily comprised of revolving lines of credit with variable
rates while fixed rate facilities incur interest at rates that
approximate fair value.
The Companys reportable business segments have been
identified based on the differences in products and service
provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and
crude oil. Revenues for the aggregation and pipeline segment
arise from the aggregation of both Company and third party
produced natural gas volumes and the related transportation. The
Other category includes items related to corporate
activities. Management utilizes earnings before interest, income
taxes, depreciation, depletion, amortization and impairment and
exploratory costs (EBITDAX), a non-GAAP financial
measure, to evaluate each segments operations.
Reconciliation of non-GAAP financial measure is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
19,051
|
|
|
$
|
11,485
|
|
|
$
|
21,731
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
8,245
|
|
|
|
10,688
|
|
|
|
9,986
|
|
Depletion and depreciation of oil and gas properties
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Depreciation of property, plant and equipment
|
|
|
4,961
|
|
|
|
5,852
|
|
|
|
6,119
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Income tax expense
|
|
|
4,815
|
|
|
|
7,855
|
|
|
|
17,355
|
|
Change in fair value derivatives
|
|
|
923
|
|
|
|
16,887
|
|
|
|
(18,166
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
64,597
|
|
|
$
|
76,737
|
|
|
$
|
78,946
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-47
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Summarized financial information for the Companys
reportable segments is shown in the following table (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
Aggregation and
|
|
|
|
|
|
|
Production
|
|
Pipeline
|
|
Other
|
|
Consolidated
|
|
Fiscal Year 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
91,405
|
|
|
$
|
120,549
|
|
|
$
|
|
|
|
$
|
211,954
|
|
Depreciation, depletion, amortization
|
|
|
19,560
|
|
|
|
2,405
|
|
|
|
1,111
|
|
|
|
23,076
|
|
Impairment and exploratory costs
|
|
|
8,487
|
|
|
|
|
|
|
|
|
|
|
|
8,487
|
|
Operating profit (loss)
|
|
|
27,194
|
|
|
|
5,418
|
|
|
|
8,046
|
|
|
|
40,658
|
|
Interest (net)
|
|
|
15,195
|
|
|
|
(6,613
|
)
|
|
|
(432
|
)
|
|
|
8,150
|
|
Other (income) & expense
|
|
|
2,027
|
|
|
|
|
|
|
|
6,616
|
|
|
|
8,643
|
|
EBITDAX
|
|
|
40,503
|
|
|
|
12,922
|
|
|
|
11,172
|
|
|
|
64,597
|
|
Total assets
|
|
|
343,952
|
|
|
|
42,096
|
|
|
|
27,273
|
|
|
|
413,321
|
|
Capital expenditures
|
|
|
87,557
|
|
|
|
5,349
|
|
|
|
714
|
|
|
|
93,620
|
|
Fiscal Year 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
|
104,247
|
|
|
|
142,825
|
|
|
|
|
|
|
|
247,072
|
|
Depreciation, depletion, amortization
|
|
|
22,440
|
|
|
|
3,159
|
|
|
|
1,190
|
|
|
|
26,789
|
|
Impairment and exploratory costs
|
|
|
3,033
|
|
|
|
|
|
|
|
|
|
|
|
3,033
|
|
Operating profit (loss)
|
|
|
37,486
|
|
|
|
5,318
|
|
|
|
9,108
|
|
|
|
51,912
|
|
Interest (net)
|
|
|
18,450
|
|
|
|
(7,269
|
)
|
|
|
(575
|
)
|
|
|
10,606
|
|
Other (income) & expense
|
|
|
18,924
|
|
|
|
|
|
|
|
3,042
|
|
|
|
21,966
|
|
EBITDAX
|
|
|
44,133
|
|
|
|
14,128
|
|
|
|
18,476
|
|
|
|
76,737
|
|
Total assets
|
|
|
468,189
|
|
|
|
55,327
|
|
|
|
34,464
|
|
|
|
557,980
|
|
Capital expenditures
|
|
|
93,364
|
|
|
|
6,868
|
|
|
|
578
|
|
|
|
100,810
|
|
Fiscal Year 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
|
99,490
|
|
|
|
116,730
|
|
|
|
|
|
|
|
216,220
|
|
Depreciation, depletion, amortization
|
|
|
25,012
|
|
|
|
3,239
|
|
|
|
1,313
|
|
|
|
29,564
|
|
Impairment and exploratory costs
|
|
|
18,476
|
|
|
|
|
|
|
|
|
|
|
|
18,476
|
|
Operating profit (loss)
|
|
|
14,940
|
|
|
|
5,502
|
|
|
|
9,908
|
|
|
|
30,350
|
|
Interest (net)
|
|
|
16,035
|
|
|
|
(7,965
|
)
|
|
|
1,778
|
|
|
|
9,848
|
|
Other (income) & expense
|
|
|
(25,733
|
)
|
|
|
4
|
|
|
|
7,145
|
|
|
|
(18,584
|
)
|
EBITDAX
|
|
|
52,028
|
|
|
|
14,670
|
|
|
|
12,248
|
|
|
|
78,946
|
|
Total assets
|
|
|
475,444
|
|
|
|
37,391
|
|
|
|
30,884
|
|
|
|
543,719
|
|
Capital expenditures
|
|
|
70,153
|
|
|
|
2,824
|
|
|
|
711
|
|
|
|
73,688
|
|
Operating profit represents revenues less costs which are
directly associated with such operations. Revenues are priced
and accounted for consistently for both unaffiliated and
intersegment sales.
ECA-48
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Revenues from two purchasers of the Companys production
during the year ended June 30, 2009 represent
$43.2 million and $19.6 million respectively of the
Companys consolidated revenues within the Exploration and
Production and Gas Aggregation and Pipeline segments. During the
year ended June 30, 2008, revenues from three purchasers of
the Companys production represented $42.6 million,
$22.2 million and $21.0 million respectively of the
Companys consolidated revenues within the Exploration and
Production and Gas Aggregation and Pipeline segments. During the
year ended June 30, 2007, revenues from two purchasers of
the Companys production represented $30.0 million,
and $22.8 million respectively of the Companys
consolidated revenues within the Exploration and Production and
Gas Aggregation and Pipeline segments.
SUPPLEMENTAL
INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Costs
The following tables set forth
capitalized costs and costs incurred, including capitalized
overhead, for oil and natural gas producing activities for the
years ended June 30 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Capitalized costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved properties
|
|
$
|
433,297
|
|
|
$
|
536,122
|
|
|
$
|
571,748
|
|
Unproved properties
|
|
|
12,302
|
|
|
|
9,908
|
|
|
|
13,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
445,599
|
|
|
|
546,030
|
|
|
|
585,377
|
|
Less accumulated depletion and depreciation
|
|
|
(136,658
|
)
|
|
|
(155,182
|
)
|
|
|
(165,146
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
308,941
|
|
|
$
|
390,848
|
|
|
$
|
420,231
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of proved and unproved properties
|
|
$
|
320
|
|
|
$
|
24
|
|
|
$
|
19
|
|
Development costs
|
|
|
50,211
|
|
|
|
84,572
|
|
|
|
66,560
|
|
Exploration costs
|
|
|
12,771
|
|
|
|
6,219
|
|
|
|
1,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
63,302
|
|
|
$
|
90,815
|
|
|
$
|
68,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-49
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Results of Operations
The results of
operations for oil and natural gas producing activities,
excluding corporate overhead and interest costs for the years
ended June 30 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Revenues from sale of oil and gas
|
|
$
|
84,429
|
|
|
$
|
96,514
|
|
|
$
|
92,262
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
|
10,872
|
|
|
|
10,738
|
|
|
|
10,486
|
|
Production taxes
|
|
|
4,352
|
|
|
|
5,076
|
|
|
|
4,264
|
|
Exploration and impairment
|
|
|
8,487
|
|
|
|
3,033
|
|
|
|
18,476
|
|
Depletion, depreciation and amortization
|
|
|
18,115
|
|
|
|
20,937
|
|
|
|
23,445
|
|
Income tax expense
|
|
|
16,935
|
|
|
|
22,976
|
|
|
|
14,414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from oil and gas operations
|
|
$
|
25,668
|
|
|
$
|
33,754
|
|
|
$
|
21,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs include those costs incurred to operate and
maintain productive wells and related equipment and include
costs such as labor, repairs and maintenance, materials,
supplies, fuel consumed and insurance. Production costs are net
of well tending fees, which are included in well operations
revenues in the accompanying consolidated statements of
operations.
Exploration and impairment expenses include the costs of
geological and geophysical activity, unsuccessful exploratory
wells and leasehold impairment allowances. Depletion,
depreciation and amortization include costs associated with
capitalized acquisitions, exploration and development costs.
The provision for income taxes is computed at the statutory
federal income tax rate and is reduced to the extent of
permanent differences which have been recognized in the
Companys tax provision, such as investment tax credits,
and the utilization of Federal tax credits permitted for fuel
produced from a non-conventional source.
Reserve Quantity Information
Reserve
estimates are subject to numerous uncertainties inherent in the
estimation of quantities of proved reserves and in the
projection of future rates of production and timing of
development expenditures. The accuracy of such estimates is a
function of the quality of available data and of engineering and
geological interpretation and judgment. Results of subsequent
drilling, testing and production may cause either upward or
downward revisions of previous estimates. Further, the volumes
considered commercially recoverable fluctuate with changes in
prices and operating costs. Reserve estimates, by their nature,
are generally less precise than other financial statement
disclosures.
ECA-50
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
The following table sets forth information for the years
indicated with respect to changes in the Companys proved
reserves, substantially all of which are in the United States.
|
|
|
|
|
|
|
|
|
|
|
Natural Gas (Mmcf)
|
|
Crude Oil (Mbbls)
|
|
Proved reserves
|
|
|
|
|
|
|
|
|
June 30, 2006
|
|
|
161,809
|
|
|
|
484
|
|
Revisions of previous estimates
|
|
|
1,033
|
|
|
|
80
|
|
Extensions and discoveries
|
|
|
17,532
|
|
|
|
65
|
|
Sales of reserves in place
|
|
|
(611
|
)
|
|
|
(71
|
)
|
Production
|
|
|
(9,138
|
)
|
|
|
(83
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2007
|
|
|
170,625
|
|
|
|
475
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(1,261
|
)
|
|
|
(42
|
)
|
Extensions and discoveries
|
|
|
15,326
|
|
|
|
11
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
Production
|
|
|
(10,294
|
)
|
|
|
(65
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2008
|
|
|
174,396
|
|
|
|
379
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(29,065
|
)
|
|
|
(21
|
)
|
Extensions and discoveries
|
|
|
7,200
|
|
|
|
11
|
|
Sales of reserves in place
|
|
|
|
|
|
|
|
|
Production
|
|
|
(9,364
|
)
|
|
|
(47
|
)
|
|
|
|
|
|
|
|
|
|
June 30, 2009
|
|
|
143,167
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
June 30, 2007
|
|
|
170,625
|
|
|
|
475
|
|
June 30, 2008
|
|
|
174,396
|
|
|
|
379
|
|
June 30, 2009
|
|
|
143,167
|
|
|
|
322
|
|
Standardized Measure of Discounted Future Net Cash
Flows
Estimated discounted future net cash
flows and changes therein were determined in accordance with
SFAS No. 69, Disclosures About Oil and Gas
Producing Activities. Certain information concerning the
assumptions used in computing the valuation of proved reserves
and their inherent limitations are discussed below. The Company
believes such information is essential for a proper
understanding and assessment of the data presented. Future cash
inflows are computed by applying period-end prices of oil and
natural gas relating to the Companys proved reserves to
the period-end quantities of those reserves. Future price
changes are considered only to the extent provided by
contractual arrangements in existence at period-end.
The assumptions used to compute estimated future net revenues do
not necessarily reflect the Companys expectations of
actual revenues or costs, or their present worth. In addition,
variations from the expected production rates also could result
directly or indirectly from factors outside of the
Companys control, such as unintentional delays in
development, changes in prices or regulatory controls. The
reserve valuation further assumes that all reserves will be
disposed of
ECA-51
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
by production. However, if reserves are sold in place, this
could affect the amount of cash eventually realized.
Future development and production costs are computed by
estimating the expenditures to be incurred in developing and
producing the proved oil and natural gas reserves at the end of
the year, based on period-end costs and assuming continuation of
existing economic conditions. Future income tax expenses are
computed by applying the appropriate year-end statutory tax
rates and existing tax credits, with consideration of future tax
rates already legislated, to the future pretax net cash flows
relating to the Companys proved oil and natural gas
reserves.
An annual discount rate of 10% was used to reflect the timing of
the future net cash flows relating to proved oil and natural gas
reserves.
Information with respect to the Companys estimated
discounted future net cash flows related to its proved oil and
natural gas reserves as of June 30 is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Future cash in flows
|
|
$
|
1,317,154
|
|
|
$
|
2,591,109
|
|
|
$
|
581,996
|
|
Future production and development costs
|
|
|
(283,845
|
)
|
|
|
(525,260
|
)
|
|
|
(211,575
|
)
|
Future income tax expense
|
|
|
(296,000
|
)
|
|
|
(703,000
|
)
|
|
|
(12,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before discount
|
|
|
737,309
|
|
|
|
1,362,849
|
|
|
|
358,421
|
|
10% discount to present value
|
|
|
(476,080
|
)
|
|
|
(870,179
|
)
|
|
|
(209,748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows related
to proved oil and gas reserves
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
148,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-52
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Consolidated Financial Statements
for the
Years Ended June 30, 2009, 2008 and
2007 (Continued)
Principal changes in the standardized measure of discounted
future net cash flow for the years ended June 30 are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Standardized measure of discounted future net cash flows at
beginning of period
|
|
$
|
200,238
|
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(62,378
|
)
|
|
|
(73,207
|
)
|
|
|
(69,225
|
)
|
Net changes in prices and production costs
|
|
|
72,014
|
|
|
|
366,774
|
|
|
|
(558,968
|
)
|
Changes in production rates and other
|
|
|
21,544
|
|
|
|
31
|
|
|
|
(29,217
|
)
|
Extensions, discoveries and other additions, net of future
production and development costs
|
|
|
37,843
|
|
|
|
65,065
|
|
|
|
7,716
|
|
Sale of reserves in place
|
|
|
(3,112
|
)
|
|
|
|
|
|
|
|
|
Changes in estimated future development costs
|
|
|
(47,622
|
)
|
|
|
(84,572
|
)
|
|
|
(66,992
|
)
|
Development costs incurred
|
|
|
50,211
|
|
|
|
84,572
|
|
|
|
66,560
|
|
Revisions of previous quantity estimates
|
|
|
3,189
|
|
|
|
(6,393
|
)
|
|
|
(30,996
|
)
|
Purchase of reserves in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
19,772
|
|
|
|
26,302
|
|
|
|
50,498
|
|
Net change in income taxes
|
|
|
(30,470
|
)
|
|
|
(147,131
|
)
|
|
|
286,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discount future net cash flows at end of
period
|
|
$
|
261,229
|
|
|
$
|
492,670
|
|
|
$
|
148,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ECA-53
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF THE
PERIODS ENDED
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2009
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
Cash (overdraft) and cash equivalents
|
|
$
|
1,979
|
|
|
$
|
(94
|
)
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
|
3,110
|
|
|
|
5,347
|
|
Gas aggregation and pipeline
|
|
|
8,040
|
|
|
|
11,796
|
|
Other
|
|
|
5,140
|
|
|
|
8,068
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
16,290
|
|
|
|
25,211
|
|
Less allowance for doubtful accounts
|
|
|
(737
|
)
|
|
|
(737
|
)
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net of allowance
|
|
|
15,553
|
|
|
|
24,474
|
|
Inventory
|
|
|
4,752
|
|
|
|
5,440
|
|
Income taxes receivable
|
|
|
1,884
|
|
|
|
1,733
|
|
Deferred income tax asset
|
|
|
1,359
|
|
|
|
1,496
|
|
Notes receivable, related party
|
|
|
70
|
|
|
|
47
|
|
Derivatives
|
|
|
30,640
|
|
|
|
13,553
|
|
Prepaid and other current assets
|
|
|
574
|
|
|
|
1,100
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
56,811
|
|
|
|
47,749
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET PROPERTY, PLANT AND EQUIPMENT (Note 2)
|
|
|
479,722
|
|
|
|
478,768
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
Deferred financing costs, less accumulated amortization of
$2,583 and $2,841
|
|
|
1,057
|
|
|
|
810
|
|
Deferred taxes other comprehensive loss
|
|
|
237
|
|
|
|
|
|
Notes receivable, related party
|
|
|
262
|
|
|
|
277
|
|
Derivatives
|
|
|
651
|
|
|
|
1,398
|
|
Other
|
|
|
4,979
|
|
|
|
5,023
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
7,186
|
|
|
|
7,508
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
543,719
|
|
|
$
|
534,025
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-54
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Consolidated
Balance Sheets
AS OF THE
PERIODS ENDED
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2009
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(Amounts in thousands)
|
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
Accounts payable and accrued expenses
|
|
$
|
32,417
|
|
|
$
|
22,611
|
|
Current portion of long-term debt
|
|
|
212
|
|
|
|
219
|
|
Current portion of non-recourse debt
|
|
|
470
|
|
|
|
485
|
|
Funds held for future distribution
|
|
|
13,620
|
|
|
|
15,521
|
|
Accrued taxes, other than income
|
|
|
10,838
|
|
|
|
9,935
|
|
Deferred income tax liability
|
|
|
|
|
|
|
137
|
|
Deferred taxes other comprehensive income
|
|
|
11,052
|
|
|
|
4,292
|
|
Deferred revenue
|
|
|
262
|
|
|
|
262
|
|
Deferred gain
|
|
|
6,992
|
|
|
|
6,757
|
|
Derivatives
|
|
|
3,331
|
|
|
|
3,163
|
|
Other current liabilities
|
|
|
1,614
|
|
|
|
1,882
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
80,808
|
|
|
|
65,264
|
|
LONG-TERM OBLIGATIONS:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
201,826
|
|
|
|
221,717
|
|
Non-recourse debt
|
|
|
16,308
|
|
|
|
16,062
|
|
Deferred revenue
|
|
|
655
|
|
|
|
505
|
|
Deferred gain
|
|
|
68,277
|
|
|
|
64,879
|
|
Deferred income tax liability
|
|
|
53,609
|
|
|
|
55,477
|
|
Deferred taxes other comprehensive income
|
|
|
|
|
|
|
537
|
|
Derivatives
|
|
|
1,237
|
|
|
|
104
|
|
Other long-term obligations
|
|
|
20,064
|
|
|
|
19,621
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
442,784
|
|
|
|
444,166
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Common stock, par value $1.00; 2,000 shares authorized;
730 shares issued and 571 outstanding
|
|
|
730
|
|
|
|
730
|
|
Class A non-voting common stock, no par value;
100 shares authorized; 91 shares issued and
66 shares outstanding
|
|
|
9,787
|
|
|
|
9,847
|
|
Additional paid-in capital
|
|
|
5,503
|
|
|
|
5,503
|
|
Retained earnings
|
|
|
96,414
|
|
|
|
94,270
|
|
Treasury stock
|
|
|
(25,892
|
)
|
|
|
(25,897
|
)
|
Accumulated other comprehensive income
|
|
|
15,645
|
|
|
|
6,628
|
|
Notes receivable from the issuance of Class A stock
|
|
|
(1,252
|
)
|
|
|
(1,222
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
100,935
|
|
|
|
89,859
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
543,719
|
|
|
$
|
534,025
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-55
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Operations
FOR THE
SIX MONTHS ENDED DECEMBER 31
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands, except per share data)
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
45,703
|
|
|
$
|
44,012
|
|
Gas aggregation and pipeline sales
|
|
|
75,655
|
|
|
|
37,240
|
|
Well operations and service revenues
|
|
|
3,752
|
|
|
|
3,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
125,110
|
|
|
|
85,040
|
|
|
|
|
|
|
|
|
|
|
COSTS AND EXPENSES:
|
|
|
|
|
|
|
|
|
Field operating expenses
|
|
|
9,754
|
|
|
|
9,085
|
|
Gas aggregation and pipeline cost of sales
|
|
|
68,678
|
|
|
|
31,867
|
|
General and administrative
|
|
|
9,417
|
|
|
|
8,678
|
|
Taxes, other than income
|
|
|
3,022
|
|
|
|
395
|
|
Depletion and depreciation of oil and gas properties
|
|
|
11,496
|
|
|
|
17,179
|
|
Depreciation of pipelines, other property and equipment
|
|
|
2,999
|
|
|
|
3,148
|
|
Exploration and impairment
|
|
|
9,878
|
|
|
|
10,460
|
|
Gain on sale of assets
|
|
|
(5,612
|
)
|
|
|
(7,761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
109,632
|
|
|
|
73,051
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
15,478
|
|
|
|
11,989
|
|
|
|
|
|
|
|
|
|
|
OTHER (INCOME) AND EXPENSE:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
5,366
|
|
|
|
4,796
|
|
Other
|
|
|
(17,317
|
)
|
|
|
3,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11,951
|
)
|
|
|
8,452
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
27,429
|
|
|
|
3,537
|
|
Income tax expense
|
|
|
12,513
|
|
|
|
1,868
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
14,916
|
|
|
$
|
1,669
|
|
|
|
|
|
|
|
|
|
|
Earnings per common share, basic and diluted
|
|
$
|
25.39
|
|
|
$
|
2.85
|
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-56
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Cash Flows
FOR THE
SIX MONTHS ENDED DECEMBER 31
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
14,916
|
|
|
$
|
1,669
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
14,495
|
|
|
|
20,327
|
|
Gain on sale of assets
|
|
|
(5,612
|
)
|
|
|
(7,761
|
)
|
Deferred income taxes
|
|
|
12,513
|
|
|
|
1,868
|
|
Exploration and impairment
|
|
|
9,310
|
|
|
|
10,356
|
|
Derivatives
|
|
|
(21,841
|
)
|
|
|
|
|
Other, net
|
|
|
(425
|
)
|
|
|
(116
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
23,356
|
|
|
|
26,343
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
24,233
|
|
|
|
(8,921
|
)
|
Inventory
|
|
|
(542
|
)
|
|
|
(689
|
)
|
Income taxes receivable
|
|
|
117
|
|
|
|
151
|
|
Prepaid and other assets
|
|
|
(2,200
|
)
|
|
|
(525
|
)
|
Accounts payable and accrued expenses
|
|
|
(26,253
|
)
|
|
|
(9,880
|
)
|
Funds held for future distributions
|
|
|
(13,212
|
)
|
|
|
1,901
|
|
Other
|
|
|
(1,458
|
)
|
|
|
(1,681
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
4,041
|
|
|
|
6,699
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
|
|
|
Expenditures for property, plant and equipment
|
|
|
(27,185
|
)
|
|
|
(29,576
|
)
|
Proceeds from sale of assets, net of costs
|
|
|
1,760
|
|
|
|
4,882
|
|
Notes receivable and other
|
|
|
(40
|
)
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities from operations
|
|
|
(25,465
|
)
|
|
|
(24,709
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
|
54,374
|
|
|
|
59,404
|
|
Principal payment on long-term debt
|
|
|
(37,989
|
)
|
|
|
(39,737
|
)
|
Purchase of treasury stock and other financing activities
|
|
|
(280
|
)
|
|
|
10
|
|
Dividends paid
|
|
|
(3,672
|
)
|
|
|
(3,740
|
)
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities from operations
|
|
|
12,433
|
|
|
|
15,937
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
(8,991
|
)
|
|
|
(2,073
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
6,988
|
|
|
|
1,979
|
|
|
|
|
|
|
|
|
|
|
Cash (overdraft) and cash equivalents, end of period
|
|
$
|
(2,003
|
)
|
|
$
|
(94
|
)
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-57
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Unaudited
Consolidated Statements of Comprehensive Income (Loss)
FOR THE
SIX MONTHS ENDED DECEMBER 31
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
|
(Amounts in thousands)
|
|
|
Net income
|
|
$
|
14,916
|
|
|
$
|
1,669
|
|
Other comprehensive income (loss), net of tax:
|
|
|
|
|
|
|
|
|
Foreign currency translation adjustment
|
|
|
|
|
|
|
|
|
Current period change
|
|
|
(246
|
)
|
|
|
64
|
|
Oil and gas derivatives:
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
66,562
|
|
|
|
3,099
|
|
Reclassification to earnings
|
|
|
(371
|
)
|
|
|
(12,827
|
)
|
Interest rate hedging:
|
|
|
|
|
|
|
|
|
Current period transactions
|
|
|
(3,041
|
)
|
|
|
(441
|
)
|
Reclassification to earnings
|
|
|
377
|
|
|
|
1,088
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax
|
|
|
63,281
|
|
|
|
(9,017
|
)
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss)
|
|
$
|
78,197
|
|
|
$
|
(7,348
|
)
|
|
|
|
|
|
|
|
|
|
See notes to unaudited consolidated
financial statements
ECA-58
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and 2008
|
|
1.
|
NATURE OF
ORGANIZATION
|
Energy Corporation of America (the Company) was
formed in June 1993 through an exchange of shares with the
common stockholders of Eastern American Energy Corporation
(Eastern American), successor to Pacific States
Gas & Oil, Inc. which was incorporated on
September 9, 1964. The Company is an independent energy
company. All references to the Company include Energy
Corporation of America and its consolidated subsidiaries.
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Reference is hereby made to the Companys audited financial
statements for the fiscal year ended June 30, 2009, which
contain a summary of major accounting policies follows in
preparation of its consolidated financial statement. Those
policies were also followed in preparing the unaudited interim
consolidated financial statements included herein.
Management of the Company believes that all adjustments,
consisting of only normal recurring accruals, necessary for a
fair presentation of the results of such interim periods have
been made. The results of operations for the period ended
December 31, 2009 are not necessarily indicative of the
results to be expected for the full year.
Recent Accounting Pronouncements
In June
2009, the FASB issued a statement that establishes the FASB
Accounting Standards Codification as the source of authoritative
U.S. generally accepted accounting principles
(U.S. GAAP). The Codification, which changes the
referencing of financial standards, became effective for the
period ended June 30, 2010. The Codification did not change
or alter existing U.S. GAAP.
On July 1, 2009, the Company adopted FASB Interpretation
No. 48, Accounting for Uncertainty in Income
Taxes, now codified in Accounting Standards Codification
(ASC)
740-10,
which clarifies the accounting for uncertainty in income taxes.
Adoption of this interpretation did not have a material impact
on the Companys financial position. The Companys
policy is to reflect potential interest and penalties related to
uncertain tax positions as part of interest and penalty expense,
respectively, when and if they become applicable.
In January 2010, the FASB issued ASU
2010-03
Extractive Activities Oil and Gas, (Topic
932): Oil and Gas Reserve Estimation in order to align the
oil and natural gas reserve estimation and disclosure
requirements with the SECs final rule Modernization
of the Oil and Gas Requirements. ASU
2010-03
is
effective for annual reporting periods ending on or after
December 31, 2009. The statement amends the definition of
proved oil and natural gas reserves and requires all entities to
use the average
first-day-of-month
price during the twelve months period before the ending date
when estimating reserve quantities.
The Companys reportable business segments have been
identified based on the differences in products and service
provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and
crude oil. Revenues for the aggregation and pipeline segment
arise from the aggregation of both Company and third party
produced natural gas volumes and the related transportation. The
Other column includes items related to
ECA-59
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
corporate activities. Management utilizes earnings before
interest, income taxes, depreciation, depletion, amortization
and impairment and exploratory costs (EBITDAX), a
non-GAAP financial measure, to evaluate each segments
operations.
Reconciliation of non-GAAP financial measure is as follows (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
Net income
|
|
$
|
14,916
|
|
|
$
|
1,669
|
|
Add:
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
5,366
|
|
|
|
4,796
|
|
Depletion and depreciation of oil and gas properties
|
|
|
11,496
|
|
|
|
17,179
|
|
Depreciation of pipelines, other property and equipment
|
|
|
2,999
|
|
|
|
3,148
|
|
Exploration and impairment
|
|
|
9,878
|
|
|
|
10,460
|
|
Income tax expense
|
|
|
12,513
|
|
|
|
1,868
|
|
Change in fair value derivatives
|
|
|
(21,842
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
EBITDAX
|
|
$
|
35,326
|
|
|
$
|
39,090
|
|
|
|
|
|
|
|
|
|
|
Summarized financial information for the Companys
reportable segments is shown in the following table (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Aggregation and
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
Pipeline
|
|
|
Other
|
|
|
Consolidated
|
|
|
Six Months Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
49,455
|
|
|
$
|
75,655
|
|
|
$
|
|
|
|
$
|
125,110
|
|
Depreciation, depletion, amortization
|
|
|
12,281
|
|
|
|
1,582
|
|
|
|
632
|
|
|
|
14,495
|
|
Exploratory costs
|
|
|
9,878
|
|
|
|
|
|
|
|
|
|
|
|
9,878
|
|
Operating profit
|
|
|
6,471
|
|
|
|
3,729
|
|
|
|
5,278
|
|
|
|
15,478
|
|
Interest (net)
|
|
|
10,443
|
|
|
|
(3,966
|
)
|
|
|
(1,199
|
)
|
|
|
5,278
|
|
Other (income) & expense
|
|
|
(21,084
|
)
|
|
|
(13
|
)
|
|
|
3,869
|
|
|
|
(17,228
|
)
|
EBITDAX
|
|
|
18,377
|
|
|
|
8,363
|
|
|
|
8,586
|
|
|
|
35,326
|
|
Total assets
|
|
|
460,293
|
|
|
|
45,788
|
|
|
|
32,420
|
|
|
|
538,501
|
|
Capital expenditures
|
|
|
25,505
|
|
|
|
1,680
|
|
|
|
|
|
|
|
27,185
|
|
ECA-60
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and
|
|
|
Aggregation and
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
Pipeline
|
|
|
Other
|
|
|
Consolidated
|
|
|
Six Months Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales to unaffiliated customers
|
|
$
|
47,800
|
|
|
$
|
37,240
|
|
|
$
|
|
|
|
$
|
85,040
|
|
Depreciation, depletion, amortization
|
|
|
17,973
|
|
|
|
1,697
|
|
|
|
657
|
|
|
|
20,327
|
|
Exploratory costs
|
|
|
10,460
|
|
|
|
|
|
|
|
|
|
|
|
10,460
|
|
Operating profit
|
|
|
5,343
|
|
|
|
1,676
|
|
|
|
4,970
|
|
|
|
11,989
|
|
Interest (net)
|
|
|
5,815
|
|
|
|
(3,922
|
)
|
|
|
2,869
|
|
|
|
4,762
|
|
Other (income) & expense
|
|
|
|
|
|
|
(3
|
)
|
|
|
3,693
|
|
|
|
3,690
|
|
EBITDAX
|
|
|
29,016
|
|
|
|
6,229
|
|
|
|
3,845
|
|
|
|
39,090
|
|
Total assets
|
|
|
458,357
|
|
|
|
41,635
|
|
|
|
34,033
|
|
|
|
534,025
|
|
Capital expenditures
|
|
|
27,657
|
|
|
|
1,906
|
|
|
|
13
|
|
|
|
29,576
|
|
Operating profit represents revenues less costs which are
directly associated with such operations.
The Company is exposed to certain risks relating to its ongoing
business operations. The primary risks managed by using
derivative instruments are commodity price risk and interest
rate risk. Swaps and agreements on natural gas and oil
commodities are entered into to manage the price risk associated
with forecasted sales. Interest rate swaps are entered into to
manage interest rate risk associated with the Companys
variable-rate borrowings.
Companies are required to recognize all derivative instruments
as either assets or liabilities at fair value in the statement
of financial position (balance sheet). The Company designates
commodity swap agreements as cash flow hedges of forecasted
sales of commodities and interest rate swaps as cash flow hedges
of variable-rate borrowings.
Cash
flow hedges
For derivative instruments that are designated and qualify a
cash flow hedge, the effective portion of the gain or loss on
the derivative is reported as a component of other comprehensive
income and reclassified into earnings in the same period or
periods during which the hedged transaction affects earnings.
Gains and losses on the derivative representing hedge
ineffectiveness are recognized in current earnings. All parts of
gain or loss on these derivatives are included in the assessment
of hedge effectiveness.
Commodity swap agreements involve payments to or receipts from
counterparties based on the differential between a fixed and
variable price for the commodity. Certain swap instruments used
by the Company do not qualify as cash flow hedges.
Exchange-traded instruments are generally settled with
offsetting positions. Over the counter (OTC) arrangements
require settlement in cash.
ECA-61
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
As of December 31, 2009 and June 30, 2009, the Company
had the following outstanding commodity swaps that were entered
into to hedge forecasted sales:
|
|
|
|
|
|
|
|
|
|
|
Volumes
|
Commodity
|
|
December 31, 2009
|
|
June 30, 2009
|
|
Natural gas
|
|
|
9,236,500 MMBtu
|
|
|
|
10,332,000 MMBtu
|
|
Oil
|
|
|
Bbl
|
|
|
|
18,000 Bbl
|
|
The open positions at December 31, 2009 had maturities for
natural gas swaps extending through June 2012. We expect that
$7,893,000 of deferred net gains on commodity swaps in other
comprehensive income at December 31, 2009 will be
reclassified as earnings during the next twelve months.
Interest rate swap agreements involve payments to or receipts
from counterparties based on the differential between a fixed
interest rate and a variable interest rate applicable to a
specified amount of debt. During November 2007 and January 2008,
the Company entered into three interest-rate swap agreements
with Wells Fargo Foothill, Inc. in an effort to reduce the
potential impact of increases in interest rates on floating-rate
long-term debt.
The three-year agreements cover $100 million in long-term
debt and fix the one-month London Interbank Offered Rate
(LIBOR) over a range of 3.67% to 4.05%. The Company
has partially hedged its exposure to the variability in future
cash flows through January 2011. We expect that $1,843,000 of
deferred net losses on interest rate swaps in other
comprehensive income at December 31, 2009 will be
reclassified into earnings during the next twelve months.
ECA-62
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
Fair values for derivatives are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
Liability Derivatives
|
|
Derivatives Designated as Hedging
|
|
12/31/09
|
|
|
06/30/09
|
|
|
12/31/09
|
|
|
06/30/09
|
|
Instruments under ASC 815
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
Current: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
13,553
|
|
|
$
|
30,640
|
|
|
$
|
12
|
|
|
$
|
281
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
3,151
|
|
|
|
3,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,553
|
|
|
|
30,640
|
|
|
|
3,163
|
|
|
|
3,331
|
|
Long-term: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
1,398
|
|
|
|
651
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
104
|
|
|
|
1,237
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,398
|
|
|
|
651
|
|
|
|
104
|
|
|
|
1,237
|
|
Total Derivatives designated as
hedging instruments under ASC 815
|
|
$
|
14,951
|
|
|
$
|
31,291
|
|
|
$
|
3,267
|
|
|
$
|
4,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives not Designated
|
|
|
|
|
|
|
|
|
|
|
|
|
as hedging instruments under ASC 815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Long-term: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives not designated as
hedging instruments under ASC 815
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives
|
|
$
|
14,951
|
|
|
$
|
31,291
|
|
|
$
|
3,267
|
|
|
$
|
4,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Included in Derivatives under
Current Assets and Current Liabilities.
|
|
(2)
|
|
Included in Derivatives under Other
Assets and Long-term Obligations.
|
All of the Companys derivative instruments are classified
as level 2 fair value measurements.
ECA-63
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
The following table shows the gains (losses) recognized related
to derivatives in ASC 815 cash flow hedging relationships:
The
Effect of Derivative Instruments on the Statement of
Operations
for the Six Months Ended December 31, 2009 and
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
|
|
|
|
|
|
|
|
|
|
or (Loss) Reclassified
|
|
|
|
Amount of Gain or
|
|
|
from Accumulated
|
|
|
|
(Loss) Recognized in OCI on Derivative
|
|
|
OCI into Income
|
|
Derivatives in ASC 815
|
|
(Effective Portion)
|
|
|
(Effective Portion) (1)
|
|
Cash Flow Hedging Relationships
|
|
12/31/09
|
|
|
12/31/08
|
|
|
12/31/09
|
|
|
12/31/08
|
|
|
Commodity contracts
|
|
$
|
5,297
|
|
|
$
|
111,869
|
|
|
$
|
21,926
|
(2)
|
|
$
|
624
|
|
Interest rate contracts
|
|
|
(755
|
)
|
|
|
(5,111
|
)
|
|
|
(1,860
|
) (3)
|
|
|
(634
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,542
|
|
|
$
|
106,758
|
|
|
$
|
20,066
|
|
|
$
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain or
|
|
|
|
(Loss) Recognized in
|
|
Derivatives in ASC 815
|
|
Income on Derivative (Ineffective Portion)
|
|
Cash Flow Hedging Relationships
|
|
12/31/09
|
|
|
12/31/08
|
|
|
Commodity contracts
|
|
$
|
30
|
(4)
|
|
$
|
542
|
|
Interest rate contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
30
|
(4)
|
|
$
|
542
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain
|
|
|
|
or (Loss) Recognized in Income
|
|
Derivatives not Designated as
|
|
on Derivative
|
|
Hedging Instruments Under ASC 815
|
|
12/31/09
|
|
|
12/31/08
|
|
|
Commodity contracts
|
|
$
|
27
|
(4)
|
|
$
|
22,787
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
If gains and losses associated with
a type of contract (for example, commodity contracts) are
displayed in multiple line items in the income statement, the
entity is required to disclose the amount included in each line
item.
|
|
(2)
|
|
Included in Oil and gas sales.
|
|
(3)
|
|
Included in Interest expense.
|
|
(4)
|
|
Included in Other (income) expense.
|
|
|
5.
|
COMMITMENTS
AND CONTINGENCIES
|
The Company is involved in various legal actions and claims
arising in the ordinary course of business. Management does not
expect that any matter pending against the Company will have a
material adverse effect on the Companys financial position
or results of operations and has established reserves that it
believes are adequate.
ECA-64
ENERGY
CORPORATION OF AMERICA AND SUBSIDIARIES
Notes to
Unaudited Consolidated Financial Statements
For the
Periods Ended December 31, 2009 and
2008 (Continued)
|
|
6.
|
OTHER
COMPREHENSIVE INCOME (LOSS)
|
At December 31, 2009 and June 30, 2009 accumulated
other comprehensive income (loss) (net of tax) consisted of the
following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2009
|
|
|
Foreign currency translation
|
|
$
|
(243
|
)
|
|
$
|
(179
|
)
|
Oil and gas hedging
|
|
|
18,439
|
|
|
|
8,711
|
|
Interest rate hedging
|
|
|
(2,551
|
)
|
|
|
(1,904
|
)
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income
|
|
$
|
15,645
|
|
|
$
|
6,628
|
|
|
|
|
|
|
|
|
|
|
For the six months ended December 31, 2009 and 2008, the
Company established a valuation allowance of $0.4 million
and $1.4 million, respectively, related to the
Companys charitable contribution carryforwards as the
Company does not currently believe that it is more likely than
not that all of the federal and state charitable contribution
carryforwards will be fully utilized during their respective
statutory carryforward periods.
|
|
8.
|
FAIR
VALUE MEASUREMENTS
|
The Company has categorized its financial statements into a
three-level fair value hierarchy based on the priority of the
inputs to the valuation technique. All of the Companys
derivative contracts (see Note 3) are included in
Level 2. The Companys carrying value for Notes
Receivable and Long-term Debt approximate fair value.
ECA-65
ANNEX A
SUMMARY RESERVE REPORTS
March 25, 2010
Energy Corporation of America
501 56th Street
Charleston, West Virginia 25304
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared
an estimate of the proved reserves, future production, and
income attributable to certain leasehold and royalty interests
in the underlying properties of the ECA Marcellus Trust 1
as of March 31, 2010. The subject properties are located in
the state of Pennsylvania. The reserves and income data were
estimated based on the definitions and disclosure guidelines of
the United States Securities and Exchange Commission (SEC)
contained in Title 17, Code of Federal Regulations,
Modernization of Oil and Gas Reporting, Final Rule released
January 14, 2009 in the Federal Register (SEC regulations).
The results of our third party study are presented herein. The
properties reviewed by Ryder Scott represent 100 percent of
the total net proved gas reserves of the underlying properties
of the ECA Marcellus Trust 1.
The estimated reserves and future net income amounts presented
in this report, as of March 31, 2010 are related to
hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices
during the
12-month
period prior to the ending date of the period covered in this
report, determined as unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements as required by the SEC regulations.
Actual future prices may vary significantly from the prices
required by SEC regulations; therefore, volumes of reserves
actually recovered and the amounts of income actually received
may differ significantly from the estimated quantities presented
in this report. The results of this study are summarized below.
SEC
PARAMETERS
Estimated
Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
ECA Marcellus Trust 1 Underlying
Properties
As of March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Total Proved
|
|
|
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMCF
|
|
|
21,703
|
|
|
|
16,459
|
|
|
|
155,610
|
|
|
|
193,771
|
|
Income Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Gross Revenue
|
|
$
|
92,320,758
|
|
|
$
|
70,013,877
|
|
|
$
|
661,949,379
|
|
|
$
|
824,284,013
|
|
Deductions
|
|
|
13,850,580
|
|
|
|
23,566,501
|
|
|
|
279,577,616
|
|
|
|
316,994,698
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Income (FNI)
|
|
$
|
78,470,177
|
|
|
$
|
46,447,375
|
|
|
$
|
382,371,763
|
|
|
$
|
507,289,315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted FNI @ 10%
|
|
$
|
42,050,024
|
|
|
$
|
18,580,268
|
|
|
$
|
108,057,099
|
|
|
$
|
168,687,390
|
|
A-1
Energy Corporation of America
March 25, 2010
Page 2
All gas volumes are reported on an as sold basis
expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas
reserves are located.
The estimates of the reserves, future production, and income
attributable to properties in this report were prepared using
the economic software package PHDWin Petroleum Economic
Evaluation Software, a copyrighted program of TRC Consultants
L.C. Ryder Scott has found this program to be generally
acceptable, but notes that certain summaries and calculations
may vary due to rounding and may not exactly match the sum of
the properties being summarized. Furthermore, one line economic
summaries may vary slightly from the more detailed cash flow
projections of the same properties, also due to rounding. The
rounding differences are not material.
The future gross revenue is normally after the deduction of
production taxes but in the State of Pennsylvania there is no
production tax. The deductions incorporate the normal direct
costs of operating the wells, gas transportation costs,
completion costs and development costs. The future net income is
before the deduction of state and federal income taxes and
general administrative overhead, and has not been adjusted for
outstanding loans that may exist nor does it include any
adjustment for cash on hand or undistributed income. Gas
reserves account for the remaining 100 percent of total
future gross revenue from proved reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded
monthly. Future net income was discounted at four other discount
rates which were also compounded monthly. These results are
shown in summary form as follows.
|
|
|
|
|
|
|
Discounted Future Net Income
|
|
|
|
As of March 31, 2010
|
|
Discount Rate Percent
|
|
Total Proved
|
|
|
5
|
|
$
|
279,494,862
|
|
8
|
|
$
|
204,849,089
|
|
12
|
|
$
|
139,938,069
|
|
15
|
|
$
|
106,703,864
|
|
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves
Included in This Report
The proved reserves included herein conform to the definition as
set forth in the Securities and Exchange Commissions
Regulations
Part 210.4-10(a).
An abridged version of the SEC reserves definitions from
210.4-10(a) entitled Petroleum Reserves Definitions
is included as an attachment to this report.
The various reserve status categories are defined under the
attachment entitled Petroleum Reserves Definitions
in this report. The developed non-producing reserves included
herein consist of the behind pipe category.
A-2
Energy Corporation of America
March 25, 2010
Page 3
No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. The gas
volumes included herein do not attribute gas consumed in
operations as reserves.
Reserves are those estimated remaining quantities of petroleum
which are anticipated to be economically producible, as of a
given date, from known accumulations under defined conditions.
All reserve estimates involve some degree of uncertainty. The
uncertainty depends chiefly on the amount of reliable geologic
and engineering data available at the time of the estimate and
the interpretation of these data.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward. The reserves included
herein were estimated using deterministic methods.
Reserves estimates will generally be revised as additional
geologic or engineering data become available or as economic
conditions change. Moreover, estimates of reserves may increase
or decrease as a result of future operations, effects of
regulation by governmental agencies or economic risks. As a
result, the estimates of oil and gas reserves have an intrinsic
uncertainty. The reserves included in this report are therefore
estimates only and should not be construed as being exact
quantities. They may or may not be actually recovered, and if
recovered, the revenues therefrom, and the actual costs related
thereto, could be more or less than the estimated amounts.
The estimates of reserves presented herein were based upon a
detailed study of the underlying properties in which ECA
Marcellus Trust 1 and Energy Corporation of America owns an
interest; however, we have not made any field examination of the
properties. No consideration was given in this report to
potential environmental liabilities that may exist nor were any
costs included for potential liability to restore and clean up
damages, if any, caused by past operating practices.
Estimates
of Reserves
The reserves for the properties included herein were estimated
by performance methods or analogy In general, reserves
attributable to producing wells
and/or
reservoirs were estimated by performance methods such as decline
curve analysis, which utilized extrapolations of historical
production. In certain cases, producing reserves were estimated
by the analogy method where there was inadequate historical
performance data to establish a definitive trend and where the
use of production performance data as a basis for the reserve
estimates was considered to be inappropriate. Reserves
attributable to non-producing and undeveloped reserves included
herein were estimated by the analogy method which utilized all
pertinent well data available through January, 2010.
To estimate economically recoverable oil and gas reserves and
related future net cash flows, we consider many factors and
assumptions including, but not limited to, the use of reservoir
parameters derived from geological and engineering data which
cannot be measured directly, economic criteria based on current
costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v)
and (26), proved reserves must be anticipated to be economically
producible based on existing economic conditions including the
prices and costs at which economic producibility from a
reservoir is to be determined. While it
A-3
Energy Corporation of America
March 25, 2010
Page 4
may reasonably be anticipated that the future prices received
for the sale of production and the operating costs and other
costs relating to such production may also increase or decrease
from existing levels, such changes were, in accordance with
rules adopted by the SEC, omitted from consideration in making
this evaluation.
Energy Corporation of America has informed us that they have
furnished us all of the accounts, records, geological and
engineering data, and reports and other data required for this
investigation. In preparing our forecast of future production
and income, we have relied upon data furnished by Energy
Corporation of America with respect to property interests owned,
production and well tests from examined wells, normal direct
costs of operating the wells or leases, other costs such as
transportation
and/or
processing fees, ad valorem and production taxes, completion and
development costs, and product prices based on the SEC
regulations. Ryder Scott reviewed such factual data for its
reasonableness; however, we have not conducted an independent
verification of the data supplied by Energy Corporation of
America. We consider the assumptions, data, methods and
procedures used in this report appropriate for the purpose
hereof, and we have used all such methods and procedures that we
consider necessary and appropriate to prepare the estimates of
reserves and future net revenues herein.
Future
Production Rates
Our forecasts of future production rates are based on historical
performance from wells now on production. Test data and other
related information were used to estimate the anticipated
initial production rates for those wells or locations that are
not currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until
a decline in ability to produce was anticipated. An estimated
rate of decline was then applied to depletion of the reserves.
If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves
not yet on production, sales were estimated to commence at an
anticipated date furnished by Energy Corporation of America.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand
or allowables set by regulatory bodies. Wells or locations that
are not currently producing may start producing earlier or later
than anticipated in our estimates.
Hydrocarbon
Prices
As previously stated, the hydrocarbon prices used herein are
based SEC price parameters using the average prices during the
12-month
period prior to the ending date of the period covered in this
report, determined as the unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements. For hydrocarbon products sold under
contract, the contract prices including fixed and determinable
escalations, exclusive of inflation adjustments, were used until
expiration of the contract. Upon contract expiration, the prices
were adjusted to the
12-month
unweighted arithmetic average as previously described. Product
prices which were actually used for each property reflect
adjustment for gravity, quality, local conditions,
and/or
distance from market.
A-4
Energy Corporation of America
March 25, 2010
Page 5
The effects of derivative instruments designated as price hedges
of oil and gas quantities are not reflected in our individual
property evaluations.
Costs
Operating costs for the leases and wells in this report are
supplied by Energy Corporation of America and include only those
costs directly applicable to the leases or wells. The operating
costs include a portion of general and administrative costs
allocated directly to the leases and wells. For operated
properties, the operating costs include an appropriate level of
corporate general administrative and overhead costs. No
deduction was made for loan repayments, interest expenses, or
exploration and development prepayments that were not charged
directly to the leases or wells.
Development costs were furnished to us by Energy Corporation of
America and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. Energy
Corporation of Americas estimates of zero abandonment
costs after salvage value were used in this report. Ryder Scott
has not performed a detailed study of the abandonment costs or
the salvage value and makes no warranty fo
r
Energy
Corporation of Americas estimate.
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the
proved undeveloped category only reserves assigned to
undeveloped locations that we have been assured will definitely
be drilled. Energy Corporation of America has assured us of
their intent and ability to proceed with the development
activities included in this report, and that they are not aware
of any legal, regulatory, political or economic obstacles that
would significantly alter their plans.
Current costs used by Energy Corporation of America were held
constant throughout the life of the properties.
Standards
of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting
firm that has been providing petroleum consulting services
throughout the world for over seventy years. Ryder Scott is
employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of
the size of our firm and the large number of clients for which
we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as
officers or directors of any publicly-traded oil and gas company
and are separate and independent from the operating and
investment decision-making process of our clients. This allows
us to bring the highest level of independence and objectivity to
each engagement for our services.
Ryder Scott actively participates in industry related
professional societies and organizes an annual public forum
focused on the subject of reserves evaluations and SEC
regulations. Many of our staff have authored or co-authored
technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional
skills by actively participating in ongoing continuing education.
A-5
Energy Corporation of America
March 25, 2010
Page 6
Prior to becoming an officer of the Company, Ryder Scott
requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or
certified professional engineers license or a registered
or certified professional geoscientists license, or the
equivalent thereof, from an appropriate governmental authority
or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to ECA
Marcellus Trust 1 and Energy Corporation of America.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to do this work
nor the compensation is contingent on our estimates of reserves
for the properties which were reviewed.
The professional qualifications of the undersigned, the
technical person primarily responsible for evaluating the
reserves information discussed in this report, are included as
an attachment to this letter.
Terms of
Usage
This report was prepared for the exclusive use and sole benefit
of ECA Marcellus Trust 1 and Energy Corporation of America
and may not be put to other use without our prior written
consent for such use. The data and work papers used in the
preparation of this report are available for examination by
authorized parties in our offices. Please contact us if we can
be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration
No. F-1580
Name: Larry T. Nelms, P.E.
Title: Managing Senior Vice President
/sm
A-6
March 25, 2010
Energy Corporation of America
501 56th Street
Charleston, West Virginia 25304
Gentlemen:
At your request, Ryder Scott Company (Ryder Scott) has prepared
an estimate of the proved reserves, future production, and
income attributable to certain royalty interests of ECA
Marcellus Trust 1 as of March 31, 2010. The subject
properties are located in the state of Pennsylvania. The
reserves and income data were estimated based on the definitions
and disclosure guidelines of the United States Securities and
Exchange Commission (SEC) contained in Title 17, Code of
Federal Regulations, Modernization of Oil and Gas Reporting,
Final Rule released January 14, 2009 in the Federal
Register (SEC regulations). The results of our third party study
are presented herein. The properties reviewed by Ryder Scott
represent 100 percent of the total net proved gas reserves
of ECA Marcellus Trust 1.
The estimated reserves and future net income amounts presented
in this report, as of March 31, 2010 are related to
hydrocarbon prices. The hydrocarbon prices used in the
preparation of this report are based on the average prices
during the
12-month
period prior to the ending date of the period covered in this
report, determined as unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements as required by the SEC regulations.
Actual future prices may vary significantly from the prices
required by SEC regulations; therefore, volumes of reserves
actually recovered and the amounts of income actually received
may differ significantly from the estimated quantities presented
in this report. The results of this study are summarized below.
SEC
PARAMETERS
Estimated
Net Reserves and Income Data
Certain Royalty Interests of
ECA Marcellus Trust 1
As of March 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Total Proved
|
|
|
Net Remaining Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas MMCF
|
|
|
18,257
|
|
|
|
13,950
|
|
|
|
72,392
|
|
|
|
104,599
|
|
Income Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Gross Revenue
|
|
$
|
77,662,894
|
|
|
$
|
59,344,037
|
|
|
$
|
307,947,958
|
|
|
$
|
444,954,889
|
|
Deductions
|
|
|
9,778,379
|
|
|
|
7,471,888
|
|
|
|
38,773,108
|
|
|
|
56,023,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future Net Income (FNI)
|
|
$
|
67,884,515
|
|
|
$
|
51,872,149
|
|
|
$
|
269,174,849
|
|
|
$
|
388,931,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted FNI @ 10%
|
|
$
|
38,274,371
|
|
|
$
|
28,887,300
|
|
|
$
|
133,108,756
|
|
|
$
|
200,270,426
|
|
All gas volumes are reported on an as sold basis
expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas
reserves are located.
A-7
Energy Corporation of America
March 25, 2010
Page 2
The estimates of the reserves, future production, and income
attributable to properties in this report were prepared using
the economic software package PHDWin Petroleum Economic
Evaluation Software, a copyrighted program of TRC Consultants
L.C. Ryder Scott has found this program to be generally
acceptable, but notes that certain summaries and calculations
may vary due to rounding and may not exactly match the sum of
the properties being summarized. Furthermore, one line economic
summaries may vary slightly from the more detailed cash flow
projections of the same properties, also due to rounding. The
rounding differences are not material.
The future gross revenue is normally after the deduction of
production taxes but in the State of Pennsylvania this is zero .
The deductions incorporate the normal direct costs of operating
the wells, gas transportation costs, completion costs and
development costs. The future net income is before the deduction
of state and federal income taxes and general administrative
overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or
undistributed income. Gas reserves account for the remaining
100 percent of total future gross revenue from proved
reserves.
The discounted future net income shown above was calculated
using a discount rate of 10 percent per annum compounded
monthly. Future net income was discounted at four other discount
rates which were also compounded monthly. These results are
shown in summary form as follows.
|
|
|
|
|
|
|
Discounted Future Net Income
|
|
|
|
As of March 31, 2010
|
|
Discount Rate Percent
|
|
Total Proved
|
|
|
5
|
|
$
|
266,589,604
|
|
8
|
|
$
|
222,637,119
|
|
12
|
|
$
|
181,841,206
|
|
15
|
|
$
|
159,636,650
|
|
The results shown above are presented for your information and
should not be construed as our estimate of fair market value.
Reserves
Included in This Report
The proved reserves included herein conform to the definition as
set forth in the Securities and Exchange Commissions
Regulations
Part 210.4-10(a).
An abridged version of the SEC reserves definitions from
210.4-10(a) entitled Petroleum Reserves Definitions
is included as an attachment to this report.
The various reserve status categories are defined under the
attachment entitled Petroleum Reserves Definitions
in this report. The developed non-producing reserves included
herein consist of the behind pipe category.
No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. The gas
volumes included herein do not attribute gas consumed in
operations as reserves.
A-8
Energy Corporation of America
March 25, 2010
Page 3
Reserves are those estimated remaining quantities of petroleum
which are anticipated to be economically producible, as of a
given date, from known accumulations under defined conditions.
All reserve estimates involve some degree of uncertainty. The
uncertainty depends chiefly on the amount of reliable geologic
and engineering data available at the time of the estimate and
the interpretation of these data.
Proved oil and gas reserves are those quantities of oil and gas,
which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically
producible from a given date forward. The reserves included
herein were estimated using deterministic methods.
Reserves estimates will generally be revised as additional
geologic or engineering data become available or as economic
conditions change. Moreover, estimates of reserves may increase
or decrease as a result of future operations, effects of
regulation by governmental agencies or economic risks. As a
result, the estimates of oil and gas reserves have an intrinsic
uncertainty. The reserves included in this report are therefore
estimates only and should not be construed as being exact
quantities. They may or may not be actually recovered, and if
recovered, the revenues therefrom, and the actual costs related
thereto, could be more or less than the estimated amounts.
The estimates of reserves presented herein were based upon a
detailed study of the properties in which ECA Marcellus
Trust 1 owns an interest; however, we have not made any
field examination of the properties. No consideration was given
in this report to potential environmental liabilities that may
exist nor were any costs included for potential liability to
restore and clean up damages, if any, caused by past operating
practices.
Estimates
of Reserves
The reserves for the properties included herein were estimated
by performance methods or analogy In general, reserves
attributable to producing wells
and/or
reservoirs were estimated by performance methods such as decline
curve analysis. which utilized extrapolations of historical
production January, 2010 in those cases where such data were
considered to be definitive. In certain cases, producing
reserves were estimated by the analogy method where there were
inadequate historical performance data to establish a definitive
trend and where the use of production performance data as a
basis for the reserve estimates was considered to be
inappropriate. Reserves attributable to non-producing and
undeveloped reserves included herein were estimated by the
analogy method which utilized all pertinent well and seismic
data available through January, 2010.
To estimate economically recoverable oil and gas reserves and
related future net cash flows, we consider many factors and
assumptions including, but not limited to, the use of reservoir
parameters derived from geological and engineering data which
cannot be measured directly, economic criteria based on current
costs and SEC pricing requirements, and forecasts of future
production rates. Under the SEC regulations 210.4-10(a)(22)(v)
and (26), proved reserves must be anticipated to be economically
producible based on existing economic conditions including the
prices and costs at which economic producibility from a
reservoir is to be determined. While it may reasonably be
anticipated that the future prices received for the sale of
production and the operating costs and other costs relating to
such production may also increase or decrease from existing
levels, such changes were, in accordance with rules adopted by
the SEC, omitted from consideration in making this evaluation.
A-9
Energy Corporation of America
March 25, 2010
Page 4
Energy Corporation of America has informed us that they have
furnished us all of the accounts, records, geological and
engineering data, and reports and other data required for this
investigation. In preparing our forecast of future production
and income, we have relied upon data furnished by Energy
Corporation of America with respect to property interests owned,
production and well tests from examined wells, normal direct
costs of operating the wells or leases, other costs such as
transportation
and/or
processing fees, ad valorem and production taxes, completion and
development costs, product prices based on the SEC regulations.
Ryder Scott reviewed such factual data for its reasonableness;
however, we have not conducted an independent verification of
the data supplied by Energy Corporation of America. We consider
the assumptions, data, methods and procedures used in this
report appropriate for the purpose hereof, and we have used all
such methods and procedures that we consider necessary and
appropriate to prepare the estimates of reserves and future net
revenues herein.
Future
Production Rates
Our forecasts of future production rates are based on historical
performance from wells now on production. Test data and other
related information were used to estimate the anticipated
initial production rates for those wells or locations that are
not currently producing. If no production decline trend has been
established, future production rates were held constant, or
adjusted for the effects of curtailment where appropriate, until
a decline in ability to produce was anticipated. An estimated
rate of decline was then applied to depletion of the reserves.
If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves
not yet on production, sales were estimated to commence at an
anticipated date furnished by Energy Corporation of America.
The future production rates from wells now on production may be
more or less than estimated because of changes in market demand
or allowables set by regulatory bodies. Wells or locations that
are not currently producing may start producing earlier or later
than anticipated in our estimates.
Hydrocarbon
Prices
As previously stated, the hydrocarbon prices used herein are
based SEC price parameters using the average prices during the
12-month
period prior to the ending date of the period covered in this
report, determined as the unweighted arithmetic averages of the
prices in effect on the
first-day-of-the-month
for each month within such period, unless prices were defined by
contractual arrangements. For hydrocarbon products sold under
contract, the contract prices including fixed and determinable
escalations, exclusive of inflation adjustments, were used until
expiration of the contract. Upon contract expiration, the prices
were adjusted to the
12-month
unweighted arithmetic average as previously described. Product
prices which were actually used for each property reflect
adjustment for gravity, quality, local conditions,
and/or
distance from market.
The effects of derivative instruments designated as price hedges
of oil and gas quantities are not reflected in our individual
property evaluations.
A-10
Energy Corporation of America
March 25, 2010
Page 5
Costs
Operating costs for the leases and wells in this report are
supplied by Energy Corporation of America and include only those
costs directly applicable the leases or wells. The operating
costs include a portion of general and administrative costs
allocated directly to the leases and wells. For operated
properties, the operating costs include an appropriate level of
corporate general administrative and overhead costs. No
deduction was made for loan repayments, interest expenses, or
exploration and development prepayments that were not charged
directly to the leases or wells.
Development costs were furnished to us by Energy Corporation of
America and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. Energy
Corporation of Americas estimates of zero abandonment
costs after salvage value were used in this report. Ryder Scott
has not performed a detailed study of the abandonment costs or
the salvage value and makes no warranty fo
r
Energy
Corporation of Americas estimate.
Because of the direct relationship between volumes of proved
undeveloped reserves and development plans, we include in the
proved undeveloped category only reserves assigned to
undeveloped locations that we have been assured will definitely
be drilled. Energy Corporation of America has assured us of
their intent and ability to proceed with the development
activities included in this report, and that they are not aware
of any legal, regulatory, political or economic obstacles that
would significantly alter their plans.
Current costs used by Energy Corporation of America were held
constant throughout the life of the properties.
Standards
of Independence and Professional Qualification
Ryder Scott is an independent petroleum engineering consulting
firm that has been providing petroleum consulting services
throughout the world for over seventy years. Ryder Scott is
employee-owned and maintains offices in Houston, Texas; Denver,
Colorado; and Calgary, Alberta, Canada. We have over eighty
engineers and geoscientists on our permanent staff. By virtue of
the size of our firm and the large number of clients for which
we provide services, no single client or job represents a
material portion of our annual revenue. We do not serve as
officers or directors of any publicly-traded oil and gas company
and are separate and independent from the operating and
investment decision-making process of our clients. This allows
us to bring the highest level of independence and objectivity to
each engagement for our services.
Ryder Scott actively participates in industry related
professional societies and organizes an annual public forum
focused on the subject of reserves evaluations and SEC
regulations. Many of our staff have authored or co-authored
technical papers on the subject of reserves related topics. We
encourage our staff to maintain and enhance their professional
skills by actively participating in ongoing continuing education.
Prior to becoming an officer of the Company, Ryder Scott
requires that staff engineers and geoscientists have received
professional accreditation in the form of a registered or
certified professional engineers license or a registered
or certified professional geoscientists license, or
A-11
Energy Corporation of America
March 25, 2010
Page 6
the equivalent thereof, from an appropriate governmental
authority or a recognized self-regulating professional
organization.
We are independent petroleum engineers with respect to ECA
Marcellus Trust 1 and Energy Corporation of America.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to do this work
nor the compensation is contingent on our estimates of reserves
for the properties which were reviewed.
The professional qualifications of the undersigned, the
technical person primarily responsible for evaluating the
reserves information discussed in this report, are included as
an attachment to this letter.
Terms of
Usage
This report was prepared for the exclusive use and sole benefit
of ECA Marcellus Trust 1 and Energy Corporation of America
and may not be put to other use without our prior written
consent for such use. The data and work papers used in the
preparation of this report are available for examination by
authorized parties in our offices. Please contact us if we can
be of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
TBPE Firm Registration
No. F-1580
Name: Larry T. Nelms, P.E.
Title: Managing Senior Vice President
/sm
A-12
ANNEX
B
CALCULATION
OF TARGET DISTRIBUTIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly Target Distributions
|
Quarter
|
|
Subordination
|
|
Target
|
|
Incentive
|
|
Quarter
|
|
Target
|
Ending
|
|
Threshold
|
|
Distribution
|
|
Threshold
|
|
Ending
|
|
Distribution
|
|
June 30, 2010
|
|
$
|
0.217
|
|
|
$
|
0.271
|
|
|
$
|
0.326
|
|
|
June 30, 2020
|
|
$
|
0.451
|
|
September 30, 2010
|
|
|
0.298
|
|
|
|
0.372
|
|
|
|
0.447
|
|
|
September 30, 2020
|
|
|
0.449
|
|
December 31, 2010
|
|
|
0.426
|
|
|
|
0.532
|
|
|
|
0.639
|
|
|
December 31, 2020
|
|
|
0.443
|
|
March 31, 2011
|
|
|
0.413
|
|
|
|
0.516
|
|
|
|
0.619
|
|
|
March 31, 2021
|
|
|
0.426
|
|
June 30, 2011
|
|
|
0.418
|
|
|
|
0.523
|
|
|
|
0.627
|
|
|
June 30, 2021
|
|
|
0.425
|
|
September 30, 2011
|
|
|
0.520
|
|
|
|
0.650
|
|
|
|
0.780
|
|
|
September 30, 2021
|
|
|
0.423
|
|
December 31, 2011
|
|
|
0.544
|
|
|
|
0.680
|
|
|
|
0.815
|
|
|
December 31, 2021
|
|
|
0.417
|
|
March 31, 2012
|
|
|
0.562
|
|
|
|
0.702
|
|
|
|
0.843
|
|
|
March 31, 2022
|
|
|
0.402
|
|
June 30, 2012
|
|
|
0.595
|
|
|
|
0.744
|
|
|
|
0.893
|
|
|
June 30, 2022
|
|
|
0.400
|
|
September 30, 2012
|
|
|
0.607
|
|
|
|
0.759
|
|
|
|
0.911
|
|
|
September 30, 2022
|
|
|
0.399
|
|
December 31, 2012
|
|
|
0.688
|
|
|
|
0.859
|
|
|
|
1.031
|
|
|
December 31, 2022
|
|
|
0.393
|
|
March 31, 2013
|
|
|
0.773
|
|
|
|
0.967
|
|
|
|
1.160
|
|
|
March 31, 2023
|
|
|
0.378
|
|
June 30, 2013
|
|
|
0.771
|
|
|
|
0.964
|
|
|
|
1.157
|
|
|
June 30, 2023
|
|
|
0.377
|
|
September 30, 2013
|
|
|
0.717
|
|
|
|
0.896
|
|
|
|
1.075
|
|
|
September 30, 2023
|
|
|
0.375
|
|
December 31, 2013
|
|
|
0.674
|
|
|
|
0.842
|
|
|
|
1.010
|
|
|
December 31, 2023
|
|
|
0.370
|
|
March 31, 2014
|
|
|
0.623
|
|
|
|
0.779
|
|
|
|
0.935
|
|
|
March 31, 2024
|
|
|
0.360
|
|
June 30, 2014
|
|
|
0.601
|
|
|
|
0.751
|
|
|
|
0.902
|
|
|
June 30, 2024
|
|
|
0.355
|
|
September 30, 2014
|
|
|
0.583
|
|
|
|
0.728
|
|
|
|
0.874
|
|
|
September 30, 2024
|
|
|
0.353
|
|
December 31, 2014
|
|
|
0.561
|
|
|
|
0.701
|
|
|
|
0.841
|
|
|
December 31, 2024
|
|
|
0.348
|
|
March 31, 2015
|
|
|
0.530
|
|
|
|
0.663
|
|
|
|
0.795
|
|
|
March 31, 2025
|
|
|
0.334
|
|
June 30, 2015
|
|
|
|
|
|
|
0.650
|
|
|
|
|
|
|
June 30, 2025
|
|
|
0.330
|
|
September 30, 2015
|
|
|
|
|
|
|
0.639
|
|
|
|
|
|
|
September 30, 2025
|
|
|
0.327
|
|
December 31, 2015
|
|
|
|
|
|
|
0.622
|
|
|
|
|
|
|
December 31, 2025
|
|
|
0.320
|
|
March 31, 2016
|
|
|
|
|
|
|
0.600
|
|
|
|
|
|
|
March 31, 2026
|
|
|
0.305
|
|
June 30, 2016
|
|
|
|
|
|
|
0.587
|
|
|
|
|
|
|
June 30, 2026
|
|
|
0.302
|
|
September 30, 2016
|
|
|
|
|
|
|
0.581
|
|
|
|
|
|
|
September 30, 2026
|
|
|
0.299
|
|
December 31, 2016
|
|
|
|
|
|
|
0.569
|
|
|
|
|
|
|
December 31, 2026
|
|
|
0.292
|
|
March 31, 2017
|
|
|
|
|
|
|
0.546
|
|
|
|
|
|
|
March 31, 2027
|
|
|
0.279
|
|
June 30, 2017
|
|
|
|
|
|
|
0.543
|
|
|
|
|
|
|
June 30, 2027
|
|
|
0.276
|
|
September 30, 2017
|
|
|
|
|
|
|
0.540
|
|
|
|
|
|
|
September 30, 2027
|
|
|
0.274
|
|
December 31, 2017
|
|
|
|
|
|
|
0.531
|
|
|
|
|
|
|
December 31, 2027
|
|
|
0.267
|
|
March 31, 2018
|
|
|
|
|
|
|
0.510
|
|
|
|
|
|
|
March 31, 2028
|
|
|
0.258
|
|
June 30, 2018
|
|
|
|
|
|
|
0.508
|
|
|
|
|
|
|
June 30, 2028
|
|
|
0.253
|
|
September 30, 2018
|
|
|
|
|
|
|
0.506
|
|
|
|
|
|
|
September 30, 2028
|
|
|
0.250
|
|
December 31, 2018
|
|
|
|
|
|
|
0.499
|
|
|
|
|
|
|
December 31, 2028
|
|
|
0.244
|
|
March 31, 2019
|
|
|
|
|
|
|
0.480
|
|
|
|
|
|
|
March 31, 2029
|
|
|
0.233
|
|
June 30, 2019
|
|
|
|
|
|
|
0.479
|
|
|
|
|
|
|
June 30, 2029
|
|
|
0.231
|
|
September 30, 2019
|
|
|
|
|
|
|
0.477
|
|
|
|
|
|
|
September 30, 2029
|
|
|
0.228
|
|
December 31, 2019
|
|
|
|
|
|
|
0.470
|
|
|
|
|
|
|
December 31, 2029
|
|
|
0.223
|
|
March 31, 2020
|
|
|
|
|
|
|
0.458
|
|
|
|
|
|
|
March 31, 2030
|
|
|
1.359
|
|
B-1
TABLE OF CONTENTS
|
|
|
|
|
|
|
|
1
|
|
|
|
|
16
|
|
|
|
|
38
|
|
|
|
|
39
|
|
|
|
|
40
|
|
|
|
|
43
|
|
|
|
|
52
|
|
|
|
|
55
|
|
|
|
|
64
|
|
|
|
|
76
|
|
|
|
|
82
|
|
|
|
|
88
|
|
|
|
|
91
|
|
|
|
|
93
|
|
|
|
|
112
|
|
|
|
|
113
|
|
|
|
|
114
|
|
|
|
|
115
|
|
|
|
|
120
|
|
|
|
|
123
|
|
|
|
|
123
|
|
|
|
|
123
|
|
|
|
|
124
|
|
|
|
|
F-1
|
|
|
|
|
ECA-1
|
|
|
|
|
A-1
|
|
|
|
|
B-1
|
|
ECA Marcellus
Trust I
9,000,000 Common
Units
PROSPECTUS
RAYMOND JAMES
Citi
,
2010
PART II
INFORMATION
REQUIRED IN THE REGISTRATION STATEMENT
|
|
Item 13.
|
Other
Expenses Of Issuance And Distribution.
|
Set forth below are the expenses (other than underwriting
discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered
hereby. With the exception of the Securities and Exchange
Commission registration fee, the FINRA filing and the NYSE
listing fee, the amounts set forth below are estimates.
|
|
|
|
|
Registration fee
|
|
$
|
15,498
|
|
FINRA filing fee
|
|
$
|
22,235
|
|
NYSE listing fee
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Fees and expenses of legal counsel
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
|
|
|
|
|
Total
|
|
$
|
*
|
|
|
|
|
|
|
|
|
|
*
|
|
To be provided by amendment
|
|
|
Item 14.
|
Indemnification
Of Directors And Officers.
|
The trust agreement provides that the trustee and its officers,
agents and employees shall be indemnified from the assets of the
trust against and from any and all liabilities, expenses,
claims, damages or loss incurred by it individually or as
trustee in the administration of the trust and the trust assets,
including, without limitation, any liability, expenses, claims,
damages or loss arising out of or in connection with any
liability under environmental laws, or in the doing of any act
done or performed or omission occurring on account of it being
trustee or acting in such capacity, except such liability,
expense, claims, damages or loss as to which it is liable under
the trust agreement. In this regard, the trustee shall be liable
only for fraud or gross negligence or for acts or omissions in
bad faith and shall not be liable for any act or omission of any
agent or employee unless the trustee has acted in bad faith or
with gross negligence in the selection and retention of such
agent or employee. The trustee is entitled to indemnification
from the assets of the trust and shall have a lien on the assets
of the trust to secure it for the foregoing indemnification.
The West Virginia Business Corporation Act also allows a
corporation to indemnify any person who was or is threatened to
be made party to any action or suit brought by or in the right
of the corporation against all expenses, fines, judgments and
payments made in settlement, including legal fees. The person
must have acted in good faith with no reason to believe the
actions taken were in opposition to the corporation.
Indemnification is not permitted in situations where the party
seeking the indemnity was adjudged liable for negligence or
misconduct regarding tax matters.
The West Virginia Business Corporation Act also provides that
corporations may purchase and maintain insurance to cover
possible indemnities, regardless of whether the corporation is
otherwise allowed to indemnify the party under its provisions.
Article XI of Energy Corporation of Americas
Certificate of Incorporation provides that no director of Energy
Corporation of America shall be liable to Energy Corporation of
America or its stockholders
II-1
for monetary damages for breach of fiduciary duty as a director,
except for liability (i) for any breach of the
directors duty of loyalty to Energy Corporation of America
or its stockholders, (ii) for acts or omissions not in good
faith or which involve intentional misconduct or a knowing
violation of law, (iii) under Section 9 of the
Corporation Act or (iv) for any transaction from which the
director derived an improper personal benefit.
|
|
Item 15.
|
Recent
Sales Of Unregistered Securities.
|
None.
The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Trust of ECA Marcellus Royalty Trust I
|
|
3
|
.2*
|
|
|
|
Articles of Incorporation of Energy Corporation of America.
|
|
3
|
.3*
|
|
|
|
Amended Articles of Incorporation of Energy Corporation of
America dated July 31, 1998.
|
|
3
|
.4*
|
|
|
|
Amended Articles of Incorporation of Energy Corporation of
America dated December 10, 1998.
|
|
3
|
.5*
|
|
|
|
Amended Bylaws of Energy Corporation of America.
|
|
4
|
.1*
|
|
|
|
Trust Agreement dated March 19, 2010 among Energy Corporation of
America and Corporation Trust Company.
|
|
4
|
.2**
|
|
|
|
Form of Amended and Restated Trust Agreement among Energy
Corporation of America
and .
|
|
4
|
.2**
|
|
|
|
Form of Unit Certificate
|
|
5
|
.1**
|
|
|
|
Opinion
of relating
to the validity of the trust units
|
|
8
|
.1**
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax matters
|
|
10
|
.1*
|
|
|
|
Second Amended and Restated Credit Agreement dated September 7,
2007 by and among Energy Corporation of America, the Lenders
signatory thereto and Wells Fargo Foothill, Inc. (now Wells
Fargo Capital Finance, Inc.), as the Arranger and Administrative
Agent.
|
|
10
|
.2*
|
|
|
|
First Amendment to Second Amended and Restated Credit Agreement
dated August 4, 2008, 2009 by and among Energy Corporation
of America, the Lenders signatory thereto and Wells Fargo
Foothill, Inc. (now Wells Fargo Capital Finance, Inc.), as the
Arranger and Administrative Agent.
|
|
10
|
.4**
|
|
|
|
Form of Term Royalty Conveyance
|
|
10
|
.5**
|
|
|
|
Form of Perpetual Royalty Conveyance
|
|
10
|
.6**
|
|
|
|
Form of Administrative and Drilling Services Agreement
|
|
21
|
.1*
|
|
|
|
Subsidiaries of Energy Corporation of America
|
|
23
|
.1*
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.2**
|
|
|
|
Consent
of (contained
in Exhibit 5.1)
|
|
23
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.3**
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Consent of Vinson & Elkins, L.L.P. (contained in Exhibit
8.1)
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II-2
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Exhibit
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Number
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Description
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23
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.4*
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Consent of Ryder Scott
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24
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.1*
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Power of Attorney set forth on the signature page contained in
Part II
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*
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Filed Herewith
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**
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To be filed by amendment
|
The undersigned registrants hereby undertake that:
(1) For purposes of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrants pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(2) For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
The undersigned registrants hereby undertake that, for purposes
of determining any liability under the Securities Act of 1933,
each filing of the registrants annual report pursuant to
section 13(a) or section 15(d) of the Securities
Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plans annual report pursuant to
section 15(d) of the Securities Exchange Act of
1934) that is incorporated by reference in the registration
statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of
such securities at that time shall be deemed to be the initial
bona fide offering thereof.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors,
officers, and controlling persons of the registrants pursuant to
the foregoing provisions, or otherwise, the registrants have
been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer
or controlling person of a registrant in the successful defense
of any action, suit, or proceeding) is asserted by such
director, officer or controlling person in connection with the
securities being registered, the registrants will, unless in the
opinion of their respective counsel the matter has been settled
by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by them
is against public policy as expressed in the Securities Act of
1933 and will be governed by the final adjudication of such
issue.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this registration statement to be
signed on its behalf by the undersigned thereunto duly
authorized, in the City of Denver, State of Colorado, on
April 1, 2010.
ECA Marcellus Trust I
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By:
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Energy Corporation of America,
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as Sponsor
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By:
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/s/ Michael
S. Fletcher
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Name: Michael S. Fletcher
II-4
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this registration statement to be
signed on its behalf by the undersigned thereunto duly
authorized, in the City of Denver, State of Colorado, on
April 1, 2010.
Energy Corporation of America
Name: John Mork
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|
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Title:
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President and Chief Executive Officer
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Each person whose signature appears below appoints Donald C.
Supcoe and Michael S. Fletcher, and each of them, any of whom
may act without the joinder of the other, as his true and lawful
attorneys-in-fact and agents, with full power of substitution
and re-substitution, for him and in his name, place and stead,
in any and all capacities, to sign any and all amendments
(including post-effective amendments) to this Registration
Statement and any Registration Statement (including any
amendment thereto) for this offering that is to be effective
upon filing pursuant to Rule 462(b) under the Securities
Act of 1933, as amended, and to file the same, with all exhibits
thereto, and all other documents in connection therewith, with
the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents, and each of them, full power and
authority to do and perform each and every act and thing
requisite and necessary to be done in connection therewith, as
fully to all intents and purposes as he might or could do in
person, hereby ratifying and confirming all that said
attorneys-in-fact and agents, or any of them, or their or his
substitute and substitutes, may lawfully do or cause to be done
by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed below by the following
persons in the capacities as of the date indicated above.
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Signature
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Title
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/s/ John
Mork
John
Mork
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President and Chief Executive Officer
(Principal executive officer)
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/s/ Donald
C. Supcoe
Donald
C. Supcoe
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Senior Vice President; Secretary and
General Counsel
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/s/ Michael
S. Fletcher
Michael
S. Fletcher
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Chief Financial Officer
(Principal accounting and financial officer)
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/s/ W.
Gaston Caperton, III
W.
Gaston Caperton, III
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Director
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/s/ Peter
H. Coors
Peter
H. Coors
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Director
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/s/ L.B.
Curtis
L.B.
Curtis
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Director
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/s/ John
J. Dorgan
John
J. Dorgan
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Director
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II-5
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|
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Signature
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Title
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/s/ John
Fischer
John
Fischer
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Director
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/s/ Thomas
R. Goodwin
Thomas
R. Goodwin
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Director
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/s/ F.H.
McCullough, III
F.H.
McCullough, III
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Director
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/s/ Julie
Mork
Julie
Mork
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Director
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/s/ Jerry
Neely
Jerry
Neely
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Director
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/s/ Arthur
C. Nielsen, Jr.
Arthur
C. Nielsen, Jr.
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Director
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/s/ Jay
S. Pifer
Jay
S. Pifer
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Director
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II-6
Exhibit 10.1
SECOND AMENDED AND RESTATED CREDIT AGREEMENT
by and among
ENERGY CORPORATION OF AMERICA,
a West Virginia corporation
as Borrower,
THE LENDERS THAT ARE SIGNATORIES HERETO
as the Lenders,
and
WELLS FARGO FOOTHILL, INC.
as the Arranger and Administrative Agent
Dated as of September 7, 2007
TABLE OF CONTENTS
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1.
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DEFINITIONS AND CONSTRUCTION
|
|
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1
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|
2.
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LOAN AND TERMS OF PAYMENT
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27
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3.
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CONDITIONS; TERMS OF AGREEMENT
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50
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4.
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INTENTIONALLY DELETED
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54
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5.
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REPRESENTATIONS AND WARRANTIES
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54
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6.
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AFFIRMATIVE COVENANTS
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60
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7.
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NEGATIVE COVENANTS
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70
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8.
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EVENTS OF DEFAULT
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76
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9.
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THE LENDER GROUPS RIGHTS AND REMEDIES
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77
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10.
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TAXES AND EXPENSES
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78
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11.
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WAIVERS; INDEMNIFICATION
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79
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12.
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NOTICES
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80
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13.
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CHOICE OF LAW AND VENUE; JURY TRIAL WAIVER
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81
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14.
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ASSIGNMENTS AND PARTICIPATIONS; SUCCESSORS
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81
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15.
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AMENDMENTS; WAIVERS
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84
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16.
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AGENT; THE LENDER GROUP
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85
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17.
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GENERAL PROVISIONS
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94
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i
EXHIBITS AND SCHEDULES
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Exhibit A-1
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Form of Assignment and Acceptance
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Exhibit C-1
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Form of Compliance Certificate
|
Exhibit L-1
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Form of LIBOR Notice
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|
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|
Schedule C-1
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|
Commitments
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Schedule D-1
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|
Designated Account
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Schedule P-1
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Partnerships
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Schedule 2.7(a)
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Cash Management Banks
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Schedule 5.1(a)
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|
Borrowing Base Properties
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Schedule 5.1(b)
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|
Material Contracts
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Schedule 5.7
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|
Chief Executive Office; FEIN
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Schedule 5.8(b)
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|
Capitalization of Borrower
|
Schedule 5.8(c)
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|
Capitalization of Borrowers Subsidiaries
|
Schedule 5.10
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Litigation
|
Schedule 5.14
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Environmental Matters
|
Schedule 5.16
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|
Intellectual Property
|
Schedule 5.18
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|
Demand Deposit Accounts
|
Schedule 5.20
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|
Permitted Indebtedness
|
Schedule 5.22
|
|
Taxes
|
Schedule 5.23
|
|
Insurance
|
Schedule 5.25
|
|
Claims and Liabilities
|
Schedule 5.26(b)
|
|
Cumulative Imbalances in Gas Production
and Take or Pay Payments
|
Schedule 5.27
|
|
Operations of Borrowing Base Properties
|
Schedule 5.28
|
|
Hedging Agreements
|
Schedule 6.2(c)
|
|
Total Value of Total Proved Developed Producing Preserves
|
Schedule 7.2
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Liens
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Schedule 7.13
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Existing Investments
|
ii
SECOND AMENDED AND RESTATED CREDIT AGREEMENT
THIS SECOND AMENDED AND RESTATED CREDIT AGREEMENT
(this
Agreement
), is entered into as of
September 7, 2007, between and among, on the one hand, the lenders identified on the signature
pages hereof (such lenders, together with their respective successors and assigns, are referred to
hereinafter each individually as a
Lender
and collectively as the
Lenders
),
WELLS FARGO
FOOTHILL, INC.
, a California corporation, as the arranger and administrative agent for the Lenders
(
Agent
), and, on the other hand,
ENERGY CORPORATION OF AMERICA
, a West Virginia corporation
(
Borrower
).
RECITALS
A. Borrower and Agent (formerly known as Foothill Capital Corporation) and certain lenders
identified therein are party to that certain Credit Agreement dated as of July 10, 2002 (as the
same has been amended, modified or supplemented, the
Original Credit Agreement
) pursuant to which
Agent and Lenders extended Borrower a revolving credit facility of up to $50,000,000.00.
B. Borrower and Agent and certain lenders identified therein are party to that certain Amended
and Restated Credit Agreement dated as of June 10, 2004 which extended the revolving credit
facility and provided additional credit to Borrower in the form of a single advance term loan in
the principal amount of $50,000,000.00 thereby increasing the Total Commitment of the Lender Group
from $50,000,000.00 to $100,000,000.00 (together with the Original Credit Agreement, the
Amended
and Restated Credit Agreement
).
C. Borrower and Agent and certain lenders identified therein further amended the Amended and
Restated Credit Agreement pursuant to the terms of that certain First Amendment dated September 3,
2004, that certain Second Amendment dated June 20, 2005, that certain Third Amendment dated June
29, 2005, that certain Fourth Amendment dated August 16, 2005, that certain Fifth Amendment dated
October 5, 2005, that certain Sixth Amendment dated November 18, 2005, that certain Seventh
Amendment dated August 24, 2006 (which amendment, among other things, extended the Maturity Date to
July 10, 2011, and increased the Maximum Revolver Amount to $75,000,000.00 and the Term Loan Amount
to $75,000,000.00 thereby increasing the Maximum Loan Amount to $150,000,000.00), that certain
Letter Agreement dated effective as of November 17, 2006, and that certain Letter Agreement dated
April 6, 2007 (collectively with the Amended and Restated Credit Agreement, the
Existing Credit
Agreement
).
D. Borrower has requested an increase in the Maximum Loan Amount to $200,000,000.00,
consisting of a Maximum Revolver Amount of up to $100,000,000.00 and a Term Loan Amount of up to
$100,000,000.00.
E. As a result of the foregoing, and in consideration of the premises herein contained and
other good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties, intending to be legally bound, hereby agree to amend and restate the
Existing Credit Agreement to read in its entirety as follows:
1.
|
|
DEFINITIONS AND CONSTRUCTION.
|
1.1.
Definitions
. As used in this Agreement, the following terms shall have the
following definitions:
A&W
means Allegheny & Western Energy Corporation, a West Virginia corporation.
-1-
Account Debtor
means any Person who is or who may become obligated under, with respect to,
or on account of, an Account.
Accounts
means all currently existing and hereafter arising accounts, contract rights, and
all other forms of obligations owing to Borrower or any of its Subsidiaries, arising from its
partnership interests or other interests in the Partnerships or from its membership interests or
other interests in the LLC or out of the sale or lease of goods, Hydrocarbons, or Oil and Gas
Properties or the rendition of services by Borrower or any of its Subsidiaries, irrespective of
whether earned by performance, and any and all credit insurance, guaranties or security therefor.
ACH Transactions
means any cash management or related services (including the Automated
Clearing House processing of electronic funds transfers through the direct Federal Reserve Fedline
system) provided by Wells Fargo or its Affiliates for the account of Borrower or its Subsidiaries.
Additional Term Loan
means the term loan in the principal amount equal to the Additional
Term Loan Amount made by Lenders to Borrower pursuant to
Section 2.2
of this Agreement.
Additional Term Loan Amount
means $25,000,000.00.
Advances
has the meaning set forth in
Section 2.1(a)
.
Affiliate
means, as applied to any Person, any other Person who, directly or indirectly,
controls, is controlled by, or is under common control with, such Person. For purposes of this
definition, control means the possession, directly or indirectly, of the power to direct the
management and policies of a Person, whether through the ownership of Stock, by contract, or
otherwise;
provided
,
however
, that, in any event, (a) any Person which owns
directly or indirectly 11.5% or more of the securities having ordinary voting power for the
election of directors or other members of the governing body of a Person or 11.5% or more of the
partnership or other ownership interests of a Person (other than as a limited partner of such
Person) shall be deemed to control such Person; (b) each director (or comparable manager) of a
Person shall be deemed to be an Affiliate of such Person; and (c) each partnership or joint venture
in which a Person is a partner or joint venturer shall be deemed to be an Affiliate of such Person.
Agent
means Foothill, solely in its capacity as agent for the Lenders hereunder, and any
successor thereto.
Agents Account
means an account at a bank designated by Agent from time to time as the
account into which Borrower shall make all payments to Agent for the benefit of the Lender Group
and into which the Lender Group shall make all payments to Agent under this Agreement and the other
Loan Documents; unless and until Agent notifies Borrower and the Lender Group to the contrary,
Agents Account shall be that certain deposit account bearing account number 323-266193 and
maintained by Agent with JPMorgan Chase Bank, 4 New York Plaza, 15th Floor, New York, New York
10004, ABA #021000021.
Agent Advances
has the meaning set forth in
Section 2.
3(e)(i)
.
Agents Liens
means the Liens granted by Borrower and its Subsidiaries to Agent for the
benefit of the Lender Group under the Loan Documents.
Agent-Related Persons
means Agent together with its Affiliates, officers, directors,
employees, and agents.
-2-
Agreement
has the meaning set forth in the preamble hereto.
Applicable Margin
means, on any day, and with respect to any Obligation, the applicable per
annum percentage set forth in the table shown below, based on the average monthly Revolver Usage
for the immediately preceding month:
|
|
|
|
|
Average Monthly
Revolver Usage
|
|
Base Rate
Loans
|
|
LIBOR Rate
Loans
|
$0 to $40,000,000.00
|
|
Less 0.25%
|
|
Plus 1.50%
|
$40,000,000.01 to $75,000,000.00
|
|
Plus 0.00%
|
|
Plus 1.75%
|
Greater than $75,000,000.00
|
|
Plus 0.25%
|
|
Plus 2.00%
|
Applicable Prepayment Premium
means, as of any date of determination, an amount equal to (a)
during the period of time from and including July 11, 2007 up to and including July 10, 2008, 1%
times
the Maximum Loan Amount, (b) during the period of time from and including July 11, 2008 up to
and including July 10, 2009, 0.5%
times
the Maximum Loan Amount, and (c) during the period of time
from and including July 11, 2009 up to July 10, 2012, 0.25%
times
the Maximum Loan Amount.
Approved Engineer
means Ryder Scott Company Petroleum Consultants or any other independent
petroleum engineer satisfactory to Lender.
Assignee
has the meaning set forth in
Section 14.1(a)
.
Assignment and Acceptance
means an Assignment and Acceptance Agreement substantially in the
form of
Exhibit A-1
.
Authorized Person
means any officer or other employee of Borrower.
Availability
means, as of any date of determination, if such date is a Business Day, and
determined at the close of business on the immediately preceding Business Day, if such date of
determination is not a Business Day, the amount that Borrower is entitled to borrow as Advances
under
Section 2.1
(after giving effect to all then outstanding Obligations (other than Bank
Products Obligations) and all sublimits and reserves applicable hereunder).
Bank Product
means any financial accommodation extended to Borrower or its Subsidiaries by a
Bank Product Provider (other than pursuant to this Agreement) including: (a) credit cards, (b)
credit card processing services, (c) debit cards, (d) purchase cards, (e) ACH Transactions, (f)
cash management, including controlled disbursement, accounts or services, or (g) transactions under
Hedge Agreements.
Bank Product Agreements
means the Hedging Agreements and cash management service agreements
entered into from time to time by Borrower, its Subsidiaries, the Partnerships, and the LLC with a
Bank Product Provider in connection with the obtaining of any of the Bank Products.
Bank Product Obligations
means all obligations, liabilities, contingent reimbursement
obligations, fees, and expenses owing by Borrower, its Subsidiaries, the Partnerships, and the LLC
to any Bank Product Provider pursuant to or evidenced by the Bank Product Agreements and
irrespective of whether for the payment of money, whether direct or indirect, absolute or
contingent, due or to become due, now existing or hereafter arising, and including all such amounts
that Borrower or any Subsidiary is obligated to reimburse to Agent or any member of the Lender
Group as a result of Agent or such member of the Lender Group purchasing participations from, or
executing indemnities or reimbursement
-3-
obligations to, a Bank Product Provider with respect to the Bank Products provided by such
Bank Product Provider to Borrower or its Subsidiaries pursuant to the Bank Product Agreements.
Bank Product Provider
means Wells Fargo or any of its Affiliates, and, with respect to
Hedging Agreements between Borrower and Bank of America, N.A., if, and only to the extent, Agent
has timely received such information in writing in connection therewith from Bank of America, N.A.
as Agent may, from time to time, request, Bank of America, N.A.
Bank Product Reserves
means, as of any date of determination, the amount of reserves that
Agent has established (based upon the Bank Product Providers reasonable determination of the
credit exposure of Borrower and its Subsidiaries in respect of then extant Bank Products) in
respect of Bank Products then provided or outstanding.
Bankruptcy Code
means Title 11 of the United States Code, as in effect from time to time.
Base LIBOR Rate
means the rate per annum, determined by Agent in accordance with its
customary procedures, and utilizing such electronic or other quotation sources as it considers
appropriate (rounded upwards, if necessary, to the next 1/100%), to be the rate at which Dollar
deposits (for delivery on the first day of the requested Interest Period) are offered to major
banks in the London interbank market 2 Business Days prior to the commencement of the requested
Interest Period, for a term and in an amount comparable to the Interest Period and the amount of
the LIBOR Rate Loan requested (whether as an initial LIBOR Rate Loan or as a continuation of a
LIBOR Rate Loan or as a conversion of a Base Rate Loan to a LIBOR Rate Loan) by Borrower in
accordance with this Agreement, which determination shall be conclusive in the absence of manifest
error.
Base Rate
means, the rate of interest announced, from time to time, within Wells Fargo at
its principal office in San Francisco as its prime rate, with the understanding that the prime
rate is one of Wells Fargos base rates (not necessarily the lowest of such rates) and serves as
the basis upon which effective rates of interest are calculated for those loans making reference
thereto and is evidenced by the recording thereof after its announcement in such internal
publication or publications as Wells Fargo may designate.
Base Rate Loan
means the portion of the Advances or the Term Loan that bears interest at a
rate determined by reference to the Base Rate.
Basis Differential
means, in the case of any Borrowing Base Properties, the difference
between the NYMEX futures contract prices and the sales prices at the delivery point where the oil
and gas, as the case may be, produced by such Borrowing Base Property is sold.
Benefit Plan
means a defined benefit plan (as defined in
Section 3(35)
of ERISA)
for which Borrower or any Subsidiary or ERISA Affiliate of Borrower has been an employer (as
defined in
Section 3(5)
of ERISA) within the past six years.
Board of Directors
means the board of directors (or comparable managers) of Borrower or any
committee thereof duly authorized to act on behalf of the board of directors (or comparable
managers).
Book Net Worth
means, as of any date of determination, all amounts which, in conformity with
GAAP, would be included as shareholder equity on a consolidated balance sheet of Borrower and its
Subsidiaries.
-4-
Books
means all of Borrowers and its Subsidiaries now owned or hereafter acquired books
and records (including all of their Records indicating, summarizing, or evidencing their assets
(including the Collateral) or liabilities, all of Borrowers and its Subsidiaries Records relating
to its or their business operations or financial condition, and all of its and their goods or
general intangibles related to such information).
Borrower
has the meaning set forth in the preamble to this Agreement.
Borrowers Security Agreement
means the Second Amended and Restated Security Agreement dated
of even date herewith executed by Borrower assigning to Agent, and granting Agent a security
interest in, the Intercompany Notes, in form, scope, and substance acceptable to Agent.
Borrowing
means a borrowing hereunder consisting of Advances (or term loans, in the case of
the Term Loan) made on the same day by the Lenders (or Agent on behalf thereof), or by Swing Lender
in the case of a Swing Loan, or by Agent in the case of an Agent Advance.
Borrowing Base
has the meaning set forth in
Section 2.1(a)
.
Borrowing Base Properties
means the Mortgaged Properties and the Oil and Gas Properties of
the Partnerships and the LLC, including, without limitation, the Oil and Gas Properties set forth
on
Schedule 5.1(a)
.
Business Day
means any day that is not a Saturday, Sunday, or other day on which national
banks are authorized or required to close in the state of Georgia, except that, if a determination
of a Business Day shall relate to a LIBOR Rate Loan, the term Business Day also shall exclude any
day on which banks are closed for dealings in Dollar deposits in the London interbank market.
Capital Expenditures
means, with respect to any Person for any period, the aggregate of all
expenditures by such Person and its Subsidiaries during such period that are capital expenditures
as determined in accordance with GAAP, whether such expenditures are paid in cash or financed.
Capital Lease
means a lease that is required to be capitalized for financial reporting
purposes in accordance with GAAP.
Capitalized Lease Obligation
means that portion of the obligations under a Capital Lease
that is required to be capitalized in accordance with GAAP.
Cash Equivalents
means (a) marketable direct obligations issued or unconditionally
guaranteed by the United States or issued by any agency thereof and backed by the full faith and
credit of the United States, in each case maturing within 1 year from the date of acquisition
thereof, (b) marketable direct obligations issued by any state of the United States or any
political subdivision of any such state or any public instrumentality thereof maturing within 1
year from the date of acquisition thereof and, at the time of acquisition, having one of the two
highest ratings obtainable from either Standard & Poors Rating Group (
S&P
) or Moodys Investors
Service, Inc. (
Moodys
), (c) commercial paper maturing no more than 270 days from the date of
creation thereof and, at the time of acquisition, having a rating of at least A-1 from S&P or at
least P-1 from Moodys, and (d) certificates of deposit or bankers acceptances maturing within 1
year from the date of acquisition thereof either (i) issued by any bank organized under the laws of
the United States or any state thereof having at the date of acquisition thereof combined capital
and surplus of not less than $250,000,000, (e) Deposit Accounts maintained with (i) any bank that
satisfies the criteria described in
clause (d)
above, or (ii) any other bank organized
under the laws of the United States or any state thereof so long as the amount maintained with any
such other bank is less than
-5-
or equal to $100,000 and is insured by the Federal Deposit Insurance Corporation, and (f)
Investments in money market funds substantially all of whose assets are invested in the types of
assets described in clauses (a) through (e) above.
Cash Management Account
has the meaning set forth in
Section 2.7(a)
.
Cash Management Agreements
means the Cash Management Agreement executed and delivered to
Agent in connection with the Existing Credit Agreement.
Cash Management Bank
has the meaning set forth in
Section 2.7(a)
.
CERCLA
means the Comprehensive Environmental Response Corporation, and Liability Act of
1980, 42 U.S.C. Section 9601,
et. seq.
, as amended from time to time.
Change of Control
means (a) any person or group (within the meaning of Sections 13(d)
and 14(d) of the Exchange Act) becomes the beneficial owner (as defined in Rule 13d-3 under the
Exchange Act), directly or indirectly, of 10%, or more, of the Stock of Borrower having the right
to vote for the election of members of the Board of Directors, or (b) a majority of the members of
the Board of Directors do not constitute Continuing Directors, or (c) Borrower ceases to own and
control, directly or indirectly, 100% of the outstanding capital Stock of each of the Pledging
Subsidiaries.
Closing Date
means the date of the making of the initial Advance or Term Loan (or other
extension of credit) under the Existing Credit Agreement.
Code
means the Georgia Uniform Commercial Code, as in effect from time to time;
provided
,
however
, that in the event that, by reason of mandatory provisions of
law, any or all of the attachment, perfection, priority, or remedies with respect to Agents Lien
on any Collateral is governed by the Uniform Commercial Code as enacted and in effect in a
jurisdiction other than the State of Georgia, the term Code shall mean the Uniform Commercial
Code as enacted and in effect in such other jurisdiction solely for purposes of the provisions
thereof relating to such attachment, perfection, priority, or remedies.
Collateral
means all assets and interests in assets and proceeds thereof, now owned or
hereafter acquired by Borrower or its Subsidiaries in or upon which a Lien is granted under any of
the Loan Documents.
Collateral Access Agreement
means a landlord waiver, bailee letter, or acknowledgement
agreement of any lessor, warehouseman, processor, consignee, or other Person in possession of,
having a Lien upon, or having rights or interests in Borrowers or its Subsidiaries Books,
Equipment or Inventory, in each case, in form and substance satisfactory to Agent.
Collateral Value Amount
has the meaning set forth in
Section 6.23
.
Collections
means
all
cash, checks, notes, instruments, and other items of payment
(including insurance proceeds, proceeds of cash sales, rental proceeds, and tax refunds) of
Borrower and each of its Subsidiaries including, its rights to distributions from the LLC and the
Partnerships.
Commitment
means, with respect to each Lender, its Revolver Commitment, its Term Loan
Commitment, or its Total Commitment, as the context requires, and, with respect to all Lenders,
their Revolver Commitments, their Term Loan Commitments, or their Total Commitments, as the context
requires, in each case as such Dollar amounts are set forth beside such Lenders name under the
applicable heading on
Schedule C-1
or on the signature page of the Assignment and
Acceptance pursuant
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to which such Lender became a Lender hereunder, as such amounts may be reduced or increased
from time to time pursuant to assignments made in accordance with the provisions of
Section
14.1
.
Compliance Certificate
means a certificate substantially in the form of
Exhibit C-1
delivered by the president or chief financial officer of Borrower to Agent.
Continuing Director
means (a) any member of the Board of Directors who was a director (or
comparable manager) of Borrower on the Closing Date, and (b) any individual who becomes a member of
the Board of Directors after the Closing Date if such individual was appointed or nominated for
election to the Board of Directors by a majority of the Continuing Directors, but excluding any
such individual originally proposed for election in opposition to the Board of Directors in office
at the Closing Date in an actual or threatened election contest relating to the election of the
directors (or comparable managers) of Borrower (as such terms are used in Rule 14a-11 under the
Exchange Act) and whose initial assumption of office resulted from such contest or the settlement
thereof.
Contribution Agreement
means the Second Amended and Restated Contribution and
Indemnification Agreement among Borrower and the Pledging Subsidiaries.
Control Agreement
means a control agreement, in form and substance satisfactory to Agent,
executed and delivered by the Borrower or any of its Subsidiaries, Agent, and the applicable
securities intermediary with respect to a Securities Account or a bank with respect to a DDA.
Daily Balance
means, as of any date of determination and with respect to any Obligation, the
amount of such Obligation owed at the end of such day.
DDA
means any checking or other demand deposit account maintained by Borrower or any
Subsidiary.
Default
means an event, condition, or default that, with the giving of notice, the passage
of time, or both, would be an Event of Default.
Defaulting Lender
means any Lender that fails to make any Advance or Term Loan (or other
extension of credit) that it is required to make hereunder on the date that it is required to do so
hereunder.
Defaulting Lender Rate
means (a) for the first 3 days from and after the date the relevant
payment is due, the Base Rate, and (b) thereafter, at the interest rate then applicable to Advances
that are Base Rate Loans (inclusive of the Base Rate Margin applicable thereto).
Designated Account
means that certain DDA of Borrower identified on
Schedule D-1
.
Designated Account Bank
means Wells Fargo.
Disbursement Letter
means an instructional letter executed and delivered by Borrower to
Agent regarding the extensions of credit to be made on the Closing Date and/or thereafter, the form
and substance of which is satisfactory to Agent.
Dollars
or
$
means United States dollars.
Eastern American
means Eastern American Energy Corporation, a West Virginia corporation.
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EBITDAX
means, with respect to any fiscal period, Borrowers and its Subsidiaries
consolidated net earnings (or loss), as determined in accordance with GAAP, minus extraordinary
gains, plus extraordinary losses, minus gain on sale of Permitted Dispositions, plus loss on sale
of Permitted Dispositions, plus interest expense, income taxes, depletion, depreciation and
amortization, exploration and impairment expense, and valuation losses that recognize changes in
the value of derivatives minus valuation gains that recognize changes in the value of derivatives
to the extent that such changes in the value of derivatives were included in consolidated net
earnings (or loss) plus cash received from Permitted Dispositions to the extent that such cash is
paid to Agent for application to the Obligations.
Eligible Proved Developed Producing Reserves
means the Eligible Proved Developed Producing
Reserves of the Partnerships and the LLC and the Eligible Proved Developed Producing Reserves of
the Pledging Subsidiaries, the Hydrocarbons from which are directly deliverable from the Wells to
the Gathering System or to a transporter or buyer which is a non-Affiliate of Borrower or its
Subsidiaries.
Eligible Proved Developed Producing Reserves of the Partnerships and the LLC
means the
Proved Developed Producing Reserves of the Partnerships and the LLC that (a) are identified on
Schedule 5.1(a)
, and (b) comply in all material respects with each and all of the
representations and warranties made by Borrower to Agent in the Loan Documents. An item of Proved
Developed Producing Reserves of the Partnerships and the LLC shall not be included in Eligible
Proved Developed Producing Reserves of the Partnerships and the LLC if:
(i) the LLC or the applicable Partnership is not Solvent or subject to an Insolvency
Proceeding;
(ii) it is not owned by the LLC or the applicable Partnership, or the LLC or the
applicable Partnership does not have good, valid, and indefeasible title thereto, or the
title information relating thereto is not satisfactory;
(iii) Borrower and its Subsidiaries have not assigned to Agent and granted Agent a
first priority perfected security interest in and to their interests in the LLC and the
applicable Partnership and their share of monies, distributions, profits and revenues from
the LLC and the Partnership;
(iv) any consents or approvals required for Borrower or any of its Subsidiaries to
assign or grant a security interest in accordance with (iii) above have not been obtained
and delivered to Agent; or
(v) it is subject to a Lien in favor of a Person (other than Agent) or any order,
judgment, writ, or decree which either restricts or purports to restrict the ability of the
LLC or the applicable Partnership to grant Liens to Persons on or in respect of its assets
and properties; other than Permitted Liens.
Eligible Proved Developed Producing Reserves of the Pledging Subsidiaries
means the Proved
Developed Producing Reserves of the Pledging Subsidiaries that (a) are subject to a duly executed
and recorded Mortgage that creates a valid and enforceable first priority perfected lien on and
security interest in the Oil and Gas Properties attributable thereto; (b) are identified on
Schedule 5.1(a)
; and (c) comply in all material respects with each and all of the
representations and warranties made by the Pledging Subsidiaries to Agent in the Loan Documents.
An item of Proved Developed Producing Reserves of the Pledging Subsidiaries shall not be included
in Eligible Proved Developed Producing Reserves of the Pledging Subsidiaries if:
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(i) the Pledging Subsidiary is not Solvent or subject to an Insolvency Proceeding;
(ii) it is not owned by a Pledging Subsidiary or a Pledging Subsidiary does not have
good, valid, and indefeasible title thereto, or the title information relating thereto is
not satisfactory to Agent;
(iii) it is not subject to a valid, enforceable and perfected first priority Lien and
security interest in favor of Agent created by a duly executed and recorded Mortgage;
(iv) any consents or approvals required for its valid transfer, assignment, pledge or
mortgage have not been obtained and delivered to Agent; or
(v) it is subject to a Lien in favor of any third Person or any order, judgment, writ,
or decree which either restricts or purports to restrict the ability of Borrower or a
Pledging Subsidiary to grant Liens to other Persons on or in respect of its respective
assets or properties, other than Permitted Liens.
Eligible Transferee
means (a) a commercial bank organized under the laws of the United
States, or any state thereof, and having total assets in excess of $250,000,000, (b) a commercial
bank organized under the laws of any other country which is a member of the Organization for
Economic Cooperation and Development or a political subdivision of any such country and which has
total assets in excess of $250,000,000, provided that such bank is acting through a branch or
agency located in the United States, (c) a finance company, insurance company, or other financial
institution or fund that is engaged in making, purchasing, or otherwise investing in commercial
loans in the ordinary course of its business and having (together with its Affiliates) total assets
in excess of $250,000,000, (d) any Affiliate (other than individuals) of a Lender that was party
hereto as of the Closing Date, (e) so long as no Event of Default has occurred and is continuing,
any other Person approved by Agent and Borrower, and (f) during the continuation of an Event of
Default, any other Person approved by Agent.
Energy Business
means (a) the acquisition, exploration, exploitation, development, operation
and disposition of interests in Oil and Gas Properties; (b) the gathering, marketing, treating,
processing, storage, selling and transporting of any production from such interests or properties
including, without limitation, the marketing of Hydrocarbons obtained from third Persons; (c) any
business relating to or arising from exploration for or development, production, treatment,
processing, storage, transportation or marketing of Hydrocarbons, including without limitation (i)
the production of electricity or other sources of power using oil, gas or other hydrocarbon
products, and (ii) providing services in support of or incidental to any such business or activity;
and (d) any activity that is ancillary or necessary or desirable to facilitate the activities
described in clauses (a) through (c) of this definition.
Environmental Actions
means any complaint, summons, citation, notice, directive, order,
claim, litigation, investigation, judicial or administrative proceeding, judgment, letter, or other
communication from any Governmental Authority, or any third party involving violations of
Environmental Laws or releases of Hazardous Materials (a) from any assets, properties, or
businesses of Borrower or its Subsidiaries, or any predecessor in interest, (b) from adjoining
properties or businesses, or (c) from or onto any facilities which received Hazardous Materials
generated by Borrower or its Subsidiaries, or any predecessor in interest.
Environmental Law
means any applicable federal, state, provincial, foreign or local statute,
law, rule, regulation, ordinance, code, binding and enforceable guideline, binding and enforceable
written policy, or rule of common law now or hereafter in effect and in each case as amended, or
any judicial or administrative interpretation thereof, including any judicial or administrative
order, consent decree or
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judgment, in each case, to the extent binding on Borrower or its Subsidiaries, relating to the
environment, the effect of the environment on employee health, or Hazardous Materials, including
the Comprehensive Environmental Response Compensation and Liability Act, 42 USC §9601
et seq.
; the
Resource Conservation and Recovery Act, 42 USC §6901
et seq.
; the Federal Water Pollution Control
Act, 33 USC §1251
et seq.
; the Toxic Substances Control Act, 15 USC §2601
et seq.
; the Clean Air
Act, 42 USC §7401
et seq.
; the Safe Drinking Water Act, 42 USC §3803
et seq.
; the Oil Pollution Act
of 1990, 33 USC §2701
et seq.
; the Emergency Planning and the Community Right-to-Know Act of 1986,
42 USC §11001
et seq.
; the Hazardous Material Transportation Act, 49 USC §1801
et seq.
; and the
Occupational Safety and Health Act, 29 USC §651
et seq.
(to the extent it regulates occupational
exposure to Hazardous Materials); any state and local or foreign counterparts or equivalents, in
each case as amended from time to time.
Environmental Liabilities and Costs
means all liabilities, monetary obligations, Remedial
Actions, losses, damages, punitive damages, consequential damages, treble damages, costs and
expenses (including all reasonable fees, disbursements and expenses of counsel, experts, or
consultants and costs of investigation and feasibility studies), fines, penalties, sanctions, and
interest incurred as a result of any claim or demand by any Governmental Authority or any third
party, and which relate to any Environmental Action.
Environmental Lien
means any Lien in favor of any Governmental Authority for Environmental
Liabilities and Costs.
Equipment
means equipment (as that term is defined in the Code) and includes all of
Borrowers and each Subsidiarys now owned or hereafter acquired right, title, and interest with
respect to equipment, machinery, machine tools, motors, furniture, furnishings, fixtures, vehicles
(including motor vehicles), tools, parts, and goods (other than consumer goods, farm products, or
Inventory), wherever located, including all attachments, accessories, accessions, replacements,
substitutions, additions, and improvements to any of the foregoing.
ERISA
means the Employee Retirement Income Security Act of 1974, as amended, and any
successor statute thereto.
ERISA Affiliate
means (a) any Person subject to ERISA whose employees are treated as
employed by the same employer as the employees of Borrower or its Subsidiaries under IRC Section
414(b), (b) any trade or business subject to ERISA whose employees are treated as employed by the
same employer as the employees of Borrower or its Subsidiaries under IRC Section 414(c), (c) solely
for purposes of Section 302 of ERISA and Section 412 of the IRC, any organization subject to ERISA
that is a member of an affiliated service group of which Borrower or any of its Subsidiaries is a
member under IRC Section 414(m), or (d) solely for purposes of Section 302 of ERISA and Section 412
of the IRC, any Person subject to ERISA that is a party to an arrangement with Borrower or any of
its Subsidiaries and whose employees are aggregated with the employees of Borrower or any of its
Subsidiaries under IRC Section 414(o).
Event of Default
has the meaning set forth in
Section 8
.
Excess Availability
means the amount, as of the date any determination thereof is to be
made, equal to Availability
minus
the aggregate amount, if any, of all trade payables of Borrower
and each of its Subsidiaries aged in excess of 60 days past invoice date unless disputed in good
faith by appropriate proceedings diligently conducted and for which reserves adequate under GAAP
have been established and all book overdrafts in excess of their historical practices with respect
thereto, in each case as determined by Agent in its Permitted Discretion.
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Exchange Act
means the Securities Exchange Act of 1934, as in effect from time to time.
Fee Letter
means that certain fee letter, dated as of even date herewith, between Borrower
and Agent, in form and substance satisfactory to Agent.
FEIN
means Federal Employer Identification Number.
Filing Authorization Letter
means a letter duly executed by Borrower and each Pledging
Subsidiary authorizing Agent to file appropriate financing statements in such office or offices as
may be necessary or, in the opinion of Agent, desirable to perfect the security interests to be
created by the Loan Documents.
Fixed Charge Coverage Ratio
means, with respect to Borrower and its Subsidiaries for any
period, computed on a rolling four-quarter basis, the ratio of (a) EBITDAX for such period minus
Capital Expenditures made (to the extent not already incurred in a prior period) or incurred during
such period, to (b) Fixed Charges for such period.
Fixed Charges
means with respect to Borrower and its Subsidiaries for any period, the sum,
without duplication, on a cash basis, of (a) Interest Expense, (b) principal payments required and
paid during such period in respect of Indebtedness, (c) dividends and (d) all federal, state, and
local income taxes paid for such period.
Foothill
means Wells Fargo Foothill, Inc., a California corporation.
Funding Date
means the date on which a Borrowing occurs.
GAAP
means generally accepted accounting principles as in effect from time to time in the
United States, consistently applied.
Gathering Systems
means all right, title and interest of Borrower and each of its Pledging
Subsidiaries in and to all (i) Hydrocarbon pipelines through which any Hydrocarbons produced from
any of the Wells flows to, or has flowed at any time during the preceding twelve (12) month period
immediately preceding the date of this Agreement, to a master/sales meter from which such
Hydrocarbons can be sold to, or delivered for further transport to, a non-Affiliate of Borrower or
any of its Subsidiaries (
Subject Pipelines
); (ii) meters, compressors, drips, stripping or other
treatment plants or facilities, drips and other facilities located on or used in connection with or
related to the Subject Pipelines; (iii) easements, rights of way, permits, licenses, road boring
agreements and similar contracts and grants pursuant to which the Subject Pipelines were
constructed or exist (whether such rights are contained in a separate instrument or in an oil and
gas lease or other instrument); and (iv) all accounts, contract rights and general intangibles
related to the Hydrocarbons produced from the Wells.
Governing Documents
means, with respect to any Person, the certificate or articles of
incorporation, by-laws, or other organizational documents of such Person.
Governmental Approval
means (a) any authorization, consent, approval, license, ruling,
permit, tariff, rate, certification, waiver, exemption, filing, variance, claim, order, judgment or
decree of or with, (b) any required notice to, (c) any declaration of or with, or (d) any
registration by or with, any Governmental Authority.
-11-
Governmental Authority
means any federal, state, local, or other governmental or
administrative body, instrumentality, board, department, or agency or any court, tribunal,
administrative hearing body, arbitration panel, commission, or other similar dispute-resolving
panel or body.
Governmental Rule
means any statute, law, regulation, ordinance, rule, judgment, order,
decree, permit, concession, grant, franchise, license, agreement, directive, requirement of, or
other governmental restriction or any similar binding form of decision of or determination by, or
any binding interpretation or administration of any of the foregoing by, any Governmental
Authority, whether now or hereafter in effect.
Hazardous Materials
means (a) substances that are defined or listed in, or otherwise
classified pursuant to, any applicable laws or regulations as hazardous substances, hazardous
materials, hazardous wastes, toxic substances, or any other formulation intended to define,
list, or classify substances by reason of deleterious properties such as ignitability, corrosivity,
reactivity, carcinogenicity, reproductive toxicity, or EP toxicity, (b) oil, petroleum, or
petroleum derived substances, natural gas, natural gas liquids, synthetic gas, drilling fluids,
produced waters, and other wastes associated with the exploration, development, or production of
crude oil, natural gas, or geothermal resources, (c) any flammable substances or explosives or any
radioactive materials, and (d) asbestos in any form or electrical equipment that contains any oil
or dielectric fluid containing levels of polychlorinated biphenyls in excess of 50 parts per
million.
Hedging Agreement
means (a) any hedging contract, forward contract, swap agreement, futures
contract or other hydrocarbon pricing protection agreement or option with respect to any such
transaction, designed to hedge against fluctuations in Hydrocarbon prices, (b) any rate swap, rate
cap, rate floor, rate collar, forward rate agreement or other rate protection agreement or option
with respect to any such transaction, designed to hedge against fluctuations in interest rates, and
(c) any other derivative agreement or other similar agreement or arrangement, in each case
evidenced by an ISDA Agreement with appropriate schedule and confirmation.
Hedging Obligations
means, with respect to any Person, all liabilities (including but not
limited to obligations and liabilities arising in connection with or as a result of early or
premature termination of a Hedging Agreement, whether or not occurring as a result of a default
thereunder) of such Person under a Hedging Agreement whether direct or by a guaranty; provided,
however, that such liabilities in connection with Hedging Agreements between Borrower and Bank of
America, N.A. shall be Hedging Obligations hereunder if, and then only to the extent, Agent has
timely received from Bank of America, N.A. such information in writing in connection therewith as
Agent may, from time to time, request.
Highest Lawful Rate
means on any day, the maximum nonusurious rate of interest permitted for
that day by whichever of applicable federal or Georgia law permits the higher interest rate, stated
as a rate per annum.
Hydrocarbon Interests
means all rights, titles and interests in and to oil and gas leases,
oil, gas and mineral leases, other Hydrocarbon leases, mineral interests, mineral servitudes,
overriding royalty interests, royalty interests, net profits interests, production payment
interests, and other similar interests.
Hydrocarbon Interests Hedging Agreement Reserves
means as of any date of determination,
reserves in an amount, if positive, equal to (a) the aggregate Hedging Obligations of Borrower, its
Subsidiaries and Affiliates to Bank Product Providers relating to commodities or commodity prices,
minus
(b) (i) 65%
multiplied
by the PV-10 Value of the Total Proved Developed
Producing Reserves as
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set forth in the Reserve Report most recently delivered to Agent, calculated in a manner
consistent with the determination of the Borrowing Base,
minus
(ii) the Maximum Loan
Amount.
Hydrocarbons
means, collectively, oil, gas, casinghead gas, drip gasoline, natural gasoline,
condensate, distillate and all other liquid or gaseous hydrocarbons and related minerals and all
products therefrom, in each case whether in a natural or a processed state.
Indebtedness
of any Person means, without duplication, (a) all obligations of such Person
for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such
Person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such
Person upon which interest charges are customarily paid, (d) all obligations of such Person under
conditional sale or other title retention agreements relating to Property acquired by such Person,
(e) all obligations of such Person in respect of the deferred purchase price of Property or
services (excluding current accounts payable incurred in the ordinary course of business), (f) all
Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing
right, contingent or otherwise, to be secured by) any Lien on Property owned or acquired by such
Person, whether or not the Indebtedness secured thereby has been assumed, (g) all guarantees by
such Person of Indebtedness of others, (h) all Capitalized Lease Obligations of such Person, (i)
all obligations, contingent or otherwise, of such Person as an account party in respect of letters
of credit and letters of guaranty, (j) all obligations, contingent or otherwise, of such Person in
respect of bankers acceptances, (k) all obligations of such Person with respect to any
arrangement, directly or indirectly, whereby such Person shall sell or transfer any material asset,
and whereby such Person shall then or immediately thereafter rent or lease as lessee such asset or
any part thereof, (l) all recourse and support obligations of such Person with respect to the sale
or discount of any of its accounts receivable, (m) all obligations of such Person with respect to
any arrangement for the purchase of materials, supplies, other Property or services if such
arrangement by its express terms requires that payment be made by such Person regardless of whether
such materials, supplies, other Property or services are delivered or furnished to it, (n) all
obligations of such Person with respect to Production Payments, (o) net liabilities of such Person
under all Hedging Obligations, (p) all obligations of such Person under any prepayment for oil and
gas production or other similar agreement, and (q) all obligations of such Person under operating
leases which require such Person to make payments over the term of such lease based on the purchase
price or appraised value of the Property subject to such lease plus a marginal interest rate, and
used primarily as a financing vehicle for, or to monetize, such Property. The Indebtedness of any
Person shall include the Indebtedness of any other entity (including any partnership in which such
Person is a general partner) to the extent such Person is liable therefor as a result of such
Persons ownership interest in or other relationship with such entity, except to the extent the
terms of such Indebtedness provide that such Person is not liable therefor.
Indemnified Liabilities
has the meaning set forth in
Section 11.3
.
Indemnified Person
has the meaning set forth in
Section 11.3
.
Initial Reserve Report
means the report delivered to Agent dated as of January 1, 2004,
prepared by Ryder Scott Company Petroleum Consultants with respect to the Oil and Gas Properties of
Borrower, its Subsidiaries, the LLC and the Partnerships, a true and correct copy of which has been
delivered to Agent and the Lenders.
Initial Term Loan
means the term loan made by Lenders pursuant to the Existing Credit
Agreement in the principal amount equal to the Initial Term Loan Amount.
Initial Term Loan Amount
means $75,000,000.00.
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Insolvency Proceeding
means any proceeding commenced by or against any Person under any
provision of the Bankruptcy Code or under any other state or federal bankruptcy or insolvency law,
assignments for the benefit of creditors, formal or informal moratoria, compositions, extensions
generally with creditors, or proceedings seeking reorganization, arrangement, or other similar
relief.
Intangible Assets
means, with respect to any Person, that portion of the book value of all
of such Persons assets that would be treated as intangibles under GAAP.
Interest Expense
means, for any period, the aggregate of the interest expense of Borrower
and its Subsidiaries for such period, determined on a consolidated basis in accordance with GAAP.
Interest Period
means, with respect to each LIBOR Rate Loan, a period commencing on the date
of the making of such LIBOR Rate Loan (or the continuation of a LIBOR Rate Loan or the conversion
of a Base Rate Loan to a LIBOR Rate Loan) and ending 1, 3, 6 or 12 months thereafter;
provided
,
however
, that (a) if any Interest Period would end on a day that is not a
Business Day, such Interest Period shall be extended (subject to clauses (c)-(e) below) to the next
succeeding Business Day, (b) interest shall accrue at the applicable rate based upon the LIBOR Rate
from and including the first day of each Interest Period to, but excluding, the day on which any
Interest Period expires, (c) any Interest Period that would end on a day that is not a Business Day
shall be extended to the next succeeding Business Day unless such Business Day falls in another
calendar month, in which case such Interest Period shall end on the next preceding Business Day,
(d) with respect to an Interest Period that begins on the last Business Day of a calendar month (or
on a day for which there is no numerically corresponding day in the calendar month at the end of
such Interest Period), the Interest Period shall end on the last Business Day of the calendar month
that is 1, 3, 6 or 12 months after the date on which the Interest Period began, as applicable, and
(e) Borrower may not elect an Interest Period which will end after the Maturity Date.
Intercompany Notes
has the meaning assigned that term in
Section 7.13
.
Inventory
means all Borrowers and each Subsidiaries now owned or hereafter acquired right,
title, and interest with respect to inventory, including goods held for sale or lease or to be
furnished under a contract of service, goods that are leased by Borrower or any of its Subsidiaries
as lessor, goods that are furnished by Borrower or any of its Subsidiaries under a contract of
service, and raw materials, work in process, or materials used or consumed in Borrowers or any
Subsidiaries business.
Investment
means, with respect to any Person, any investment by such Person in any other
Person (including Affiliates) in the form of loans, guarantees, advances, or capital contributions
(excluding (a) commission, travel, and similar advances to officers and employees of such Person
made in the ordinary course of business, and (b) bona fide Accounts arising in the ordinary course
of business consistent with past practices), purchases or other acquisitions for consideration of
Indebtedness, Stock, or all or substantially all of the assets of such other Person (or of any
division or business line of such other Person), and any other items that are or would be
classified as investments on a balance sheet prepared in accordance with GAAP.
IRC
means the Internal Revenue Code of 1986, as in effect from time to time.
Issuing Lender
means Foothill or any other Lender that, at the request of Borrower and with
the consent of Agent agrees, in such Lenders sole discretion, to become an Issuing Lender for the
purpose of issuing L/Cs or L/C Undertakings pursuant to
Section 2.12
.
L/C
has the meaning set forth in
Section 2.12(a)
.
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L/C Disbursement
means a payment made by the issuing Lender pursuant to a Letter of Credit.
L/C Undertaking
has the meaning set forth in
Section 2.12(a)
.
Lender
and
Lenders
have the respective meanings set forth in the preamble to this
Agreement, and shall include any other Person made a party to this Agreement in accordance with the
provisions of
Section 14.1
.
Lender Group
means, individually and collectively, each of the Lenders (including the
Issuing Lender) and Agent.
Lender Group Expenses
means all (a) costs or expenses (including taxes, and insurance
premiums) required to be paid by Borrower or any of its Subsidiaries under any of the Loan
Documents that are paid, advanced, or incurred by the Lender Group, (b) fees or charges paid or
incurred by Agent in connection with the Lender Groups transactions with Borrower or any of its
Subsidiaries, including, fees or charges for photocopying, notarization, couriers and messengers,
telecommunication, public record searches (including tax lien, litigation, and UCC searches and
including searches with the patent and trademark office, the copyright office, or the department of
motor vehicles), filing, recording, publication, appraisal (including periodic collateral
appraisals or business valuations to the extent of the fees and charges (and up to the amount of
any limitation) contained in this Agreement), real estate surveys, real estate title policies and
endorsements, and environmental audits, (c) costs and expenses incurred by Agent in the
disbursement of funds to or for the account of Borrower or other members of the Lender Group (by
wire transfer or otherwise), (d) charges paid or incurred by Agent resulting from the dishonor of
checks, (e) reasonable costs and expenses paid or incurred by the Lender Group to correct any
default or enforce any provision of the Loan Documents, or in gaining possession of, maintaining,
handling, preserving, storing, shipping, selling, preparing for sale, or advertising to sell the
Collateral, or any portion thereof, irrespective of whether a sale is consummated, (f) audit fees
and expenses of Agent related to audit examinations of the Books to the extent of the fees and
charges (and up to the amount of any limitation) contained in this Agreement, (g) reasonable costs
and expenses of third party claims or any other suit paid or incurred by the Lender Group in
enforcing or defending the Loan Documents or in connection with the transactions contemplated by
the Loan Documents or the Lender Groups relationship with Borrower or any of its Subsidiaries, (h)
Agents and each Lenders reasonable costs and expenses (including attorneys fees) incurred in
advising, structuring, drafting, reviewing, administering, syndicating, or amending the Loan
Documents, and (i) Agents and each Lenders reasonable costs and expenses (including attorneys,
accountants, consultants, and other advisors fees and expenses) incurred in terminating, enforcing
(including attorneys, accountants, consultants, and other advisors fees and expenses incurred in
connection with a workout, a restructuring, or an Insolvency Proceeding concerning Borrower or
its Subsidiaries or in exercising rights or remedies under the Loan Documents), or defending the
Loan Documents, irrespective of whether suit is brought, or in taking any Remedial Action
concerning the Collateral.
Lender-Related Person
means, with respect to any Lender, such Lender together with such
Lenders Affiliates, and the officers, directors, employees, attorneys, and agents of such Lender.
Letter of Credit
means an L/C or an L/C Undertaking, as the context requires.
Letter of Credit Usage
means, as of any date of determination, the aggregate undrawn amount
of all outstanding Letters of Credit plus 100% of the amount of outstanding time drafts accepted by
an Underlying Issuer as a result of drawings under Underlying Letters of Credit.
LIBOR Deadline
has the meaning set forth in
Section 2.
13(b)(i)
.
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LIBOR Notice
means a written notice in the form of
Exhibit L-1
.
LIBOR Option
has the meaning set forth in
Section 2.13(a)
.
LIBOR Rate
means, for each Interest Period for each LIBOR Rate Loan, the rate per annum
determined by Agent (rounded upwards, if necessary, to the next 1/100%) by
dividing
(a) the Base
LIBOR Rate for such Interest Period, by (b) 100%
minus
the Reserve Percentage. The LIBOR Rate
shall be adjusted on and as of the effective day of any change in the Reserve Percentage.
LIBOR Rate Loan
means each portion of an Advance or the Term Loan that bears interest at a
rate determined by reference to the LIBOR Rate.
Lien
means any interest in an asset securing an obligation owed to, or a claim by, any
Person other than the owner of the asset, irrespective of whether (a) such interest is based on the
common law, statute, or contract, (b) such interest is recorded or perfected, and (c) such interest
is contingent upon the occurrence of some future event or events or the existence of some future
circumstance or circumstances. Without limiting the generality of the foregoing, the term Lien
includes the lien or security interest arising from a mortgage, deed of trust, encumbrance, pledge,
hypothecation, assignment, deposit arrangement, security agreement, conditional sale or trust
receipt, or from a lease, consignment, or bailment for security purposes and also includes
reservations, exceptions, encroachments, easements, rights-of-way, covenants, conditions,
restrictions, leases, and other title exceptions and encumbrances affecting Real Property.
LLC
means A&W LLC, a West Virginia limited liability company.
LLC Pledge Agreement
means the Second Amended and Restated Pledge and Security Agreement
dated as of even date herewith, executed by A&W in favor of the Agent or otherwise delivered
pursuant to the Loan Documents, in form, scope, and substance acceptable to the Agent.
Loan Account
has the meaning set forth in
Section 2.10
.
Loan Documents
means this Agreement, the Bank Product Agreements, the Cash Management
Agreements, the Control Agreements, the Disbursement Letter, the Fee Letter, the Intercompany
Notes, the Letters of Credit, the Mortgages, the Officers Certificate, the Security Documents, the
Subordination Agreements, any note or notes executed by Borrower in connection with this Agreement
and payable to a member of the Lender Group, and all the other agreements, documents and
instruments entered into from time to time, evidencing or securing the Obligations.
Material Adverse Change
means (a) a material adverse change in the business, prospects,
operations, results of operations, assets, liabilities or condition (financial or otherwise) of
Borrower and its Subsidiaries taken as a whole, (b) a material impairment of Borrowers or any of
its Subsidiaries ability to perform its obligations under the Loan Documents to which it is a
party or of the Lender Groups ability to enforce the Obligations or realize upon the Collateral,
or (c) a material impairment of the enforceability or priority of the Agents Liens with respect to
the Collateral as a result of an action or failure to act on the part of Borrower or any of its
Subsidiaries.
Material Contracts
means any supply, purchase, service, employment, tax, indemnity, gas
marketing, farm-in agreement, farm-out agreement, gas imbalance, operating, unitization,
communitization, partnership, joint venture, or other agreement of Borrower, its Subsidiaries, the
LLC or any Partnership or by which Borrower, its Subsidiaries, the LLC or any Partnership or any of
their respective properties are otherwise bound, if such agreement (i) requires the expenditure of
over
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$5,000,000.00 by the Borrower or any of its Subsidiaries during any calendar year, or (ii)
involves the sale of more than $5,000,000.00 in Hydrocarbons by the Borrower, any of its
Subsidiaries, the LLC, or any Partnership, or (iii) involves a liability of Borrower, any of its
Subsidiaries, the LLC, or any Partnership, in excess of $5,000,000.00, or (iv) is otherwise
determined by Agent, in its reasonable judgment, to be material to the business, operations, or
properties of Borrower or any of its Subsidiaries, as the same shall be amended, modified and
supplemented and in effect from time to time.
Maturity Date
has the meaning set forth in
Section 3.4
.
Maximum Loan Amount
means $200,000,000.00.
Maximum Revolver Amount
means $100,000,000.00, as such amount may be reduced from time to
time in accordance with
Section 6.23
.
Mortgage
means a Mortgage, Deed of Trust, Assignment, Security Agreement, Financing
Statement and Fixture Filing, dated as of the Closing Date or thereafter or otherwise delivered
pursuant to the Loan Documents, in form, scope and substance acceptable to the Agent, executed and
delivered by a Pledging Subsidiary or any other Subsidiary of Borrower, as amended, supplemented,
restated or otherwise modified from time to time in accordance with the terms of this Agreement and
the other Loan Documents. The term
Mortgage
shall include each Mortgage Supplement after
execution and delivery of such Mortgage Supplement. The term
Mortgages
shall include each and
every Mortgage executed and delivered by any of the Pledging Subsidiaries hereunder.
Mortgage Supplement
means a supplement to any Mortgage, in form and substance satisfactory
to the Agent, pursuant to which any Pledging Subsidiary will grant a lien on additional Property
subject to the terms of such Mortgage, as amended, supplemented, restated or otherwise modified
from time to time in accordance with the terms of this Agreement and the other Loan Documents.
Mortgaged Properties
means all of the Oil and Gas Properties and other collateral purported
to be subject to the Lien of the Mortgages.
Net Operating Income
means the projected revenue attributable to (a) the general partner
interests of the Pledging Subsidiaries in the Partnerships interests in the Eligible Proved
Developed Producing Reserves of the Partnerships, (b) the membership interests of the Pledging
Subsidiaries in the LLCs interest in the Eligible Proved Developed Producing Reserves of the LLC,
and (c) the interests of the Pledging Subsidiaries in the Eligible Proved Developed Producing
Reserves of the Pledging Subsidiaries, which the Partnerships, the LLC and the Pledging
Subsidiaries can reasonably expect to receive from the sale of Hydrocarbons therefrom, as shown on
the most current Reserve Report net of royalties, minus production and severance taxes (including,
without limitation, any windfall profits or similar tax but excluding income taxes), and
production expenses, and minus the amount of all production revenue therefrom from the dates of
such reports to the determination date.
Non-Pledged Properties
means Property of Borrower, its Subsidiaries, the Partnerships, and
the LLC which does not constitute Borrowing Base Properties, the Gathering Systems, or assets or
interests subject to the Liens of the Partnership Pledge Agreements, the LLC Pledge Agreement, or
the Mortgages.
Non-Prepayment Premium Event
means that a material dispute exists between Agent and Borrower
as to the Availability due to (i) a redetermination of the Borrowing Base by the Agent or (ii) the
establishment of a reserve by Agent under
Section 2.1(b)
(other than due to an event
described in
Section
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2.1(b)
,
clauses (i) through (vi)
inclusive, except that a material dispute as
to the amount of a reserve established under
Section 2.1(b)
clauses (i) through (vi)
inclusive shall be resolved by binding arbitration under
Section 17.13
) and (x) at the time
of such dispute there exists no Default, Event of Default or Material Adverse Change and (y) the
Obligations are prepaid within 60 days from the date Borrower notifies Agent in writing of such
dispute.
Non-Recourse Debt
means Indebtedness as to which (a) neither Borrower nor any Subsidiary
(other than an Unrestricted Subsidiary) is directly or indirectly liable pursuant to the terms of
such Indebtedness, and (b) no default with respect to such Indebtedness would permit (upon notice,
lapse of time or otherwise) any holder of any other Indebtedness of Borrower or any Subsidiary to
declare a default on such other Indebtedness or cause the payment thereof to be accelerated or
payable prior to its stated maturity.
NYMEX
means the New York Mercantile Exchange or its successor.
NYMEX Price
means, as of the date of the determination thereof, the average of the 24
succeeding monthly futures contract prices, commencing with the month during which the
determination is to be made, for the category of Proved Developed Producing Reserves included in
the most recent Reserve Report provided by Borrower to Agent pursuant to
Section 6.2
as
quoted on the NYMEX, or, if the NYMEX no longer provides futures contract price quotes for 24 month
periods, the longest period of quotes of less than 24 months shall be used, and, if the NYMEX no
longer provides such futures contract quotes or has ceased to operate, the Agent shall designate
another nationally recognized commodities exchange to replace the NYMEX.
Obligations
means (a) all loans (including the Term Loan), Advances, debts, principal,
interest (including any interest that, but for the commencement of an Insolvency Proceeding, would
have accrued), contingent reimbursement obligations with respect to outstanding Letters of Credit,
premiums, liabilities (including all amounts charged to Borrowers Loan Account pursuant hereto),
obligations, fees (including the fees provided for in the Fee Letter), charges, costs, Lender Group
Expenses (including any fees or expenses that, but for the commencement of an Insolvency
Proceeding, would have accrued), lease payments, guaranties, covenants, and duties of any kind and
description owing by Borrower or any of the Subsidiaries to the Lender Group pursuant to or
evidenced by the Loan Documents (including, without limitation, all claims for indemnity under the
Loan Documents including claims under
Section 11.3
of this Agreement) and irrespective of
whether for the payment of money, whether direct or indirect, absolute or contingent, due or to
become due, now existing or hereafter arising, and including all interest not paid when due and all
Lender Group Expenses that Borrower or any of its Subsidiaries are required to pay or reimburse by
the Loan Documents, by law, or otherwise, and (b) all Bank Product Obligations. Any reference in
this Agreement or in the Loan Documents to the Obligations shall include all amendments, changes,
extensions, modifications, renewals, alterations, replacements, substitutions, and supplements,
thereto and thereof, as applicable, both prior and subsequent to any Insolvency Proceeding.
Officers Certificate
means the representations and warranties of officers form submitted by
Agent to Borrower, together with Borrowers completed responses to the inquiries set forth therein,
the form and substance of such responses to be satisfactory to Agent.
Oil and Gas Properties
means the Hydrocarbon Interests; the Properties now or hereafter
pooled or unitized with Hydrocarbon Interests; all presently existing or future unitization,
pooling agreements and declarations of pooled units and the units created thereby (including
without limitation all units created under orders, regulations and rules of any Governmental
Authority having jurisdiction) which may affect all or any portion of the Hydrocarbon Interests;
all operating agreements, joint venture agreements, contracts and other agreements which relate to
any of the Hydrocarbon Interests or the
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production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to
such Hydrocarbon Interests; all Hydrocarbons in and under and which may be produced and saved or
attributable to the Hydrocarbon Interests, the lands covered thereby and all oil in tanks and all
rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the
Hydrocarbon Interests; all tenements, profits a prendre, hereditaments, appurtenances and
Properties in anywise appertaining, belonging, affixed or incidental to the Hydrocarbon Interests,
Properties, rights, titles, interests and estates described or referred to above, including any and
all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for
use or useful in connection with the operating, working or development of any of such Hydrocarbon
Interests or Property (excluding drilling rigs, automotive equipment or other personal Property
which may be on such premises for the purpose of drilling a well or for other similar temporary
uses) and including any and all oil wells, gas wells, water wells, injection wells or other wells,
buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping
units, field gathering systems, tanks and tank batteries, fixtures, valves, fittings, machinery and
parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables,
wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes
together with all additions, substitutions, replacements, accessions and attachments to any and all
of the foregoing.
Originating Lender
has the meaning set forth in
Section 14.1(e)
.
Overadvance
has the meaning set forth in
Section 2.5
.
Participant
has the meaning set forth in
Section 14.1(e)
.
Partnership Pledge Agreements
means the Second Amended and Restated Partnership Pledge and
Security Agreements dated as of even date herewith or otherwise delivered pursuant to the Loan
Documents, in form, scope, and substance acceptable to the Agent, executed by the Pledging
Subsidiaries in favor of the Agent.
Partnerships
means those partnerships and joint ventures listed on
Schedule P-1
.
Permitted Discretion
means a determination made in good faith and in the exercise of
reasonable business judgment.
Permitted Dispositions
means (a) sales or other dispositions by Borrower or its Subsidiaries
of Equipment that is substantially worn, damaged, or obsolete in the ordinary course of business,
(b) sales by Borrower or its Subsidiaries of Inventory and Hydrocarbons to buyers in the ordinary
course of business, (c) the use or transfer of money or Cash Equivalents by Borrower or its
Subsidiaries in a manner that is not prohibited by the terms of this Agreement or the other Loan
Documents, (d) the licensing by Borrower or its Subsidiaries, on a non-exclusive basis, of patents,
trademarks, copyrights, and other intellectual property rights in the ordinary course of business,
(e) sales of Non-Pledged Properties of the Pledging Subsidiaries having an aggregate value not
exceeding $2,000,000.00 in any fiscal year of Borrower provided (i) the Non-Pledged Property
subject to disposition was acquired by a Pledging Subsidiary after the Closing Date and (ii) the
disposition does not expose a Bank Product Provider to increased risk under any Hedging Obligation,
(f) the abandonment, farm-out, lease, or sublease of undeveloped Oil and Gas Properties of Borrower
or any of its Subsidiaries in the ordinary course of business, (g) the trade or exchange by
Borrower or any of its Subsidiaries of any of its Oil and Gas Properties (other than the Borrowing
Base Properties, Non-Pledged Properties, and the Gathering Systems) for Oil and Gas Properties
owned by another Person which the Board of Directors of Borrower determines in good faith to be of
approximately equivalent value; and (h) sales of Non-Pledged Properties by Borrower or a Subsidiary
(other than a Pledging Subsidiary, the Partnerships or the LLC) provided (i)
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prior written notice of such sale or other disposition is delivered to Agent setting forth the
property to be sold or otherwise disposed of, its value, and such other information as Agent may
reasonably request, and (ii) if the aggregate value of such property or sale exceeds $10,000,000.00
in one or more transactions in any fiscal year, Agent shall have consented in writing in advance,
such consent by Agent not to be unreasonably withheld.
Permitted Investments
means (a) investments in Cash Equivalents, (b) investments in
negotiable instruments for collection, (c) advances made in connection with purchases of goods or
services in the ordinary course of business, (d) investments received in connection with the
bankruptcy or reorganization of suppliers and customers and in settlement of delinquent obligations
of and other disputes with, customers and suppliers arising in the ordinary course of business, (e)
investments made as a result of non-cash consideration of an asset sale that was made pursuant to a
Permitted Disposition, (f) acceptance by Borrower of notes payable from employees, officers, or
directors of Borrower or any of its Subsidiaries as payment for the purchase of common or Class A
stock by such employees; provided that (i) the aggregate principal amount owing to Borrower under
such notes shall not exceed $1,600,000.00 at any one time outstanding, and (ii) any such note shall
be secured by a pledge of the shares of stock purchased therewith, and (g) loans by Borrower to
officers, directors and employees in connection with Borrowers annual drilling programs consistent
with past practices up to but not exceeding $2,000,000.00 in the aggregate at any one time
outstanding.
Permitted Liens
means (a) Liens held by Agent, (b) Liens for unpaid taxes that either (i)
are not yet delinquent, or (ii) do not constitute an Event of Default hereunder and are the subject
of Permitted Protests, (c) the interests of lessors under operating leases, (d) Liens arising by
operation of law in favor of warehousemen, landlords, carriers, mechanics, materialmen, laborers,
or suppliers, incurred in the ordinary course of business of Borrower or any of its Subsidiaries
and not in connection with the borrowing of money, and which Liens either (i) are for sums not yet
delinquent, or (ii) are the subject of Permitted Protests, (e) Liens arising from deposits made in
connection with obtaining workers compensation or other unemployment insurance, (f) Liens or
deposits to secure performance of bids, tenders, or leases incurred in the ordinary course of
business of Borrower or any of its Subsidiaries and not in connection with the borrowing of money,
(g) Liens granted as security for surety or appeal bonds in connection with obtaining such bonds in
the ordinary course of business of Borrower or any of its Subsidiaries, (h) with respect to any
Property (other than the Borrowing Base Properties) from which Hydrocarbons may be severed or
extracted in commercial quantities, Liens for farmout, farmin, joint operating, and area of mutual
interest agreements and/or similar arrangements that Borrower determines in good faith to be
necessary for the economic development of such Property (other than the Borrowing Base Properties)
and are customary and usual for the area in which such Property (other than the Borrowing Base
Properties) is located, (i) with respect to any Borrowing Base Properties from which Hydrocarbons
may be severed or extracted in commercial quantities, Liens for farm-out, farm-in, operating, joint
operating, and area of mutual interest agreements and/or similar arrangements that the Borrower
determines in good faith to be necessary for the economic development of such Borrowing Base
Properties and are customary and usual for the area in which such Borrowing Base Properties are
located;
provided
,
however
, that such Liens held by Borrower or any of its
Subsidiaries or Affiliates shall be expressly made subordinate to the Liens created by the Security
Documents pursuant to terms of a Subordination Agreement, (j) Liens associated with Production
Payments now existing or hereafter created on oil, gas or mineral leases or interests (other than
Borrowing Base Properties) now owned or hereafter acquired by the Borrower or any Subsidiary;
provided (i) such Liens are limited to the interest in the Properties subject to the Production
Payment and do not apply to any other Property or assets of Borrower or any Subsidiary and (ii)
such Liens only secure the Indebtedness incurred pursuant to the Production Payments, and (k)
royalties, overriding royalties, revenue interests, net revenue interest and other similar burdens
now existing or hereafter acquired on oil, gas or mineral leases or interests now
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owned or hereafter acquired by Borrower or any Subsidiary and, with respect to any Borrowing
Base Properties, are reflected in the most recent Reserve Report.
Permitted Protest
means the right of Borrower or any of its Subsidiaries, as applicable, to
protest any Lien (other than any such Lien that secures the Obligations), taxes (other than payroll
taxes or taxes that are the subject of a United States federal tax lien), or rental payment,
provided that (a) a reserve with respect to such obligation is established on the Books in such
amount as is required under GAAP, (b) any such protest is instituted promptly and prosecuted
diligently by Borrower or any of its Subsidiaries, as applicable, in good faith, and (c) Agent is
satisfied that, while any such protest is pending, there will be no impairment of the
enforceability, validity, or priority of any of the Agents Liens.
Person
means natural persons, corporations, limited liability companies, limited
partnerships, general partnerships, limited liability partnerships, joint ventures, trusts, land
trusts, business trusts, or other organizations, irrespective of whether they are legal entities,
and governments and agencies and political subdivisions thereof.
Personal Property Collateral
means all Collateral other than Hydrocarbon Interests and Real
Property.
Pledging Subsidiaries
means Eastern American, A&W and any other Subsidiary of Borrower that
executes a Mortgage, LLC Pledge Agreement and/or a Partnership Pledge Agreement.
Projections
means Borrowers forecasted (a) balance sheets, (b) profit and loss statements,
and (c) cash flow statements, all prepared on a consistent basis with Borrowers historical
financial statements, together with appropriate supporting details and a statement of underlying
assumptions.
Production Payments
means a production payment (whether volumetric or dollar denominated) or
similar royalty, overriding royalty, net profits interest or other similar interest in Oil and Gas
Properties, or the right to receive all or a portion of the production or the proceeds from the
sale of production attributable to such Oil and Gas Properties where the holder of such interest
has recourse solely to such interest and the grantor or transferor thereof has an express
contractual obligation to produce and sell Hydrocarbons from such Oil and Gas Properties, or to
cause such Oil and Gas Properties to be so operated and maintained, in each case in a reasonably
prudent manner.
Property
means any interest in any kind of Property or asset, whether real, personal or
mixed, or tangible or intangible.
Pro Rata Share
means, as of any date of determination:
(a) with respect to a Lenders obligation to make Advances and receive payments of
principal, interest, fees, costs, and expenses with respect thereto, (i) prior to the
Revolver Commitments being terminated or reduced to zero, the percentage obtained by
dividing (y) such Lenders Revolver Commitment, by (z) the aggregate Revolver Commitments of
all Lenders, and (ii) from and after the time that the Revolver Commitments have been
terminated or reduced to zero, the percentage obtained by dividing (y) the aggregate
outstanding principal amount of such Lenders Advances by (z) the aggregate outstanding
principal amount of all Advances,
(b) with respect to a Lenders obligation to participate in Letters of Credit, to
reimburse the Issuing Lender, and to receive payments of fees with respect thereto, (i)
prior to the Revolver Commitments being terminated or reduced to zero, the percentage
obtained by dividing (y) such Lenders Revolver Commitment, by (z) the aggregate Revolver
Commitments of all
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Lenders, and (ii) from and after the time that the Revolver Commitments have been
terminated or reduced to zero, the percentage obtained by dividing (y) the aggregate
outstanding principal amount of such Lenders Advances by (z) the aggregate outstanding
principal amount of all Advances,
(c) with respect to a Lenders obligation to make the Term Loan and receive payments of
interest, fees, and principal with respect thereto, (i) prior to the making of the Term
Loan, the percentage obtained by dividing (y) such Lenders Term Loan Commitment, by (z) the
aggregate amount of all Lenders Term Loan Commitments, and (ii) from and after the making
of the Term Loan, the percentage obtained by dividing (y) the principal amount of such
Lenders portion of the Term Loan by (z) the principal amount of the Term Loan, and
(d) with respect to all other matters as to a particular Lender (including the
indemnification obligations arising under
Section 16.7
), the percentage obtained by
dividing (i) such Lenders Revolver Commitment plus the outstanding principal amount of such
Lenders portion of the Term Loan, by (ii) the aggregate amount of Total Commitments of all
Lenders plus the outstanding principal amount of the Term Loan;
provided
,
however
, that, in the event the Revolver Commitments have been terminated or reduced
to zero, the Pro Rata Share under this clause shall be the percentage obtained by dividing
(A) the outstanding principal amount of such Lenders Advances plus such Lenders ratable
portion of the Risk Participation Liability with respect to outstanding Letters of Credit
plus the outstanding principal amount of such Lenders portion of the Term Loan, by (B) the
outstanding principal amount of all Advances plus the aggregate amount of the Risk
Participation Liability with respect to the outstanding Letters of Credit plus the principal
amount of the Term Loan.
Proved Developed Non-Producing Reserves
means those Oil and Gas Properties of the Borrower,
the Pledging Subsidiaries, the LLC and the Partnerships designated as proved developed
non-producing (in accordance with the Definitions for Oil and Gas Reserves approved by the Board
of Directors of the Society for Petroleum Engineers, Inc. from time to time) in the Reserve Report.
Proved Developed Producing Reserves
means those Oil and Gas Properties designated as proved
developed producing (in accordance with the Definitions for Oil and Gas Reserves approved by the
Board of Directors of the Society for Petroleum Engineers, Inc.), from time to time in the Reserve
Report.
Proved Developed Producing Reserves of the Partnerships and the LLC
means those Oil and Gas
Properties of the Partnerships and the LLC designated as proved developed producing (in
accordance with the Definitions for Oil and Gas Reserves approved by the Board of Directors of the
Society for Petroleum Engineers, Inc. from time to time) in the Reserve Report and used in
establishing the Borrowing Base.
Proved Developed Producing Reserves of the Pledging Subsidiaries
means those Oil and Gas
Properties of the Pledging Subsidiaries designated as proved developed producing (in accordance
with the Definitions for Oil and Gas Reserves approved by the Board of Directors of the Society for
Petroleum Engineers, Inc., from time to time) in the Reserve Report and used in establishing the
Borrowing Base.
Proved Undeveloped Reserves
means those Oil and Gas Properties of the Pledging Subsidiaries,
the LLC and the Partnerships designated as proved undeveloped (in accordance with the Definitions
for Oil and Gas Reserves approved by the Board of Directors of the Society for Petroleum Engineers,
Inc. from time to time) in the Reserve Report.
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PV-10 Value
means, as of the date of determination, the sum of the present values of the Net
Operating Income expected to be received in each of the months following the date of determination,
determined as follows:
(a) the Net Operating Income shall be determined on the lesser amount of (i) a ceiling
value of MmBTU $6.50 and Bbl $45.00 of Proved Developed Producing Reserves as of such
date of determination, without adjustment to reflect the Basis Differential with respect to
Hydrocarbons produced from the Eligible Proved Developed Producing Reserves of the Pledging
Subsidiaries and the Eligible Proved Developed Producing Reserves of the Partnerships and
the LLC, as determined by the Approved Engineer and approved by Agent, or (ii) (x) on the
basis of the contract price to the extent contracts exist or (y) in the event that contracts
do not exist, on the basis of the applicable NYMEX Price for the category of Proved
Developed Producing Reserves as of such date of determination, adjusting such price to
reflect the appropriate Basis Differential with respect to Hydrocarbons produced from the
Eligible Proved Developed Producing Reserves of the Pledging Subsidiaries and the Eligible
Proved Developed Producing Reserves of the Partnerships and the LLC, as determined by the
Approved Engineer and approved by Agent; and
(b) the present value of each such Net Operating Income amount shall be determined by
discounting such Monthly Net Operating Income from the month in which it is expected to be
received, on a monthly basis, to such date of determination at a rate of 10% per annum.
Real Property
means any estates or interests in real property now owned or hereafter
acquired by Borrower or any of its Subsidiaries and the improvements thereto.
Record
means information that is inscribed on a tangible medium or which is stored in an
electronic or other medium and is retrievable in perceivable form.
Release
means a release, as such term is defined in CERCLA.
Remedial Action
means any action under Environmental Laws required to (a) clean up, remove,
remediate, contain, treat, monitor, assess, evaluate, dispose of, abate, or in any other way
address pollutants (including Hazardous Materials) in the indoor or outdoor environment, (b)
prevent the Release or threat of a Release or minimize the further Release of pollutants, or (c)
investigate and determine if a remedial response is needed and to design such a response and any
post-remedial investigation, monitoring, operation, and maintenance and care.
Replacement Lender
has the meaning set forth in
Section 15.2(a)
.
Report
has the meaning set forth in
Section 16.17
.
Required Lenders
means, at any time, (a) Agent, and (b) Lenders whose aggregate Pro Rata
Shares (calculated under clause (d) of the definition of Pro Rata Shares) equal or exceed 66.67%.
Reserve Percentage
means, on any day, for any Lender, the maximum percentage prescribed by
the Board of Governors of the Federal Reserve System (or any successor Governmental Authority) for
determining the reserve requirements (including any basic, supplemental, marginal, or emergency
reserves) that are in effect on such date with respect to eurocurrency funding (currently referred
to as eurocurrency liabilities) of that Lender, but so long as such Lender is not required or
directed under applicable regulations to maintain such reserves, the Reserve Percentage shall be
zero.
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Reserve Report
means the Initial Reserve Report and any other report delivered pursuant to
Section 6.2
, in form and substance satisfactory to the Agent, prepared at the sole cost and
expense of the Borrower by the Approved Engineer, which shall evaluate the oil and gas reserves
attributable to the Hydrocarbon Interests owned directly by Borrower, its Subsidiaries, the LLC and
the Partnerships, as of the immediately preceding January 1 or July 1. Each Reserve Report shall
set forth volumes, projections of the future rate of production, Hydrocarbon prices, escalation
rates, discount rate assumptions, and net proceeds of production, present value of the net proceeds
of production, estimated costs of Remedial Action, operating expenses and capital expenditures, in
each case based upon updated economic assumptions reasonably acceptable to the Agent.
Revolver Commitment
means, with respect to each Lender, its Revolver Commitment, and, with
respect to all Lenders, their Revolver Commitments, in each case as such Dollar amounts are set
forth beside such Lenders name under the applicable heading on
Schedule C-1
or on the
signature page of the Assignment and Acceptance pursuant to which such Lender became a Lender
hereunder, as such amounts may be reduced or increased from time to time pursuant to assignments
made in accordance with the provisions of
Section 14.1
.
Revolver Usage
means, as of any date of determination, the sum of (a) the then extant amount
of outstanding Advances,
plus
(b) the then extant amount of the Letter of Credit Usage.
Risk Participation Liability
means, as to each Letter of Credit, all reimbursement
obligations of Borrower to the Issuing Lender with respect to an L/C Undertaking, consisting of (a)
the amount available to be drawn or which may become available to be drawn, (b) all amounts that
have been paid by the Issuing Lender to the Underlying Issuer to the extent not reimbursed by
Borrower, whether by the making of an Advance or otherwise, and (c) all accrued and unpaid
interest, fees, and expenses payable with respect thereto.
SEC
means the United States Securities and Exchange Commission and any successor thereto.
Securities Account
means a securities account as that term is defined in the Code.
Security Documents
means the Mortgages, the Partnership Pledge Agreements, the Borrowers
Security Agreement, the LLC Pledge Agreement and all other security documents hereafter delivered
to Agent granting a Lien on any asset of any Person to secure the Obligations.
Solvent
means, with respect to any Person on a particular date, that such Person is not
insolvent (as such term is defined in the Uniform Fraudulent Transfer Act).
Stock
means all shares, options, warrants, interests, participations, or other equivalents
(regardless of how designated) of or in a Person, whether voting or nonvoting, including common
stock, preferred stock, or any other equity security (as such term is defined in Rule 3a11-1 of
the General Rules and Regulations promulgated by the SEC under the Exchange Act).
Subsidiary
of a Person means a corporation, limited liability company, or other entity
(other than Partnerships) in which that Person directly or indirectly owns or controls the shares
of Stock having ordinary voting power to elect a majority of the board of directors (or appoint
other comparable managers) of such corporation, limited liability company, or other entity.
Subordination Agreement
means an agreement executed by a Person holding or having the right
to a Lien on any Collateral subordinating such Lien to the Agents Liens, all in form, scope, and
substance satisfactory to Agent.
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Swing Lender
means Foothill or any other Lender that, at the request of Borrower and with
the consent of Agent agrees, in such Lenders sole discretion, to become the Swing Lender under
Section 2.3(d)
.
Swing Loan
has the meaning set forth in
Section 2.
3(d)(i)
.
Taxes
means any and all present or future taxes, levies, imposts, duties, deductions,
charges or withholdings imposed by any Governmental Authority.
Term Loan
means, collectively, the Initial Term Loan and the Additional Term Loan.
Term Loan Amount
means, collectively, the Initial Term Loan Amount and the Additional Term
Loan Amount.
Term Loan Commitment
means, with respect to each Lender, its Term Loan Commitment, and, with
respect to all Lenders, their Term Loan Commitments, in each case as such Dollar amounts are set
forth beside such Lenders name under the applicable heading on
Schedule C-1
or in the
Assignment and Acceptance pursuant to which such Lender became a Lender hereunder, as such amounts
may be reduced or increased from time to time pursuant to assignments made in accordance with the
provisions of
Section 14.1
.
Total Commitment
means, with respect to each Lender, its Total Commitment, and, with respect
to all Lenders, their Total Commitments, in each case as such Dollar amounts are set forth beside
such Lenders name under the applicable heading on
Schedule C-1
attached hereto or on the
signature page of the Assignment and Acceptance pursuant to which such Lender became a Lender
hereunder, as such amounts may be reduced or increased from time to time pursuant to assignment
made in accordance with the provisions of
Section 14.1
.
Total Proved Developed Producing Reserves
means the Proved Developed Producing Reserves of
the Partnerships and the LLC and the Proved Developed Producing Reserves of the Pledging
Subsidiaries.
Total Usage
means, as of any date of determination, the sum of (a) the then extant amount of
outstanding Advances, plus (b) the then extant amount of the Letter of Credit Usage, plus (c) the
then extant amount of the Term Loan.
Total Value
means an amount equal to the sum of (a) with respect to the LLC and each
Partnership, the PV-10 Value of the Eligible Proved Developed Producing Reserves of the
Partnerships and the LLC multiplied (i) in the case of the Partnerships, by the general partnership
interest of the applicable Pledging Subsidiary in such Partnership, and (ii) in the case of the LLC
by the membership interest of A&W in the LLC plus (b) with respect to the Pledging Subsidiaries,
the PV-10 Value of the Eligible Proved Developed Producing Reserves of the Pledging Subsidiaries.
Underlying Issuer
means a third Person which is the beneficiary of an L/C Undertaking and
which has issued a letter of credit at the request of Lender for the benefit of Borrower.
Underlying Letter of Credit
means a letter of credit that has been issued by an Underlying
Issuer.
United States
means the United States of America.
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Unrestricted Subsidiary
means ECA Trans LLC, a Subsidiary of Borrower; provided, however,
that if the Borrower receives the prior written consent of Agent (not to be unreasonably withheld),
the Board of Directors of the Borrower may designate any Subsidiary of the Borrower (including any
newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through permitted
merger, consolidation or Investment therein) to be an Unrestricted Subsidiary, but only if (a) such
Subsidiary does not own any capital stock of, or own or hold any Lien on any property of, any other
Subsidiary of the Borrower which is not a Subsidiary of the Subsidiary to be so designated or
otherwise an Unrestricted Subsidiary; (b) all the Indebtedness of such Subsidiary shall, at the
date of designation, and will at all times thereafter; consist of Non-Recourse Debt; (c) such
Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not own
or operate, directly or indirectly, any material portion of the business of the Borrower and its
Subsidiaries; (d) such Subsidiary does not, directly or indirectly, own any Indebtedness of or
equity interest in, and has no Investments in, the Borrower or any Subsidiary (other than an
Unrestricted Subsidiary); (e) such Subsidiary is a Person with respect to which neither the
Borrower nor any of its Subsidiaries (other than an Unrestricted Subsidiary) has any direct or
indirect obligation; (1) to subscribe for additional equity interests or (2) to maintain or
preserve such Persons financial condition or to cause such Person to achieve any specified levels
of operating results; and (f) on the date such Subsidiary is designated an Unrestricted Subsidiary,
such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the
Borrower or any Subsidiary (other than an Unrestricted Subsidiary) with terms substantially less
favorable to the Borrower than those that might have been obtained from Persons who are not
Affiliates of the Borrower. Any such designation by the Board of Directors of the Borrower shall
be evidenced to the Agent by delivering to the Agent a resolution of the Board of Directors of the
Borrower giving effect to such designation and an Officers Certificate certifying that such
designation complied with the foregoing conditions. If, at any time, any Unrestricted Subsidiary
would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter
cease to be an Unrestricted Subsidiary for purposes of this Agreement and the other Loan Documents
and any Indebtedness of such Subsidiary shall be deemed to be incurred as of such date. The Board
of Directors of the Borrower may designate any Unrestricted Subsidiary to be a Subsidiary other
than an Unrestricted Subsidiary; provided, that immediately after giving effect to such
designation, no Default or Event of Default shall have occurred and be continuing or would occur as
a consequence thereof and no additional Indebtedness (excluding Indebtedness permitted under
Section 7.1
) would be incurred by the Borrower on a pro forma basis taking into account
such designation; such designation shall be evidenced by delivering to the Agent a resolution of
the Board of Directors of the Borrower giving effect to such designation and an Officers
Certificate certifying that such designation complied with the foregoing conditions.
Voidable Transfer
has the meaning set forth in
Section 17.7
.
Wells
means any existing oil or gas well which is producing Hydrocarbons from the Mortgaged
Properties.
Wells Fargo
means Wells Fargo Bank, National Association, a national banking association.
1.2.
Accounting Terms
. All accounting terms not specifically defined herein shall be
construed in accordance with GAAP. When used herein, the term financial statements shall include
the notes and schedules thereto. Whenever the term Borrower is used in respect of a financial
covenant or a related definition, it shall be understood to mean Borrower and its Subsidiaries on a
consolidated basis unless the context clearly requires otherwise.
1.3.
Code
. Any terms used in this Agreement that are defined in the Code shall be
construed and defined as set forth in the Code unless otherwise defined herein;
provided
,
however
, that to the extent
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that the Code is used to define any term herein and such term is defined differently in
different Articles of the Code, the definition of such term contained in Article 9 shall govern.
1.4.
Construction
. Unless the context of this Agreement or any other Loan Document
clearly requires otherwise, references to the plural include the singular, references to the
singular include the plural, the terms includes and including are not limiting, and the term
or has, except where otherwise indicated, the inclusive meaning represented by the phrase
and/or. The words hereof, herein, hereby, hereunder, and similar terms in this Agreement
or any other Loan Document refer to this Agreement or such other Loan Document, as the case may be,
as a whole and not to any particular provision of this Agreement or such other Loan Document, as
the case may be. Section, subsection, clause, schedule, and exhibit references herein are to this
Agreement unless otherwise specified. Any reference in this Agreement or in the other Loan
Documents to any agreement, instrument, or document shall include all alterations, amendments,
changes, extensions, modifications, renewals, replacements, substitutions, joinders, and
supplements, thereto and thereof, as applicable (subject to any restrictions on such alterations,
amendments, changes, extensions, modifications, renewals, replacements, substitutions, joinders,
and supplements set forth herein). Any reference herein to the satisfaction or repayment in full
of the Obligations shall mean the repayment in full in cash (or cash collateralization in
accordance with the terms hereof) of all Obligations other than contingent indemnification
Obligations and other than any Bank Product Obligations that, at such time, are allowed by the
applicable Bank Product Provider to remain outstanding and are not required to be repaid or cash
collateralized pursuant to the provisions of this Agreement. Any reference herein to any Person
shall be construed to include such Persons successors and assigns. Any requirement of a writing
contained herein or in the other Loan Documents shall be satisfied by the transmission of a Record
and any Record transmitted shall constitute a representation and warranty as to the accuracy and
completeness of the information contained therein.
1.5.
Schedules and Exhibits
. All of the schedules and exhibits attached to this
Agreement shall be deemed incorporated herein by reference.
2. LOAN AND TERMS OF PAYMENT
2.1.
Revolver Advances
.
(a) Subject to the terms and conditions of this Agreement, and during the term of this
Agreement, each Lender with a Revolver Commitment agrees (severally, not jointly or jointly
and severally) to make advances (
Advances
) to Borrower in an amount at any one time
outstanding not to exceed such Lenders Pro Rata Share of an amount equal to the lesser of
(i) the Maximum Revolver Amount less the Letter of Credit Usage, or (ii) the Borrowing Base
then in effect less the Letter of Credit Usage, of which there is currently outstanding
[$
]. For purposes of this Agreement and subject to the provisions of
Section
2.16
of this Agreement, Borrowing Base, as of any date of determination, shall mean
the result of:
(w) an amount equal to 65% of the PV-10 Value of the Eligible Proved Developed
Producing Reserves of the Pledging Subsidiaries directly owned by the Pledging
Subsidiaries, as reflected in the most recent report delivered in accordance with
Section 6.2
, plus
(x) an amount with respect to each Partnership equal to 65% of the PV-10 Value
of the Eligible Proved Developed Producing Reserves directly owned by such
Partnership multiplied by the general partnership interest of the Pledging
Subsidiary in such partnership, plus
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(y) an amount with respect to the LLC equal to 65% of the PV-10 Value of the
Eligible Proved Developed Producing Reserves directly owned by the LLC multiplied by
the membership interest of A&W in the LLC, minus
(z) the sum of (i) the Bank Products Reserves, and (ii) the aggregate amount of
reserves, if any, established by Lender under
Section 2.1(b)
.
(b) Anything to the contrary in this
Section 2.1
notwithstanding, the Agent
shall have the right to establish reserves in such amounts, and with respect to such
matters, as Agent, in its Permitted Discretion, shall deem necessary or appropriate against
the Borrowing Base including, but not limited to, reserves based upon (i) past due or
accrued taxes or other governmental charges including ad valorem, personal property,
production, severance, and other taxes which may have priority over the Liens or security
interests of Agent in the Collateral; (ii) Liens relating to the Collateral in favor of
third Persons; (iii) deposits which are due or scheduled to become due during the
immediately following 180 day period under deposit, escrow or other arrangements concerning
costs, expenses and liabilities relating to the plugging and abandonment of the Borrowing
Base Properties; (iv) estimates of present or future operating costs and expenses, royalty
and overriding payments and other costs and expenses associated with the maintenance and
operation of the Borrowing Base Properties; (v) estimates of present and future costs,
expenses, deposits and liabilities related to the plugging and abandonment of the Borrowing
Base Properties (net of the amount thereof which has been taken into account in the most
recent Reserve Report), (vi) without duplication of the foregoing, amounts owing by
Borrower, any of its Subsidiaries, the LLC or the Partnerships to any Person to the extent
secured by a Lien on, or trust (constructive or otherwise) over, any of the Collateral
(including proceeds thereof or collections from the sale of Hydrocarbons or Hydrocarbon
Interests which may from time to time come into the possession of Agent or the Lender Group
or its agents), which Lien or trust, in the determination of Agent, has a reasonable
possibility of having a priority superior to the Agents Liens (such as landlord liens, ad
valorem taxes, production taxes, severance taxes, sales taxes, collections attributable to
the sale of Hydrocarbons or Hydrocarbon Interests of Persons other than Borrower or any of
its Subsidiaries) in and to such item of Collateral, proceeds or collection, and (vii)
Hydrocarbon Interests Hedging Agreement Reserves.
(c) The Lenders with Revolver Commitments shall have no obligation to make additional
Advances hereunder to the extent such additional Advances would cause the Revolver Usage to
exceed the Maximum Revolver Amount.
(d) Amounts borrowed pursuant to this Section may be repaid and, subject to the terms
and conditions of this Agreement, reborrowed at any time during the term of this Agreement.
(e) The outstanding principal amount of the Advances, together with all unpaid interest
accrued thereon, shall be due and payable on the Maturity Date or, if earlier, on the date
on which they are declared due and payable pursuant to the terms of this Agreement.
2.2.
Term Loan
. Borrower hereby represents and warrants that Lenders have made the
Initial Term Loan in the principal amount equal to the Initial Term Loan Amount to Borrower for the
purposes set forth in
Section 6.20
hereof. Borrower represents and warrants that, as of
the date hereof, the unpaid principal amount of the Initial Term Loan is [$
] and such
amount is unconditionally owed by Borrower to Lenders without offset, defense or counterclaim of
any kind, nature or description whatsoever. Subject to the terms and conditions of this Agreement,
each Lender with a Term Loan Commitment agrees (severally, not jointly or jointly and severally) to
make, on or about the date of this
-28-
Agreement, the Additional Term Loan to Borrower in an amount equal to such Lenders Pro Rata
Share of the Additional Term Loan Amount. The Term Loan shall be repaid on the following dates and
in the following amounts:
|
|
|
|
|
Date
|
|
Installment Amount
|
July 10, 2008
|
|
$
|
1,000,000.00
|
|
July 10, 2009
|
|
$
|
1,000,000.00
|
|
July 10, 2010
|
|
$
|
1,000,000.00
|
|
July 10, 2011
|
|
$
|
1,000,000.00
|
|
The outstanding unpaid principal balance and all accrued and unpaid interest under the Term Loan
shall be due and payable on the earliest of (a) the Maturity Date, (b) the date of the acceleration
of the Term Loan in accordance with the terms hereof, and (c) the date of termination of this
Agreement, whether by its terms, by prepayment, or by acceleration. All amounts outstanding under
the Term Loan shall constitute Obligations.
2.3.
Borrowing Procedures
.
(a)
Procedure for Borrowing
. Each Borrowing shall be made by an irrevocable
written request by an Authorized Person delivered to Agent. Such notice must be received by
Agent no later than 10:00 a.m. (California time) on the Business Day prior to the date that
is the requested Funding Date specifying (i) the amount of such Borrowing, and (ii) the
requested Funding Date, which shall be a Business Day;
provided
,
however
,
that in the case of a request for a Swing Loan in an amount of $5,000,000.00, or less, such
notice will be timely received if it is received by Agent no later than 10:00 a.m.
(California time) on the Business Day that is the requested Funding Date) specifying (i) the
amount of such Borrowing, and (ii) the requested Funding Date, which shall be a Business
Day. At Agents election, in lieu of delivering the above-described written request, any
Authorized Person may give Agent telephonic notice of such request by the required time. In
such circumstances, Borrower agrees that any such telephonic notice will be confirmed in
writing within 24 hours of the giving of such telephonic notice, but the failure to provide
such written confirmation shall not affect the validity of the request.
(b)
Agents Election
. Promptly after receipt of a request for a Borrowing
pursuant to
Section 2.3(a)
, Agent shall elect, in its discretion, (i) to have the
terms of
Section 2.3(c)
apply to such requested Borrowing, or (ii) if the Borrowing
is for an Advance, to request Swing Lender to make a Swing Loan pursuant to the terms of
Section 2.3(d)
in the amount of the requested Borrowing;
provided
,
however
, that if Swing Lender declines in its sole discretion to make a Swing Loan
pursuant to
Section 2.3(d)
, Agent shall elect to have the terms of
Section
2.3(c)
apply to such requested Borrowing.
(c)
Making of Loans
.
(i) In the event that Agent shall elect to have the terms of this
Section
2.3(c)
apply to a requested Borrowing as described in
Section 2.3(b)
,
then promptly after receipt of a request for a Borrowing pursuant to
Section
2.3(a)
, Agent shall notify the Lenders, not later than 1:00 p.m. (California
time) on the Business Day immediately
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preceding the Funding Date applicable thereto, by telecopy, telephone, or other
similar form of transmission, of the requested Borrowing. Each Lender shall make
the amount of such Lenders Pro Rata Share of the requested Borrowing available to
Agent in immediately available funds, to Agents Account, not later than 10:00 a.m.
(California time) on the Funding Date applicable thereto. After Agents receipt of
the proceeds of such Advances (or the Term Loan, as applicable), upon satisfaction
of the conditions precedent set forth in
Section 3
hereof, Agent shall make
the proceeds thereof available to Borrower on the applicable Funding Date by
transferring immediately available funds equal to such proceeds received by Agent to
Borrowers Designated Account;
provided
,
however
, that, subject to
the provisions of
Section 2.3(i)
, Agent shall not request any Lender to
make, and no Lender shall have the obligation to make, any Advance (or its portion
of the Term Loan) if Agent shall have actual knowledge that (1) one or more of the
applicable conditions precedent set forth in
Section 3
will not be satisfied
on the requested Funding Date for the applicable Borrowing unless such condition has
been waived, or (2) the requested Borrowing would exceed the Availability on such
Funding Date.
(ii) Unless Agent receives notice from a Lender on or prior to the date hereof
or, with respect to any Borrowing after the date hereof, at least 1 Business Day
prior to the date of such Borrowing, that such Lender will not make available as and
when required hereunder to Agent for the account of Borrower the amount of that
Lenders Pro Rata Share of the Borrowing, Agent may assume that each Lender has made
or will make such amount available to Agent in immediately available funds on the
Funding Date and Agent may (but shall not be so required), in reliance upon such
assumption, make available to Borrower on such date a corresponding amount. If and
to the extent any Lender shall not have made its full amount available to Agent in
immediately available funds and Agent in such circumstances has made available to
Borrower such amount, that Lender shall on the Business Day following such Funding
Date make such amount available to Agent, together with interest at the Defaulting
Lender Rate for each day during such period. A notice submitted by Agent to any
Lender with respect to amounts owing under this subsection shall be conclusive,
absent manifest error. If such amount is so made available, such payment to Agent
shall constitute such Lenders Advance (or portion of the Term Loan, as applicable)
on the date of Borrowing for all purposes of this Agreement. If such amount is not
made available to Agent on the Business Day following the Funding Date, Agent will
notify Borrower of such failure to fund and, upon demand by Agent, Borrower shall
pay such amount to Agent for Agents account, together with interest thereon for
each day elapsed since the date of such Borrowing, at a rate per annum equal to the
interest rate applicable at the time to the Advances (or portion of the Term Loan,
as applicable) composing such Borrowing. The failure of any Lender to make any
Advance (or portion of the Term Loan, as applicable) on any Funding Date shall not
relieve any other Lender of any obligation hereunder to make an Advance (or portion
of the Term Loan, as applicable) on such Funding Date, but no Lender shall be
responsible for the failure of any other Lender to make the Advance (or portion of
the Term Loan, as applicable) to be made by such other Lender on any Funding Date.
(iii) Agent shall not be obligated to transfer to a Defaulting Lender any
payments made by Borrower to Agent for the Defaulting Lenders benefit, and, in the
absence of such transfer to the Defaulting Lender, Agent shall transfer any such
payments to each other non-Defaulting Lender member of the Lender Group ratably in
accordance with their Commitments (but only to the extent that such Defaulting
Lenders Advance was funded by the other members of the Lender Group) or, if so
directed by Borrower
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and if no Default or Event of Default has occurred and is continuing (and to
the extent such Defaulting Lenders Advance was not funded by the Lender Group),
retain same to be re-advanced to Borrower as if such Defaulting Lender had made
Advances to Borrower. Subject to the foregoing, Agent may hold and, in its
Permitted Discretion, re-lend to Borrower for the account of such Defaulting Lender
the amount of all such payments received and retained by Agent for the account of
such Defaulting Lender. Solely for the purposes of voting or consenting to matters
with respect to the Loan Documents, such Defaulting Lender shall be deemed not to be
a Lender and such Lenders Commitment shall be deemed to be zero. This Section
shall remain effective with respect to such Lender until (x) the Obligations under
this Agreement shall have been declared or shall have become immediately due and
payable, (y) the non-Defaulting Lenders, Agent, and Borrower shall have waived such
Defaulting Lenders default in writing, or (z) the Defaulting Lender makes its Pro
Rata Share of the applicable Advance and pays to Agent all amounts owing by
Defaulting Lender in respect thereof. The operation of this Section shall not be
construed to increase or otherwise affect the Commitment of any Lender, to relieve
or excuse the performance by such Defaulting Lender or any other Lender of its
duties and obligations hereunder, or to relieve or excuse the performance by
Borrower of its duties and obligations hereunder to Agent or to the Lenders other
than such Defaulting Lender. Any such failure to fund by any Defaulting Lender
shall constitute a material breach by such Defaulting Lender of this Agreement and
shall entitle Borrower at its option, upon written notice to Agent, to arrange for a
substitute Lender to assume the Commitment of such Defaulting Lender, such
substitute Lender to be acceptable to Agent. In connection with the arrangement of
such a substitute Lender, the Defaulting Lender shall have no right to refuse to be
replaced hereunder, and agrees to execute and deliver a completed form of Assignment
and Acceptance Agreement in favor of the substitute Lender (and agrees that it shall
be deemed to have executed and delivered such document if it fails to do so) subject
only to being repaid its share of the outstanding Obligations (other than Bank
Product Obligation, but including an assumption of its Pro Rata Share of the Risk
Participation Liability) without any premium or penalty of any kind whatsoever;
provided
further
,
however
, that any such assumption of the
Commitment of such Defaulting Lender shall not be deemed to constitute a waiver of
any of the Lender Groups or Borrowers rights or remedies against any such
Defaulting Lender arising out of or in relation to such failure to fund.
(d)
Making of Swing Loans
.
(i) In the event Agent shall elect, with the consent of Swing Lender, as a
Lender, to have the terms of this
Section 2.3(d)
apply to a requested
Borrowing as described in
Section 2.3(b)
, Swing Lender as a Lender shall
make such Advance in the amount of such Borrowing (any such Advance made solely by
Swing Lender as a Lender pursuant to this
Section 2.3(d)
being referred to
as a
Swing Loan
and such Advances being referred to collectively as
Swing Loans
)
available to Borrower on the Funding Date applicable thereto by transferring
immediately available funds to Borrowers Designated Account. Each Swing Loan shall
be deemed to be an Advance hereunder and shall be subject to all the terms and
conditions applicable to other Advances, except that no such Swing Loan shall be
eligible to be a LIBOR Rate Loan and all payments on any Swing Loan shall be payable
to Swing Lender as a Lender solely for its own account (and for the account of the
holder of any participation interest with respect to such Swing Loan). Subject to
the provisions of
Section 2.3(i)
, Agent shall not request Swing Lender as a
Lender to make, and Swing Lender as a Lender shall not make, any Swing Loan if
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Agent has actual knowledge that (i) one or more of the applicable conditions
precedent set forth in
Section 3
will not be satisfied on the requested
Funding Date for the applicable Borrowing unless such condition has been waived, or
(ii) the requested Borrowing would exceed the Availability on such Funding Date.
Swing Lender as a Lender shall not otherwise be required to determine whether the
applicable conditions precedent set forth in
Section 3
have been satisfied
on the Funding Date applicable thereto prior to making, in its sole discretion, any
Swing Loan.
(ii) The Swing Loans shall be secured by the Agents Liens, constitute
Obligations hereunder, and bear interest at the rate applicable from time to time to
Advances that are Base Rate Loans.
(e)
Agent Advances
.
(i) Agent hereby is authorized by Borrower and the Lenders, from time to time
in Agents sole discretion, (1) after the occurrence and during the continuance of a
Default or an Event of Default, or (2) at any time that any of the other applicable
conditions precedent set forth in
Section 3
have not been satisfied, to make
Advances to Borrower on behalf of the Lenders that Agent, in its Permitted
Discretion deems necessary or desirable (A) to preserve or protect the Collateral,
or any portion thereof, (B) to enhance the likelihood of repayment of the
Obligations, or (C) to pay any other amount chargeable to Borrower pursuant to the
terms of this Agreement, including Lender Group Expenses and the costs, fees, and
expenses described in
Section 10
(any of the Advances described in this
Section 2.3(e)
shall be referred to as
Agent Advances
). Each Agent
Advance is an Advance hereunder and shall be subject to all the terms and conditions
applicable to other Advances, except that no such Agent Advance shall be eligible to
be a LIBOR Rate Loan and all payments thereon shall be payable to Agent solely for
its own account (and for the account of the holder of any participation interest
with respect to such Agent Advance).
(ii) The Agent Advances shall be repayable on demand and secured by the Agents
Liens granted to Agent under the Loan Documents, shall constitute Advances and
Obligations hereunder, and shall bear interest at the rate applicable from time to
time to Advances that are Base Rate Loans.
(f)
Settlement
. It is agreed that each Lenders funded portion of the Advances
is intended by the Lenders to equal, at all times, such Lenders Pro Rata Share of the
outstanding Advances. Such agreement notwithstanding, Agent, Swing Lender, and the other
Lenders agree (which agreement shall not be for the benefit of or enforceable by Borrower)
that in order to facilitate the administration of this Agreement and the other Loan
Documents, settlement among them as to the Advances, the Swing Loans, and the Agent Advances
shall take place on a periodic basis in accordance with the following provisions:
(i) Agent shall request settlement (
Settlement
) with the Lenders on a weekly
basis, or on a more frequent basis if so determined by Agent, (1) on behalf of Swing
Lender, with respect to each outstanding Swing Loan, (2) for itself, with respect to
each Agent Advance, and (3) with respect to Collections received, as to each by
notifying the Lenders by telecopy, telephone, or other similar form of transmission,
of such requested Settlement, no later than 2:00 p.m. (California time) on the
Business Day immediately prior to the date of such requested Settlement (the date of
such requested Settlement being the
Settlement Date
). Such notice of a Settlement
Date shall include
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a summary statement of the amount of outstanding Advances, Swing Loans, and
Agent Advances for the period since the prior Settlement Date. Subject to the terms
and conditions contained herein (including
Section 2.
3(c)(iii)
): (y) if a
Lenders balance of the Advances (including Swing Loans and Agent Advances) exceeds
such Lenders Pro Rata Share of the Advances (including Swing Loans and Agent
Advances) as of a Settlement Date, then Agent shall, by no later than 12:00 p.m.
(California time) on the Settlement Date, transfer in immediately available funds to
the account of such Lender (as such Lender may designate), an amount such that each
such Lender shall, upon receipt of such amount, have as of the Settlement Date, its
Pro Rata Share of the Advances (including Swing Loans and Agent Advances) and (z) if
a Lenders balance of the Advances, Swing Loans, and Agent Advances is less than
such Lenders Pro Rata Share of the Advances (including Swing Loans and Agent
Advances) as of a Settlement Date, such Lender shall no later than 12:00 p.m.
(California time) on the Settlement Date transfer in immediately available funds to
the Agents Account, an amount such that each such Lender shall, upon transfer of
such amount, have as of the Settlement Date, its Pro Rata Share of the Advances,
Swing Loans, and Agent Advances. Such amounts made available to Agent under clause
(z) of the immediately preceding sentence shall be applied against the amounts of
the applicable Swing Loan or Agent Advance and, together with the portion of such
Swing Loan or Agent Advance representing Swing Lenders Pro Rata Share thereof,
shall constitute Advances of such Lenders. If any such amount is not made available
to Agent by any Lender on the Settlement Date applicable thereto to the extent
required by the terms hereof, Agent shall be entitled to recover for its account
such amount on demand from such Lender together with interest thereon at the
Defaulting Lender Rate.
(ii) In determining whether a Lenders balance of the Advances, Swing Loans,
and Agent Advances is less than, equal to, or greater than such Lenders Pro Rata
Share of the Advances, Swing Loans, and Agent Advances as of a Settlement Date,
Agent shall, as part of the relevant Settlement, apply to such balance the portion
of payments actually received in good funds by Agent with respect to principal,
interest, fees payable by Borrower and allocable to the Lenders hereunder, and
proceeds of Collateral. To the extent that a net amount is owed to any such Lender
after such application, such net amount shall be distributed by Agent to that Lender
as part of such next Settlement.
(iii) Between Settlement Dates, Agent, to the extent no Agent Advances or Swing
Loans are outstanding, may pay over to Swing Lender any payments received by Agent,
that in accordance with the terms of this Agreement would be applied to the
reduction of the Advances, for application to Swing Lenders Pro Rata Share of the
Advances. If, as of any Settlement Date, Collections received since the then
immediately preceding Settlement Date have been applied to Swing Lenders Pro Rata
Share of the Advances other than to Swing Loans, as provided for in the previous
sentence, Swing Lender shall pay to Agent for the accounts of the Lenders, and Agent
shall pay to the Lenders, to be applied to the outstanding Advances of such Lenders,
an amount such that each Lender shall, upon receipt of such amount, have, as of such
Settlement Date, its Pro Rata Share of the Advances. During the period between
Settlement Dates, Swing Lender with respect to Swing Loans, Agent with respect to
Agent Advances, and each Lender (subject to the effect of agreements between Agent
and individual Lenders) with respect to the Advances other than Swing Loans and
Agent Advances, shall be entitled to interest at the applicable rate or rates
payable under this Agreement on the daily amount of funds employed by Swing Lender,
Agent, or the Lenders, as applicable.
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(g)
Notation
. Agent shall record on its books the principal amount of the
Advances (or portion of the Term Loan, as applicable) owing to each Lender, including the
Swing Loans owing to Swing Lender, and Agent Advances owing to Agent, and the interests
therein of each Lender, from time to time and such records shall, absent manifest error,
conclusively be presumed to be correct and accurate. In addition, each Lender is
authorized, at such Lenders option, to note the date and amount of each payment or
prepayment of principal of such Lenders Advances (or portion of the Term Loan, as
applicable) in its books and records, including computer records, such books and records
constituting conclusive evidence, absent manifest error, of the accuracy of the information
contained therein. There shall be no promissory notes evidencing the payment obligations of
Borrower to Lenders.
(h)
Lenders Failure to Perform
. All Advances (other than Swing Loans and
Agent Advances) shall be made by the Lenders contemporaneously and in accordance with their
Pro Rata Shares. It is understood that (i) no Lender shall be responsible for any failure
by any other Lender to perform its obligation to make any Advance (or other extension of
credit) hereunder, nor shall any Commitment of any Lender be increased or decreased as a
result of any failure by any other Lender to perform its obligations hereunder, and (ii) no
failure by any Lender to perform its obligations hereunder shall excuse any other Lender
from its obligations hereunder.
(i)
Optional Overadvances
. Any contrary provision of this Agreement
notwithstanding, the Lenders hereby authorize Agent or Swing Lender, as applicable, and
Agent or Swing Lender, as applicable, may, but is not obligated to, knowingly and
intentionally, continue to make Advances (including Swing Loans) to Borrower notwithstanding
that an Overadvance exists or thereby would be created, so long as (i) after giving effect
to such Advances (including a Swing Loan), the outstanding Revolver Usage does not exceed
the Borrowing Base by more than $5,000,000.00, (ii) after giving effect to such Advances
(including a Swing Loan) the outstanding Revolver Usage (except for and excluding amounts
charged to the Loan Account for interest, fees, or Lender Group Expenses) does not exceed
the Maximum Revolver Amount, and (iii) at the time of the making of any such Advance
(including a Swing Loan), Agent does not believe, in good faith, that the Overadvance
created by such Advance will be outstanding for more than 90 days. The foregoing provisions
are for the exclusive benefit of Agent, Swing Lender, and the Lenders and are not intended
to benefit Borrower in any way. The Advances and Swing Loans, as applicable, that are made
pursuant to this
Section 2.3(i)
shall be subject to the same terms and conditions as
any other Advance or Swing Loan, as applicable, except that they shall not be eligible for
the LIBOR Option and the rate of interest applicable thereto shall be the rate applicable to
Advances that are Base Rate Loans under
Section 2.6(c)
hereof without regard to the
presence or absence of a Default or Event of Default.
(i) In the event Agent obtains actual knowledge that the Revolver Usage exceeds
the amounts permitted by the preceding paragraph, regardless of the amount of, or
reason for, such excess, Agent shall notify Lenders as soon as practicable (and
prior to making any (or any additional) intentional Overadvances (except for and
excluding amounts charged to the Loan Account for interest, fees, or Lender Group
Expenses) unless Agent determines that prior notice would result in imminent harm to
the Collateral or its value), and the Lenders with Revolver Commitments thereupon
shall, together with Agent, jointly determine the terms of arrangements that shall
be implemented with Borrower and intended to reduce, within a reasonable time, the
outstanding principal amount of the Advances to Borrower to an amount permitted by
the preceding paragraph. In the event Agent or any Lender disagrees over the terms
of reduction or repayment of any Overadvance, the terms of reduction or repayment
thereof shall be implemented according to the determination of the Required Lenders.
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(ii) Each Lender with a Revolver Commitment shall be obligated to settle with
Agent as provided in
Section 2.3(f)
for the amount of such Lenders Pro Rata
Share of any unintentional Overadvances by Agent reported to such Lender, any
intentional Overadvances made as permitted under this
Section 2.3(i)
, and
any Overadvances resulting from the charging to the Loan Account of interest, fees,
or Lender Group Expenses.
2.4.
Payments
.
(a)
Payments by Borrower
.
(i) Except as otherwise expressly provided herein, all payments by Borrower
shall be made to Agents Account for the account of the Lender Group and shall be
made in immediately available funds, no later than 11:00 a.m. (California time) on
the date specified herein. Any payment received by Agent later than 11:00 a.m.
(California time), shall be deemed to have been received on the following Business
Day and any applicable interest or fee shall continue to accrue until such following
Business Day.
(ii) Unless Agent receives notice from Borrower prior to the date on which any
payment is due to the Lenders that Borrower will not make such payment in full as
and when required, Agent may assume that Borrower has made (or will make) such
payment in full to Agent on such date in immediately available funds and Agent may
(but shall not be so required), in reliance upon such assumption, distribute to each
Lender on such due date an amount equal to the amount then due such Lender. If and
to the extent Borrower does not make such payment in full to Agent on the date when
due, each Lender severally shall repay to Agent on demand such amount distributed to
such Lender, together with interest thereon at the Defaulting Lender Rate for each
day from the date such amount is distributed to such Lender until the date repaid.
(b)
Apportionment and Application
.
(i) Except as otherwise provided with respect to Defaulting Lenders and except
as otherwise provided in the Loan Documents (including letter agreements between
Agent and individual Lenders), aggregate principal and interest payments shall be
apportioned ratably among the Lenders (according to the unpaid principal balance of
the Obligations to which such payments relate held by each Lender) and payments of
fees and expenses (other than fees or expenses that are for Agents separate
account, after giving effect to any letter agreements between Agent and individual
Lenders) shall be apportioned ratably among the Lenders having a Pro Rata Share of
the type of Commitment or Obligation to which a particular fee relates. All
payments shall be remitted to Agent and all such payments (other than payments
received while no Default or Event of Default has occurred and is continuing and
which relate to the payment of principal or interest of specific Obligations or
which relate to the payment of specific fees), and all proceeds of Accounts or other
Collateral received by Agent, shall be applied as follows:
A.
first
, to pay any Lender Group Expenses then due to Agent
under the Loan Documents, until paid in full,
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B.
second
, to pay any Lender Group Expenses then due to the
Lenders under the Loan Documents, on a ratable basis, until paid in full,
C.
third
, to pay any fees then due to Agent (for its separate
accounts, after giving effect to any letter agreements between Agent and the
individual Lenders) under the Loan Documents until paid in full,
D.
fourth
, to pay any fees then due to any or all of the
Lenders (after giving effect to any letter agreements between Agent and
individual Lenders) under the Loan Documents, on a ratable basis, until paid
in full,
E.
fifth
, to pay interest due in respect of all Agent Advances,
until paid in full,
F.
sixth
, ratably to pay interest due in respect of the
Advances (other than Agent Advances), the Swing Loans, and the Term Loan
until paid in full,
G.
seventh
, to pay the principal of all Agent Advances until
paid in full,
H.
eighth
, ratably to pay all principal amounts then due and
payable (other than as a result of an acceleration thereof) with respect to
the Term Loan until paid in full,
I.
ninth
, to pay the principal of all Swing Loans until paid in
full,
J.
tenth
, so long as no Event of Default has occurred and is
continuing, and at Agents election (which election Agent agrees will not be
made if an Overadvance would be created thereby), to pay amounts then due
and owing in respect of Bank Product Obligations until paid in full,
K.
eleventh
, so long as no Event of Default has occurred and is
continuing, to pay the principal of all Advances until paid in full,
L.
twelfth
, so long as no Event of Default has occurred and is
continuing, to pay any other Obligations until paid in full,
M.
thirteenth
, if an Event of Default has occurred and is
continuing, to pay amounts to Agent, to be held by Agent, for the benefit of
the Bank Product Providers, as cash collateral in an amount up to the amount
determined by Agent in its Permitted Discretion as the amount necessary to
secure the Bank Product Obligations,
N.
fourteenth
, if an Event of Default has occurred and is
continuing, ratably (i) to pay the principal of all Advances until paid in
full, and (ii) to Agent, to be held by Agent, for the ratable benefit of
Issuing Lender and those Lenders having a Revolver Commitment, as cash
collateral in an amount up to 105% of the then extant Letter of Credit Usage
until paid in full,
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O.
fifteenth
, if an Event of Default has occurred and is
continuing, to pay the outstanding principal balance of the Term Loan (in
the inverse order of the maturity of the installments due thereunder) until
the Term Loan is paid in full,
P.
sixteenth
, if an Event of Default has occurred and is
continuing, to pay any other Obligations, and
Q.
seventeenth
, to Borrower (to be wired to the Designated
Account) or such other Person entitled thereto under applicable law.
(ii) Agent promptly shall distribute to each Lender, pursuant to the applicable
wire instructions received from each Lender in writing, such funds as it may be
entitled to receive, subject to a Settlement delay as provided in
Section
2.3(f)
.
(iii) In each instance, so long as no Default or Event of Default has occurred
and is continuing,
Section 2.4(b)
shall not be deemed to apply to any
payment made by Borrower to Agent specified by Borrower to be for the payment of
specific Obligations then due and payable (or prepayable) under any provision of
this Agreement.
(iv) For purposes of the foregoing, paid in full means payment of all amounts
owing under the Loan Documents according to the terms thereof, including loan fees,
service fees, professional fees, interest (and specifically including interest
accrued after the commencement of any Insolvency Proceeding), default interest,
interest on interest, and expense reimbursements, whether or not any of the
foregoing would be or is allowed or disallowed in whole or in part in any Insolvency
Proceeding.
(v) In the event of a direct conflict between the priority provisions of this
Section 2.4
and other provisions contained in any other Loan Document, it is
the intention of the parties hereto that such priority provisions in such documents
shall be read together and construed, to the fullest extent possible, to be in
concert with each other. In the event of any actual, irreconcilable conflict that
cannot be resolved as aforesaid, the terms and provisions of this
Section
2.4
shall control and govern.
2.5.
Overadvances
. If at any time or for any reason, the amount of Obligations (other
than Bank Product Obligations) owed by Borrower to the Agent and the Lender Group pursuant to
Sections 2.1, 2.2 and 2.12
is greater than an amount equal to the lower of (a) the Maximum
Loan Amount, or (b) the then current Borrowing Base (an
Overadvance
), Borrower, within five (5)
Business Days from the date of each such occurrence, shall notify the Agent that Borrower shall
take one of the following actions:
(a) execute and deliver, and/or cause the Pledging Subsidiaries or any other Subsidiary
to execute and deliver to the Agent within sixty (60) days from and after the date of the
occurrence of such Overadvance, supplemental or additional Mortgages, in form and substance
satisfactory to the Agent and its counsel, securing payment of the Obligations and covering
Oil and Gas Properties directly owned by Borrower, the Pledging Subsidiaries or such other
Subsidiary which are not then covered by any Loan Document and which are of a type and
nature satisfactory to the Agent, and having a value (as determined by the Agent in its sole
discretion), in addition to other Oil and Gas Properties already subject to a Mortgage,
sufficient to eliminate the Overadvance, all as more particularly described in
Sections
6.
21(c)
and (d)
; or
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(b) make a payment with respect to the Obligations, in an aggregate principal amount
sufficient to eliminate such Overadvance within ten (10) days after the date of the
occurrence of such Overadvance (and the Borrower shall make such payment within such ten-day
period).
If the Borrower shall elect to execute and deliver, and/or to cause the Pledging Subsidiaries or
any other Subsidiary to execute and deliver supplemental or additional Security Documents to the
Agent pursuant to
clause (a)
, it shall provide the Agent with descriptions of the
additional assets to be mortgaged (together with current valuations, engineering reports, Security
Documents described in
clause (a)
and title evidence applicable thereto and other documents
including opinions of counsel, each of which shall be in form and substance reasonably satisfactory
to the Agent) within sixty (60) days after the date of the occurrence of such Overadvance. Such
supplemental or additional Security Documents shall be subject to the terms of
Section
6.21
. If the Borrower fails to give the required notice that it shall take any of the actions
described in this
Section 2.5
within such five (5) Business Day period or take the
applicable action in
subclauses (a)
or
(b)
above within such sixty (60) or ten (10)
day (as applicable) period, in each case from and after the date of the occurrence of the
Overadvance, then without any necessity for notice to the Borrower or any other person, the
Borrower shall become obligated immediately to pay Obligations in an aggregate principal amount
equal to the applicable Overadvance.
2.6.
Interest Rates and Letter of Credit Fee: Rates, Payments, and Calculations
.
(a)
Interest Rates
. Except as provided in clause (c) below, all Obligations
(except for undrawn Letters of Credit and except for Bank Product Obligations) that have
been charged to the Loan Account pursuant to the terms hereof shall bear interest on the
Daily Balance thereof as follows: (i) if the relevant Obligation is a LIBOR Rate Loan, at a
per annum rate equal to the LIBOR Rate plus the Applicable Margin, (ii) if the relevant
Obligation is a Base Rate Loan, at a per annum rate equal to the Base Rate plus the
Applicable Margin, and (iii) otherwise, at a per annum rate equal to the Base Rate plus the
Applicable Rate Margin for Base Rate Loans;
provided
,
however
, that the
outstanding principal amount of the Term Loan shall bear interest as follows: (x) if a
LIBOR Rate Loan, at a per annum rate equal to the LIBOR Rate plus 1.50%, and (y) if a Base
Rate Loan, at a per annum rate equal to the Base Rate less 0.25%.
(b)
Letter of Credit Fee
. Borrower shall pay Agent (for the ratable benefit of
the Lenders with a Revolver Commitment, subject to any letter agreement between Agent and
individual Lenders), a Letter of Credit fee (in addition to the charges, commissions, fees,
and costs set forth in
Section 2.12(e)
) which shall accrue at a rate equal to 2.25%
per annum times the Daily Balance of the undrawn amount of all outstanding Letters of
Credit.
(c)
Default Rate
. Upon the occurrence and during the continuation of an Event
of Default (and at the election of Agent or the Required Lenders),
(i) all Obligations (except for undrawn Letters of Credit and Bank Product
Obligations) that have been charged to the Loan Account pursuant to the terms hereof
shall bear interest on the Daily Balance thereof at a per annum rate equal to 4
percentage points above the per annum rate otherwise applicable hereunder, and
(ii) the Letter of Credit fee provided for above shall be increased to 4
percentage points above the per annum rate otherwise applicable hereunder.
(d)
Payment
. Except as provided to the contrary in
Section 2.11
or
Section 2.13(a)
, interest, Letter of Credit fees, and all other fees payable
hereunder shall be due and payable, in
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arrears, on the first day of each month at any time that Obligations or Commitments are
outstanding. Borrower hereby authorizes Agent, from time to time, without prior notice to
Borrower, to charge all interest and fees (when due and payable), all Lender Group Expenses
(as and when incurred), all charges, commissions, fees, and costs provided for in
Section 2.12(e)
(as and when accrued or incurred), all fees and costs provided for
in
Section 2.11
(as and when accrued or incurred), and all other payments as and
when due and payable under any Loan Document (including the amounts due and payable with
respect to the Term Loan and including any amounts due and payable to the Bank Product
Providers in respect of Bank Products up to the amount of the then extant Bank Products
Reserve) to Borrowers Loan Account, which amounts thereafter shall constitute Advances
hereunder and shall accrue interest at the rate then applicable to Advances hereunder. Any
interest not paid when due shall be compounded by being charged to Borrowers Loan Account
and shall thereafter constitute Advances hereunder and shall accrue interest at the rate
then applicable to Advances that are Base Rate Loans hereunder.
(e)
Computation
. All interest and fees chargeable under the Loan Documents
shall be computed on the basis of a 360 day year for the actual number of days elapsed. In
the event the Base Rate is changed from time to time hereafter, the rates of interest
hereunder based upon the Base Rate automatically and immediately shall be increased or
decreased by an amount equal to such change in the Base Rate.
(f)
Intent to Limit Charges to Maximum Lawful Rate
. Borrower and the Lender
Group hereby agree and stipulate that the only charges imposed upon Borrower for the use of
money in connection with this Agreement are and shall be the specific interest and fees
described in this Article 2 and in any other Loan Document. Notwithstanding the foregoing,
Borrower and the Lender Group further agree and stipulate that all agency fees, syndication
fees, facility fees, underwriting fees, default charges, late charges, funding or breakage
charges, increased cost charges, the Applicable Prepayment Premium, float or clearance
charges, attorneys fees and reimbursement for costs and expenses paid by the Agent or the
Lender Group to third parties or for damages incurred by the Agent or the Lender Group are
charges to compensate the Agent and the Lender Group for underwriting and administrative
services and costs or losses performed or incurred, and to be performed and incurred, by the
Agent and the Lender Group in connection with this Agreement and the other Loan Documents.
In no event shall the amount of interest and other charges for the use of money payable
under this Agreement exceed the maximum amounts permissible under any law that a court of
competent jurisdiction shall, in a final determination, deem applicable. Borrower and the
Lender Group, in executing and delivering this Agreement, intend legally to agree upon the
rate or rates of interest and other charges for the use of money and manner of payment
stated within it;
provided
,
however
, that, anything contained herein to the
contrary notwithstanding, if the amount of such interest and other charges for the use of
money or manner of payment exceeds the maximum amount allowable under applicable law, then,
ipso facto as of the date of this Agreement, Borrower is and shall be liable only for the
payment of such maximum as allowed by law, and payment received from Borrower in excess of
such legal maximum whenever received, shall be applied to reduce the principal balance of
the Obligations to the extent of such excess.
2.7.
Cash Management
.
(a) Borrower shall (i) establish and maintain cash management services of a type and on
terms satisfactory to Agent at one or more of the banks set forth on
Schedule 2.7(a)
(each a
Cash Management Bank
), and shall request in writing and otherwise take such
reasonable steps, if necessary, to ensure that all Account Debtors of Borrower and the
Pledging Subsidiaries, forward payment of the amounts owed by them directly to such Cash
Management Bank, and (ii)
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deposit or cause to be deposited promptly, and in any event no later than the first
Business Day after the date of receipt thereof, all Collections (including those sent
directly by Account Debtors to a Cash Management Bank) into a bank account subject to a
Control Agreement (a
Cash Management Account
) at one of the Cash Management Banks.
(b) Each Cash Management Bank shall establish and maintain Cash Management Agreements
with Agent and Borrower, in form and substance acceptable to Agent. Each such Cash
Management Agreement shall provide, among other things, that (i) all items of payment
deposited in such Cash Management Account and proceeds thereof are held by such Cash
Management Bank as agent or bailee-in-possession for Agent, (ii) the Cash Management Bank
has no rights of setoff or recoupment or any other claim against the applicable Cash
Management Account, other than for payment of its service fees and other charges directly
related to the administration of such Cash Management Account and for returned checks or
other items of payment, and (iii) upon notice from Agent under such Cash Management
Agreement, the Cash Management Bank will immediately thereafter, until notified to the
contrary in writing by the Agent, forward by daily sweep (aa) an amount equal to seventeen
and one-half percent (17.5%) (the
Borrowers Estimated Percentage
) of all amounts
deposited in the applicable Cash Management Account to the Agents Account and (bb) an
amount equal to the remaining eighty-two and one-half percent (82.5%) of all other amounts
deposited in the applicable Cash Management Account to Borrowers account no. 4121083562 at
Wells Fargo.
(c) So long as no Default or Event of Default has occurred and is continuing, Borrower
may amend
Schedule 2.7(a)
to add or replace a Cash Management Bank or Cash
Management Account;
provided
,
however
, that (i) such prospective Cash
Management Bank shall be satisfactory to Agent and Agent shall have consented in writing in
advance to the opening of such Cash Management Account with the prospective Cash Management
Bank, and (ii) prior to the time of the opening of such Cash Management Account, Borrower
and such prospective Cash Management Bank shall have executed and delivered to Agent a Cash
Management Agreement. Borrower shall close any of their Cash Management Accounts (and
establish replacement cash management accounts in accordance with the foregoing sentence)
promptly and in any event within 30 days of notice from Agent that the creditworthiness of
any Cash Management Bank is no longer acceptable in Agents reasonable judgment, or as
promptly as practicable and in any event within 60 days of notice from Agent that the
operating performance, funds transfer, or availability procedures or performance of the Cash
Management Bank with respect to Cash Management Accounts or Agents liability under any Cash
Management Agreement with such Cash Management Bank is no longer acceptable in Agents
reasonable judgment.
(d) The Cash Management Accounts shall be cash collateral accounts, with Borrowers
ownership interest in all cash, checks and similar items of payment in such accounts
securing payment of the Obligations, and in which Borrower is hereby deemed to have granted
a Lien to Agent.
(e) Agent shall be entitled to deliver and maintain the notice of cash transfer (
Cash
Transfer Notice
) provided for in clause (iii) of
Section 2.7(b)
at any time, in the
Agents sole and absolute discretion, that a Default or Event of Default has occurred and is
continuing (each such time period a
Cash Sweep Period
). Once a Cash Sweep Period has been
established by Agent it shall remain in effect until the conditions giving rise to such Cash
Sweep Period no longer exist and Borrower has delivered to Agent a certificate to such
effect requesting a termination of such Cash Sweep Period.
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(f) During any Cash Sweep Period, Borrower shall on a monthly basis deliver to Agent a
report (each a
Monthly Funds Ownership Report
) reflecting (i) the actual percentage of
ownership by Borrower, the Pledging Subsidiaries, the LLC and the Partnerships of all funds
derived from the Borrowing Base Properties deposited to all Cash Management Banks during the
preceding monthly time period and (ii) the aggregate amount of such deposits (i.e., the
ownership percentage of Borrower, the Pledging Subsidiaries and the Pledging Subsidiaries in
the LLC and the Partnerships for such month expressed as a decimal multiplied by the
aggregate amount of all deposits to all Cash Management Banks during such month the
Borrowers Monthly Deposit
) in the Cash Management Account.
(g) In the event a Monthly Funds Ownership Report reflects that during a Cash Sweep
Period Borrowers Estimated Percentage has resulted in deposits to the Agents Account
during the preceding month in excess of the Borrowers Monthly Deposit for such month, Agent
shall, upon request of Borrower, within five (5) Business Days, return to Borrowers control
by wire transfer to the Designated Account an amount equal to the positive difference
between the Borrowers Monthly Deposit for such month and the aggregate deposits to the
Agents Account during such monthly time period.
(h) In the event a Monthly Funds Ownership Report reflects that during a Cash Sweep
Period Borrowers Estimated Percentage has resulted in deposits to the Agents Account
during the preceding month of less than the Borrowers Monthly Deposit for such month, Agent
shall promptly, in accordance with
Section 2.3(e)
of this Agreement, make an Advance
for the account of Borrower to be credited to the Agents Account in an amount equal to the
positive excess of the Borrowers Monthly Deposit for such month over the amount deposited
to Agents Account for such month as a result of the Borrowers Estimated Percentage.
2.8.
Crediting Payments; Collection Fee
. The receipt of any payment item by Agent
(whether from transfers to Agent by the Cash Management Banks pursuant to the Cash Management
Agreements or otherwise) shall not be considered a payment on account unless such payment item is a
wire transfer of immediately available federal funds made to the Agents Account or unless and
until such payment item is honored when presented for payment. Should any payment item not be
honored when presented for payment, then Borrower shall be deemed not to have made such payment and
interest shall be calculated accordingly. Anything to the contrary contained herein
notwithstanding, any payment item shall be deemed received by Agent only if it is received into the
Agents Account on a Business Day on or before 11:00 a.m. (California time). If any payment item
is received into the Agents Account on a non-Business Day or after 11:00 a.m. (California time) on
a Business Day, it shall be deemed to have been received by Agent as of the opening of business on
the immediately following Business Day. As consideration for Agents processing of all Collections,
from and after the Closing Date, Agent shall be entitled to charge Borrower a collection fee in the
amount of $1,500.00 a month (the
Collection Fee
). The Collection Fee is acknowledged by the
parties to constitute an integral aspect of the pricing of the financing of Borrower and shall
apply irrespective of whether or not there are any outstanding monetary Obligations. The parties
acknowledge and agree that the economic benefit of the foregoing provisions of this
Section
2.8
shall be for the exclusive benefit of Agent.
2.9.
Designated Account
. Agent is authorized to make the Advances, and the Term Loan,
and Issuing Lender is authorized to issue the Letters of Credit, under this Agreement based upon
telephonic or other instructions received from anyone purporting to be an Authorized Person, or
without instructions if pursuant to
Section 2.6(d)
. Borrower agrees to establish and
maintain the Designated Account with the Designated Account Bank for the purpose of receiving the
proceeds of the Advances requested by Borrower and made by Agent or the Lenders hereunder. Unless
otherwise agreed by Agent
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and Borrower, any Advance, Agent Advance, or Swing Loan requested by Borrower and made by
Agent or the Lenders hereunder shall be made to the Designated Account.
2.10.
Maintenance of Loan Account; Statements of Obligations
. Agent shall maintain an
account on its books in the name of Borrower (the
Loan Account
) on which Borrower will be charged
with the Term Loan, all Advances (including Agent Advances and Swing Loans) made by Agent, Swing
Lender, or the Lenders to Borrower or for Borrowers account, the Letters of Credit issued by
Issuing Lender for Borrowers account, and with all other payment Obligations hereunder or under
the other Loan Documents (except for Bank Product Obligations), including, accrued interest, fees
and expenses, and Lender Group Expenses. In accordance with
Section 2.8
, the Loan Account
will be credited with all payments received by Agent from Borrower or for Borrowers account,
including all amounts received in the Agents Account from any Cash Management Bank. Agent shall
render statements regarding the Loan Account to Borrower, including principal, interest, fees, and
including an itemization of all charges and expenses constituting Lender Group Expenses owing, and
such statements shall be conclusively presumed to be correct and accurate and constitute an account
stated between Borrower and the Lender Group unless, within 30 days after receipt thereof by
Borrower, Borrower shall deliver to Agent written objection thereto describing the error or errors
contained in any such statements.
2.11.
Fees
. Borrower shall pay to Agent the following fees and charges, which fees
and charges shall be non-refundable when paid (irrespective of whether this Agreement is terminated
thereafter) and shall be apportioned among the Lenders in accordance with the terms of letter
agreements between Agent and individual Lenders:
(a)
Unused Line Fee
. On the first day of each month during the term of this
Agreement, an unused line fee in the amount equal to one-half of one percent (0.50%) per
annum times the result of (a) the Maximum Revolver Amount less (b) the sum of (i) the
average Daily Balance of Advances that were outstanding during the immediately preceding
month, plus (ii) the average Daily Balance of the Letter of Credit Usage during the
immediately preceding month,
(b)
Fee Letter Fees
. As and when due and payable under the terms of the Fee
Letter, Borrower shall pay to Agent the fees set forth in the Fee Letter, and
(c)
Audit, Appraisal, and Valuation Charges
. For the separate account of
Agent, audit, appraisal, and valuation fees and charges as follows, (i) a fee of $850.00 per
day, per auditor, plus out-of-pocket expenses for each financial audit of Borrower performed
by personnel employed by Agent, (ii) a fee of $1,500.00 per day per appraiser, plus
out-of-pocket expenses, for each appraisal of the Collateral performed by personnel employed
by Agent, and (iii) the actual charges paid or incurred by Agent if it elects to employ the
services of one or more third Persons to perform financial audits of Borrower, to appraise
the Collateral, or any portion thereof, or to assess Borrowers business valuation.
2.12.
Letters of Credit
.
(a) Subject to the terms and conditions of this Agreement, the Issuing Lender agrees to
issue letters of credit for the account of Borrower (each, an
L/C
) or to purchase
participations or execute indemnities or reimbursement obligations (each such undertaking,
an
L/C Undertaking
) with respect to letters of credit issued by an Underlying Issuer (as
of the Closing Date, the prospective Underlying Issuer is to be Wells Fargo) for the account
of Borrower. To request the issuance of a Letter of Credit, (or the amendment, renewal, or
extension of an outstanding Letter of Credit), Borrower shall hand deliver or telecopy (or
transmit by electronic communication, if arrangements for doing so have been approved by the
Issuing Lender) to the
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Issuing Lender and Agent (reasonably in advance of the requested date of issuance,
amendment, renewal, or extension) a notice requesting the issuance of a Letter of Credit, or
identifying the Letter of Credit to be amended, renewed, or extended, the date of issuance,
amendment, renewal, or extension, the date on which such Letter of Credit is to expire, the
amount of such Letter of Credit, the name and address of the beneficiary thereof (or of the
Underlying Letter of Credit, as applicable), and such other information as shall be
necessary to prepare, amend, renew, or extend such Letter of Credit. If requested by the
Issuing Lender, Borrower also shall be an applicant under the application with respect to
any Underlying Letter of Credit that is to be the subject of a Letter of Credit. The
Issuing Lender shall have no obligation to issue a Letter of Credit if any of the following
would result after giving effect to the requested Letter of Credit:
(i) the Letter of Credit Usage would exceed the Borrowing Base less the amount
of outstanding Advances, or
(ii) the Letter of Credit Usage would exceed $5,000,000.00 or
(iii) the Letter of Credit Usage would exceed the Maximum Revolver Amount less
the then extant amount of outstanding Advances.
Borrower and the Lender Group acknowledge and agree that certain Underlying Letters of Credit
may be issued to support letters of credit that already are outstanding as of the Closing Date.
Each Letter of Credit (and corresponding Underlying Letter of Credit) shall have an expiry date no
later than 30 days prior to the Maturity Date and all such Letters of Credit (and corresponding
Underlying Letter of Credit) shall be in form and substance acceptable to the Issuing Lender (in
the exercise of its Permitted Discretion), including the requirement that the amounts payable
thereunder must be payable in Dollars. If Issuing Lender is obligated to advance funds under a
Letter of Credit, Borrower immediately shall reimburse such L/C Disbursement to Issuing Lender by
paying to Agent an amount equal to such L/C Disbursement not later than 11:00 a.m., California
time, on the date that such L/C Disbursement is made, if Borrower shall have received written or
telephonic notice of such L/C Disbursement prior to 10:00 a.m., California time, on such date, or,
if such notice has not been received by Borrower prior to such time on such date, then not later
than 11:00 a.m., California time, on the following Business Day and, in the absence of such
reimbursement, the L/C Disbursement immediately and automatically shall be deemed to be an Advance
hereunder and, thereafter, shall bear interest at the rate then applicable to Advances under this
Agreement. To the extent an L/C Disbursement is deemed to be an Advance hereunder, Borrowers
obligation to reimburse such L/C Disbursement shall be discharged and replaced by the resulting
Advance. Promptly following receipt by Agent of any payment from Borrower pursuant to this
paragraph, Agent shall distribute such payment to the Issuing Lender or, to the extent that Lenders
have made payments pursuant to
Section 2.12(c)
to reimburse the Issuing Lender, then to
such Lenders and the Issuing Lender as their interest may appear.
(b) Promptly following receipt of a notice of L/C Disbursement pursuant to
Section
2.12(a)
, each Lender with a Revolver Commitment agrees to fund its Pro Rata Share of any
Advance deemed made pursuant to the foregoing subsection on the same terms and conditions as
if Borrower had requested such Advance and Agent shall promptly pay to Issuing Lender the
amounts so received by it from the Lenders. By the issuance of a Letter of Credit (or an
amendment to a Letter of Credit increasing the amount thereof) and without any further
action on the part of the Issuing Lender or the Lenders with Revolver Commitments, the
Issuing Lender shall be deemed to have granted to each Lender with a Revolver Commitment,
and each Lender with a Revolver Commitment shall be deemed to have purchased, a
participation in each Letter of Credit, in an amount equal to its Pro Rata Share of the Risk
Participation Liability of such Letter of Credit, and each such Lender agrees to pay to
Agent, for the account of the Issuing Lender,
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such Lenders Pro Rata Share of any payments made by the Issuing Lender under such
Letter of Credit. In consideration and in furtherance of the foregoing, each Lender with a
Revolver Commitment hereby absolutely and unconditionally agrees to pay to Agent, for the
account of the Issuing Lender, such Lenders Pro Rata Share of each L/C Disbursement made by
the Issuing Lender and not reimbursed by Borrower on the date due as provided in clause (a)
of this Section, or of any reimbursement payment required to be refunded to Borrower for any
reason. Each Lender with a Revolver Commitment acknowledges and agrees that its obligation
to deliver to Agent, for the account of the Issuing Lender, an amount equal to its
respective Pro Rata Share of each L/C Disbursement made by the Issuing Lender pursuant to
this
Section 2.12(b)
shall be absolute and unconditional and such remittance shall
be made notwithstanding the occurrence or continuation of an Event of Default or Default or
the failure to satisfy any condition set forth in
Section 3
hereof. If any such
Lender fails to make available to Agent the amount of such Lenders Pro Rata Share of each
L/C Disbursement made by the Issuing Lender in respect of such Letter of Credit as provided
in this Section, such Lender shall be deemed to be a Defaulting Lender and Agent (for the
account of the Issuing Lender) shall be entitled to recover such amount on demand from such
Lender together with interest thereon at the Defaulting Lender Rate until paid in full.
(c) Borrower hereby agrees to indemnify, save, defend, and hold the Lender Group
harmless from any loss, cost, expense, or liability, and reasonable attorneys fees incurred
by the Lender Group arising out of or in connection with any Letter of Credit;
provided
,
however
, that Borrower shall not be obligated hereunder to
indemnify for any loss, cost, expense, or liability to the extent that it caused by the
gross negligence or willful misconduct of the Issuing Lender or any other member of the
Lender Group. Borrower agrees to be bound by the Underlying Issuers regulations and
interpretations of any Underlying Letter of Credit or by Issuing Lenders interpretations of
any L/C issued by Issuing Lender to or for Borrowers account, even though this
interpretation may be different from Borrowers own, and Borrower understands and agrees
that the Lender Group shall not be liable for any error, negligence, or mistake, whether of
omission or commission, in following Borrowers instructions or those contained in the
Letter of Credit or any modifications, amendments, or supplements thereto. Borrower
understands that the L/C Undertakings may require Issuing Lender to indemnify the Underlying
Issuer for certain costs or liabilities arising out of claims by Borrower against such
Underlying Issuer. Borrower hereby agrees to indemnify, save, defend, and hold the Lender
Group harmless with respect to any loss, cost, expense (including reasonable attorneys
fees), or liability incurred by the Lender Group under any L/C Undertaking as a result of
the Lender Groups indemnification of any Underlying Issuer;
provided
,
however
, that Borrower shall not be obligated hereunder to indemnify for any loss,
cost, expense, or liability to the extent that it caused by the gross negligence or willful
misconduct of the Issuing Lender or any other member of the Lender Group. Borrower hereby
acknowledges and agrees that neither the Lender Group nor the Issuing Lender shall be
responsible for delays, errors, or omissions resulting from the malfunction of equipment in
connection with any Letter of Credit.
(d) Borrower hereby authorizes and directs any Underlying Issuer to deliver to the
Issuing Lender all instruments, documents, and other writings and property received by such
Underlying Issuer pursuant to such Underlying Letter of Credit and to accept and rely upon
the Issuing Lenders instructions with respect to all matters arising in connection with
such Underlying Letter of Credit and the related application.
(e) Any and all charges, commissions, fees, and costs incurred by the Issuing Lender
relating to Underlying Letters of Credit shall be Lender Group Expenses for purposes of this
Agreement and immediately shall be reimbursable by Borrower to Agent for the account of the
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Issuing Lender; it being acknowledged and agreed by Borrower that, as of the Closing
Date, the issuance charge imposed by the prospective Underlying Issuer is .825% per annum
times the face amount of each Underlying Letter of Credit, that such issuance charge may be
changed from time to time, and that the Underlying Issuer also imposes a schedule of charges
for amendments, extensions, drawings, and renewals.
(f) If by reason of (i) any change after the Closing Date in any applicable law,
treaty, rule, or regulation or any change in the interpretation or application thereof by
any Governmental Authority, or (ii) compliance by the Underlying Issuer or the Lender Group
with any direction, request, or requirement (irrespective of whether having the force of
law) of any Governmental Authority or monetary authority including, Regulation D of the
Federal Reserve Board as from time to time in effect (and any successor thereto):
(i) any reserve, deposit, or similar requirement is or shall be imposed or
modified in respect of any Letter of Credit issued hereunder, or
(ii) there shall be imposed on the Underlying Issuer or the Lender Group any
other condition regarding any Underlying Letter of Credit or any Letter of Credit
issued pursuant hereto;
and the result of the foregoing is to increase, directly or indirectly, the cost to the Lender
Group of issuing, making, guaranteeing, or maintaining any Letter of Credit or to reduce the amount
receivable in respect thereof by the Lender Group, then, and in any such case, Agent may, at any
time within a reasonable period after the additional cost is incurred or the amount received is
reduced, notify Borrower, and Borrower shall pay on demand such amounts as Agent may specify to be
necessary to compensate the Lender Group for such additional cost or reduced receipt, together with
interest on such amount from the date of such demand until payment in full thereof at the rate then
applicable to the Base Rate Loans hereunder. The determination by Agent of any amount due pursuant
to this Section, as set forth in a certificate setting forth the calculation thereof in reasonable
detail, shall, in the absence of manifest or demonstrable error, be final and conclusive and
binding on all of the parties hereto.
2.13.
LIBOR Option
.
(a)
Interest and Interest Payment Dates
.
In lieu of having interest charged at
the rate based upon the Base Rate, Borrower shall have the option (the
LIBOR Option
) to
have interest on all or a portion of the Advances or the Term Loan be charged at a rate of
interest based upon the LIBOR Rate. Interest on LIBOR Rate Loans shall be payable on the
earliest of (i) the last day of the Interest Period applicable thereto (
provided
,
however
, that, subject to the following clauses (ii) and (iii), in the case of any
Interest Period greater than 3 months in duration, interest shall be payable at 3 month
intervals after the commencement of the applicable Interest Period and on the last day of
such Interest Period), (ii) the occurrence of an Event of Default in consequence of which
the Required Lenders or Agent on behalf thereof have elected to accelerate the maturity of
all or any portion of the Obligations, or (iii) termination of this Agreement pursuant to
the terms hereof. On the last day of each applicable Interest Period, unless Borrower
properly has exercised the LIBOR Option with respect thereto, the interest rate applicable
to such LIBOR Rate Loan automatically shall convert to the rate of interest then applicable
to Base Rate Loans of the same type hereunder. At any time that an Event of Default has
occurred and is continuing, Borrower no longer shall have the option to request that
Advances or the Term Loan bear interest at a rate based upon the LIBOR Rate and Agent shall
have the right to convert the interest rate on all outstanding LIBOR Rate Loans to the rate
then applicable to Base Rate Loans hereunder.
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(b)
LIBOR Election
.
(i) Borrower may, at any time and from time to time, so long as no Event of
Default has occurred and is continuing, elect to exercise the LIBOR Option by
notifying Agent prior to 11:00 a.m. (California time) at least 3 Business Days prior
to the commencement of the proposed Interest Period (the
LIBOR Deadline
). Notice
of Borrowers election of the LIBOR Option for a permitted portion of the Advances
or the Term Loan and an Interest Period pursuant to this Section shall be made by
delivery to Agent of a LIBOR Notice received by Agent before the LIBOR Deadline, or
by telephonic notice received by Agent before the LIBOR Deadline (to be confirmed by
delivery to Agent of a LIBOR Notice received by Agent prior to 5:00 p.m. (California
time) on the same day). Promptly upon its receipt of each such LIBOR Notice, Agent
shall provide a copy thereof to each of the Lenders having a Revolver Commitment or
Term Loan Commitment.
(ii) Each LIBOR Notice shall be irrevocable and binding on Borrower. In
connection with each LIBOR Rate Loan, Borrower shall indemnify, defend, and hold
Agent and the Lenders harmless against any loss, cost, or expense incurred by Agent
or any Lender as a result of (a) the payment of any principal of any LIBOR Rate Loan
other than on the last day of an Interest Period applicable thereto (including as a
result of an Event of Default), (b) the conversion of any LIBOR Rate Loan other than
on the last day of the Interest Period applicable thereto, or (c) the failure to
borrow, convert, continue or prepay any LIBOR Rate Loan on the date specified in any
LIBOR Notice delivered pursuant hereto (such losses, costs, and expenses,
collectively,
Funding Losses
). Funding Losses shall, with respect to Agent or any
Lender, be deemed to equal the amount determined by Agent or such Lender to be the
excess, if any, of (i) the amount of interest that would have accrued on the
principal amount of such LIBOR Rate Loan had such event not occurred, at the LIBOR
Rate that would have been applicable thereto, for the period from the date of such
event to the last day of the then current Interest Period therefor (or, in the case
of a failure to borrow, convert, or continue, for the period that would have been
the Interest Period therefor), minus (ii) the amount of interest that would accrue
on such principal amount for such period at the interest rate which Agent or such
Lender would be offered were it to be offered, at the commencement of such period,
Dollar deposits of a comparable amount and period in the London interbank market. A
certificate of Agent or a Lender delivered to Borrower setting forth any amount or
amounts that Agent or such Lender is entitled to receive pursuant to this
Section 2.13
shall be conclusive absent manifest error.
(iii) Borrower shall have not more than 7 LIBOR Rate Loans in effect at any
given time. Borrower only may exercise the LIBOR Option for LIBOR Rate Loans of at
least $1,000,000.00 and integral multiples of $1,000,000.00 in excess thereof.
(c)
Prepayments
. Borrower may prepay LIBOR Rate Loans at any time;
provided
,
however
, that in the event that LIBOR Rate Loans are prepaid on
any date that is not the last day of the Interest Period applicable thereto, including as a
result of any automatic prepayment through the required application by Agent of proceeds of
Borrowers and its Subsidiaries Collections in accordance with
Section 2.4(b)
or
for any other reason, including early termination of the term of this Agreement or
acceleration of all or any portion of the Obligations pursuant to the terms hereof, Borrower
shall indemnify, defend, and hold Agent and the Lenders and their Participants harmless
against any and all Funding Losses in accordance with clause (b)(ii) above.
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(d)
Special Provisions Applicable to LIBOR Rate
.
(i) The LIBOR Rate may be adjusted by Agent with respect to any Lender on a
prospective basis to take into account any additional or increased costs to such
Lender of maintaining or obtaining any eurodollar deposits or increased costs, in
each case, due to changes in applicable law occurring subsequent to the commencement
of the then applicable Interest Period, including changes in tax laws (except
changes of general applicability in corporate income tax laws) and changes in the
reserve requirements imposed by the Board of Governors of the Federal Reserve System
(or any successor), excluding the Reserve Percentage, which additional or increased
costs would increase the cost of funding loans bearing interest at the LIBOR Rate.
In any such event, the affected Lender shall give Borrower and Agent notice of such
a determination and adjustment and Agent promptly shall transmit the notice to each
other Lender and, upon its receipt of the notice from the affected Lender, Borrower
may, by notice to such affected Lender (y) require such Lender to furnish to
Borrower a statement setting forth the basis for adjusting such LIBOR Rate and the
method for determining the amount of such adjustment, or (z) repay the LIBOR Rate
Loans with respect to which such adjustment is made (together with any amounts due
under clause (b)(ii) above).
(ii) In the event that any change in market conditions or any law, regulation,
treaty, or directive, or any change therein or in the interpretation of application
thereof, shall at any time after the date hereof, in the reasonable opinion of any
Lender, make it unlawful or impractical for such Lender to fund or maintain LIBOR
Advances or to continue such funding or maintaining, or to determine or charge
interest rates at the LIBOR Rate, such Lender shall give notice of such changed
circumstances to Agent and Borrower and Agent promptly shall transmit the notice to
each other Lender and (y) in the case of any LIBOR Rate Loans of such Lender that
are outstanding, the date specified in such Lenders notice shall be deemed to be
the last day of the Interest Period of such LIBOR Rate Loans, and interest upon the
LIBOR Rate Loans of such Lender thereafter shall accrue interest at the rate then
applicable to Base Rate Loans, and (z) Borrower shall not be entitled to elect the
LIBOR Option until such Lender determines that it would no longer be unlawful or
impractical to do so.
(e)
No Requirement of Matched Funding
. Anything to the contrary contained
herein notwithstanding, neither Agent, nor any Lender, nor any of their Participants, is
required actually to acquire eurodollar deposits to fund or otherwise match fund any
Obligation as to which interest accrues at the LIBOR Rate. The provisions of this Section
shall apply as if each Lender or its Participants had match funded any Obligation as to
which interest is accruing at the LIBOR Rate by acquiring eurodollar deposits for each
Interest Period in the amount of the LIBOR Rate Loans.
2.14.
Capital Requirements
. If, after the date hereof, any Lender determines that (i)
the adoption of or change in any law, rule, regulation or guideline regarding capital requirements
for banks or bank holding companies, or any change in the interpretation or application thereof by
any Governmental Authority charged with the administration thereof, or (ii) compliance by such
Lender or its parent bank holding company with any guideline, request or directive of any such
entity regarding capital adequacy (whether or not having the force of law), has the effect of
reducing the return on such Lenders or such holding companys capital as a consequence of such
Lenders Commitments hereunder to a level below that which such Lender or such holding company
could have achieved but for such adoption, change, or compliance (taking into consideration such
Lenders or such holding companys then existing policies with respect to capital adequacy and
assuming the full utilization of such entitys capital) by any amount
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deemed by such Lender to be material, then such Lender may notify Borrower and Agent thereof.
Following receipt of such notice, Borrower agrees to pay such Lender on demand the amount of such
reduction of return of capital as and when such reduction is determined, payable within 90 days
after presentation by such Lender of a statement in the amount and setting forth in reasonable
detail such Lenders calculation thereof and the assumptions upon which such calculation was based
(which statement shall be deemed true and correct absent manifest error). In determining such
amount, such Lender may use any reasonable averaging and attribution methods.
2.15.
Intentionally Deleted
.
2.16.
Borrowing Base
.
(a)
Determination of the Borrowing Base
. During the period from the date
hereof to the date of the next determination of the Borrowing Base pursuant to the further
provisions of this
Section 2.16
, the initial amount of the Borrowing Base will be an
amount set by the Agent on the date hereof and acknowledged by the Borrower (the
Initial
Borrowing Base
).
(b)
Annual Scheduled Determinations of the Borrowing Base
. Promptly after July
1 of each calendar year (commencing July 1, 2008), and in any event prior to September 1 of
each calendar year, the Borrower shall furnish to Lenders a report in form and substance
satisfactory to Lenders, prepared by an Approved Engineer, which report shall be dated as of
July 1 of such calendar year and shall set forth the oil and gas reserves attributable to
the Borrowing Base Properties, and a projection of the rate of production and net operating
income with respect thereto, as of such date, together with additional data concerning
pricing, hedging, operating costs, quantities and purchasers of production, and other
information and engineering and geological data as the Agent may reasonably request. Within
thirty (30) days after receipt of such report and information and its review and approval by
Agent, Agent shall make a recommendation of the amount of credit available to Borrower
hereunder (a
Recommended Borrowing Base Determination
). Agent and the Required Lenders
shall approve or reject Agents Recommended Borrowing Base Determination within ten (10)
Business Days of Agents notification of the Recommended Borrowing Base Determination. If
Agent and the Required Lenders fail to approve any such determination of the Borrowing Base
made by Agent hereunder in such ten-Business Day period, then Agent shall poll all Lenders,
and the Borrowing Base shall be set at the highest amount on which Agent and the Required
Lenders can agree, it being understood that a Lender is deemed to have agreed to any and all
amounts that are lower than the amount actually determined by such Lender to be the
appropriate value of the Borrowing Base. Upon approval or deemed approval by Agent and the
Required Lenders, or all Lenders, as the case may be, of the amount of credit to be made
available to Borrower hereunder, Agent shall, by written notice to Borrower and Lenders,
designate the new Borrowing Base available to Borrower. Notwithstanding anything contained
herein to the contrary, no Lender shall be obligated to increase its Commitment without its
consent.
(c)
Semi-Annual Scheduled Determination of the Borrowing Base
. In addition,
promptly after January 1 of each calendar year (commencing January 1, 2008), and in any
event prior to March 1st of each calendar year, the Borrower shall furnish to Lenders a
report in form and substance satisfactory to Lenders, prepared (i) prior to the occurrence
of an Event of Default, by the Borrowers petroleum engineers and (ii) after the occurrence
of an Event of Default, by an Approved Engineer, and, in either case, reviewed and approved
by Agent, which report shall be dated as of January 1 of such calendar year and shall set
forth the oil and gas reserves attributable to the Borrowing Base Properties, and a
projection of the rate of production and net operating income with respect thereto, as of
such date, together with additional data concerning pricing,
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hedging, operating costs, quantities and purchasers of production, and other
information and engineering and geological data as the Agent may reasonably request. Within
thirty (30) days after receipt of such report and information and its review and approval by
Agent, Agent shall make a recommendation of the amount of credit available to Borrower
hereunder (a
Recommended Borrowing Base Determination
). Agent and the Required Lenders
shall approve or reject Agents Recommended Borrowing Base Determination within ten (10)
Business Days of Agents notification of the Recommended Borrowing Base Determination. If
Agent and the Required Lenders fail to approve any such determination of the Borrowing Base
made by Agent hereunder in such ten-Business Day period, then Agent shall poll all Lenders,
and the Borrowing Base shall be set at the highest amount on which Agent and the Required
Lenders can agree, it being understood that a Lender is deemed to have agreed to any and all
amounts that are lower than the amount actually determined by such Lender to be the
appropriate value of the Borrowing Base. Upon approval or deemed approval by Agent and the
Required Lenders, or all Lenders, as the case may be, of the amount of credit to be made
available to Borrower hereunder, Agent shall, by written notice to Borrower and Lenders,
designate the new Borrowing Base available to Borrower. Notwithstanding anything contained
herein to the contrary, no Lender shall be obligated to increase its Commitment without its
consent.
(d)
Discretionary Determination of the Borrowing Base
. Agent and the Required
Lenders shall have the right to redetermine the Borrowing Base at any time that Agent and
the Required Lenders, in their sole discretion, believe that there has been an adverse
change in the market condition of the Energy Business or in the condition (financial or
otherwise) or operations of the Borrower and its Subsidiaries. If Agent and the Required
Lenders shall elect to make a discretionary redetermination of the Borrowing Base pursuant
to the provisions of this
Section 2.16(d)
, the Borrower shall within thirty (30)
days of receipt of a request therefor from Agent and the Required Lenders, deliver to
Lenders such updated engineering, production, operating, and other data as the Agent or any
Lender may reasonably request. Agent and the Required Lenders shall approve and designate
the new Borrowing Base in accordance with the procedures and standards described in
Section 2.
16(b)
and
(g)
.
(e)
Exclusions
. Agent and the Required Lenders may exclude any oil and gas
reserves or portion of production therefrom or any income from any other Property from the
Borrowing Base, at any time, because title information is not reasonably satisfactory or
such oil and gas reserves are not Mortgaged Properties.
(f)
Quarterly Adjustments
. In addition to the re-determination of the
Borrowing Base as provided above, the valuation of the oil and gas reserves set forth in the
most recent Reserve Report shall be adjusted quarterly by Lenders, based upon the quarterly
pricing report provided by the Borrower to Agent, pursuant to
Section 6.2
, such
revaluation to be made by Agent and the Required Lenders within five (5) Business Days of
its receipt of each such report, and Agent shall promptly notify in writing the Borrower of
the revalued Borrowing Base.
(g)
General Provisions With Respect to the Borrowing Base
. The determination
of the Borrowing Base shall be made by Agent and the Required Lenders taking into
consideration the PV-10 Value of the Eligible Proved Developed Producing Reserves of the
Pledging Subsidiaries and the Eligible Proved Developed Producing Reserves of the
Partnerships and the LLC as reflected in the most recent Reserve Report or other report or
information provided under this Agreement, and any other relevant information obtained by or
delivered to the Agent and the Lender Group, all in accordance with the provisions of this
Section 2.16
, together with such other credit factors (including, without
limitation, the assets, liabilities, cash flow, hedged and unhedged exposure to price, and
interest rate changes, business, properties,
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prospects, management, and ownership of Borrower, its Subsidiaries, the LLC, or the
Partnerships) as each Lender in its discretion deems significant.
2.17.
Noteless Agreement
. No promissory notes shall evidence the payment obligations
of any Advances or the Term Loan to Borrower. Agent shall maintain in accordance with its usual
practice an account or accounts on its books evidencing the obligations of Borrower resulting from
the Term Loan and each Advance made by Agent from time to time, including the amounts of principal
and interest payable and paid to Lender hereunder. The entries maintained in said accounts shall
be prima facie evidence of the existence and amounts of the Term Loan and the Advances made by
Agent and the payment obligations of Borrower;
provided
,
however
, that the failure
of Agent to maintain such accounts or any error therein shall not in any manner affect the
obligation of Borrower to repay the Advances and the Term Loan.
3. CONDITIONS; TERMS OF AGREEMENT.
3.1.
Conditions Precedent to the Extension of Credit
. The obligation of the Lender
Group (or any member thereof) to make the extension of credit provided for hereunder is subject to
the fulfillment, to the satisfaction of Agent and each Lender, of each of the following of the
conditions precedent:
(a) Agent shall have received each of the following documents, in form and substance
satisfactory to Agent, duly executed, and each such document shall be in full force and
effect:
(i) the Contribution Agreement,
(ii) the Disbursement Letter,
(iii) the Fee Letter,
(iv) the Officers Certificate,
(v) the Borrowers Security Agreement,
(vi) the Intercompany Notes, and
(vii) Subordination Agreements, as may be required by Agent;
(b) Agent shall have received (i) counterparts of duly executed Mortgages and/or
Mortgage Supplements encumbering Oil and Gas Properties of the Pledging Subsidiaries
constituting at least 80% of the Total Proved Developed Producing Reserves of the Pledging
Subsidiaries to which value is given in the determination of the Initial Borrowing Base duly
executed on behalf of each record owner of such Oil and Gas Properties and evidence of the
completion (or satisfactory arrangements for the completion) of all recordings and filings
of such Mortgage(s) as may be necessary or, in the reasonable opinion of the Agent,
desirable effectively to create a valid, perfected first priority Lien against the Oil and
Gas Properties purported to be covered thereby, except as a result of a Permitted Lien; and
(ii) duly executed Partnership Pledge Agreements and LLC Pledge Agreement assigning to
Agent, and granting to Agent a first perfected priority security interest in, partnership
interests in Partnerships and the membership interests in the LLC having Oil and Gas
Properties constituting at least 80% the Total Proved Developed Producing Reserves of the
Partnerships to which value is given in the determination of
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the Initial Borrowing Base and evidence of the completion of all recordings and filings
of such create valid, perfected first priority Liens in such partnership interests;
(c) Agent shall have received counterparts of duly executed Mortgages encumbering the
Gathering Systems duly executed and delivered by each Subsidiary and/or Affiliate of
Borrower owning the Gathering Systems or any part thereof and evidence of the completion (or
satisfactory arrangement for the completion) of all recordings and filings of such
Mortgage(s) as may be necessary or in the reasonable opinion of the Agent, desirable
effectively to create a valid, perfected first priority Lien on the Gathering Systems;
(d) Borrower shall have delivered a certificate to Agent demonstrating, in form and
substance satisfactory to Agent, a Collateral Value Amount equal to or in excess of
$300,000,000.00.
(e) The Borrowing Base Properties, the Gathering Systems, and the other Collateral
shall be free and clear of all Liens, except Permitted Liens. All filings, notices,
recordings and other action necessary to perfect the Liens in the Collateral shall have been
made, given or accomplished or arrangements for the completion thereof satisfactory to the
Agent and its counsel shall have been made;
(f) Agent shall have received copies of all Governmental Approvals and third party
consents and approvals necessary or, in the sole discretion of the Agent, advisable in
connection with (i) the mortgaging and pledging of the Mortgaged Properties, and the other
Collateral, (ii) the pledging of the partnership interests in the Partnerships, (iii) the
pledging of the membership interests in the LLC and (iv) the operations of the Borrower, its
Subsidiaries, the LLC and the Partnerships. All such Governmental Approvals and third party
consents and approvals shall be in full force and effect;
(g) Agent and Lenders shall have received certificates, dated on or about the date
hereof, from the Borrowers insurers certifying (i) compliance with all of the insurance
required by
Section 6.8
hereof and by the Security Documents and (ii) that such
insurance is in full force and effect;
(h) Agent and Lenders shall have received and shall be satisfied with the contents,
results and scope of the most recently delivered Reserve Report;
(i) To the extent not previously provided, Borrower shall have delivered to the Agent
copies of all Hedging Agreements currently in existence to which Borrower or any of its
Subsidiaries is a party;
(j) Agent shall have completed and be satisfied with the results of a review of the
Borrowing Base Properties and the other Collateral and the status of the title of the
Borrowing Base Properties;
(k) Agent shall have received a certificate from the Secretary of Borrower and each of
its Subsidiaries: (i) attesting to the resolutions of its Board of Directors authorizing
its execution, delivery, and performance of this Agreement and the other Loan Documents to
which it is a party, (ii) authorizing specific officers of such party to execute the same,
and (iii) attesting to the incumbency and signatures of its specific officers;
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(l) Agent shall have received copies of the Governing Documents of Borrower, each of
its Subsidiaries, the LLC and the Partnerships, as amended, modified, or supplemented to the
date hereof, certified by an appropriate officer of each such entity;
(m) Agent shall have received a certificate of status with respect to Borrower, each of
its Subsidiaries, the LLC and the Partnerships, dated within 10 days of the date hereof,
such certificate to be issued by the appropriate officer of the jurisdiction of organization
of such entity, which certificate shall indicate that such entity is in good standing in
such jurisdiction;
(n) Agent shall have received certificates of status with respect to Borrower, each of
its Subsidiaries, the LLC and the Partnerships, each dated within 30 days of the date
hereof, such certificates to be issued by the appropriate officer of the jurisdictions
(other than the jurisdiction of organization of such entity) in which its failure to be duly
qualified or licensed would constitute a Material Adverse Change, which certificates shall
indicate that such entity is in good standing in such jurisdictions;
(o) Agent shall have received such updated certificates of insurance as Agent may
reasonably require;
(p) Agent shall have received opinions of Borrowers counsel in form and substance
satisfactory to Lender;
(q) Agent shall have received satisfactory evidence (including a certificate of the
chief financial officer of Borrower) that all tax returns required to be filed by Borrower,
each of its Subsidiaries, the LLC and the Partnerships have been timely filed and all taxes
upon Borrower, its Subsidiaries, the LLC and the Partnerships or their respective
properties, assets, income, and franchises (including Real Property taxes, sales taxes and
payroll taxes) have been paid prior to delinquency, except such taxes that are the subject
of a Permitted Protest;
(r) Borrower shall pay all Lender Group Expenses incurred in connection with the
transactions evidenced by this Agreement;
(s) Borrower shall have received all licenses, approvals or evidence of other actions
required by any Person or Governmental Authority in connection with the execution and
delivery by Borrower and its Subsidiaries of this Agreement or any other Loan Document or
with the consummation of the transactions contemplated hereby and thereby; and
(t) All other documents and legal matters in connection with the transactions
contemplated by this Agreement shall have been delivered, executed, or recorded and shall be
in form and substance satisfactory to Agent and its counsel.
3.2.
Intentionally Deleted
.
3.3.
Conditions Precedent to all Extensions of Credit
. The obligation of the Lender
Group (or any member thereof) to make any Advances (or to extend any other credit hereunder) shall
be subject to the following conditions precedent:
(a) the representations and warranties contained in this Agreement and the other Loan
Documents shall be true and correct in all material respects on and as of the date of such
extension of credit, as though made on and as of such date (except to the extent that such
representations and warranties relate solely to an earlier date);
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(b) no Default or Event of Default shall have occurred and be continuing on the date of
such extension of credit, nor shall either result from the making thereof;
(c) no injunction, writ, restraining order, or other order of any nature prohibiting,
directly or indirectly, the extending of such credit shall have been issued and remain in
force by any Governmental Authority against Borrower, Agent, any Lender, or any of their
Affiliates; and
(d) no Material Adverse Change shall have occurred.
3.4.
Term
. This Agreement shall become effective upon the execution and delivery
hereof by Borrower, Agent and Lenders and shall continue in full force and effect for a term ending
on July 10, 2012 (the
Maturity Date
). The foregoing notwithstanding, the Lender Group, upon the
election of the Required Lenders, shall have the right to terminate its obligations under this
Agreement immediately and without notice upon the occurrence and during the continuation of an
Event of Default.
3.5.
Effect of Termination
. On the date of termination of this Agreement, all
Obligations (including contingent reimbursement obligations of Borrower with respect to any
outstanding Letters of Credit and including all Bank Products Obligations) immediately shall become
due and payable without notice or demand (including (a) either (i) providing cash collateral to be
held by Agent for the benefit of those Lenders with a Revolver Commitment in an amount equal to
105% of the then extant Letter of Credit Usage, or (ii) causing the original Letters of Credit to
be returned to Issuing Lender, and (b) providing cash collateral (in an amount determined by Agent
as sufficient to satisfy the reasonably estimated credit exposure) to be held by Agent for the
benefit of the Bank Product Providers with respect to the then extant Bank Products Obligations).
No termination of this Agreement, however, shall relieve or discharge Borrower of its duties,
Obligations, or covenants hereunder and the Agents Liens in the Collateral shall remain in effect
until all Obligations have been fully and finally discharged and the Lender Groups obligations to
provide additional credit hereunder have been terminated. When this Agreement has been terminated
and all of the Obligations have been fully and finally discharged and the Lender Groups
obligations to provide additional credit under the Loan Documents have been terminated irrevocably,
Agent will, at Borrowers sole expense, execute and deliver any UCC termination statements, lien
releases, mortgage releases, re-assignments of trademarks, discharges of security interests, and
other similar discharge or release documents (and, if applicable, in recordable form) as are
reasonably necessary to release, as of record, the Agents Liens and all notices of security
interests and liens previously filed by Agent with respect to the Obligations.
3.6.
Early Termination by Borrower
. Borrower has the option, at any time upon 90 days
prior written notice by Borrower to Agent, to terminate this Agreement by paying to Agent, for the
benefit of the Lender Group, in cash, the Obligations (including (a) either (i) providing cash
collateral to be held by Agent for the benefit of those Lenders with a Revolver Commitment in an
amount equal to 105% of the then extant Letter of Credit Usage, or (ii) causing the original
Letters of Credit to be returned to Issuing Lender in full, and (b) providing cash collateral (in
an amount determined by Agent as sufficient to satisfy the reasonably estimated credit exposure) to
be held by Agent for the benefit of the Bank Product Providers with respect to the then extant Bank
Products Obligations), in full, together with, in the absence of a Non-Prepayment Premium Event,
the Applicable Prepayment Premium (to be allocated based upon letter agreements between Agent and
individual Lenders). If Borrower has sent a notice of termination pursuant to the provisions of
this Section, then the Commitments shall terminate and Borrower shall be obligated to repay the
Obligations (including (a) either (i) providing cash collateral to be held by Agent for the benefit
of those Lenders with a Revolver Commitment in an amount equal to 105% of the then extant Letter of
Credit Usage, or (ii) causing the original Letters of Credit to be returned to the Issuing Lender,
in full, and (b) providing cash collateral (in an amount determined by Agent as sufficient to
satisfy the reasonably estimated credit exposure) to be held by Agent for the benefit of the
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Bank Product Providers with respect to the then extant Bank Products Obligations), in full,
together with, in the absence of a Non-Prepayment Premium Event, the Applicable Prepayment Premium,
on the date set forth as the date of termination of this Agreement in such notice. In the event of
the termination of this Agreement and repayment of the Obligations at any time prior to the
Maturity Date, for any other reason, including (a) termination upon the election of the Required
Lenders to terminate after the occurrence and during the continuation of an Event of Default, (b)
foreclosure and sale of Collateral, (c) sale of the Collateral in any Insolvency Proceeding, or (d)
restructure, reorganization or compromise of the Obligations by the confirmation of a plan of
reorganization, or any other plan of compromise, restructure, or arrangement in any Insolvency
Proceeding, then, in view of the impracticability and extreme difficulty of ascertaining the actual
amount of damages to the Lender Group or profits lost by the Lender Group as a result of such early
termination, and by mutual agreement of the parties as to a reasonable estimation and calculation
of the lost profits or damages of the Lender Group, Borrower shall pay the Applicable Prepayment
Premium to Agent (to be allocated based upon letter agreements between Agent and individual
Lenders), measured as of the date of such termination;
provided
,
however
, the
Lender Group waives the Applicable Prepayment Premium in the event such early termination results
from a financing provided by Wells Fargo Bank, N.A., or any of its affiliates.
4. INTENTIONALLY DELETED.
5. REPRESENTATIONS AND WARRANTIES.
In order to induce the Lender Group to enter into this Agreement, Borrower makes the following
representations and warranties to the Lender Group which shall be true, correct, and complete, in
all material respects, as of the date hereof, and shall be true, correct, and complete, in all
material respects, as of the date hereof, and at and as of the date of the making of each Advance
(or other extension of credit) made thereafter, as though made on and as of the date of such
Advance (or other extension of credit) (except to the extent that such representations and
warranties relate solely to an earlier date) and such representations and warranties shall survive
the execution and delivery of this Agreement:
5.1.
No Encumbrances
. Borrower, Pledging Subsidiaries, the LLC, and the Partnerships
have good, valid and indefeasible title to its Collateral, free and clear of Liens except for
Permitted Liens, including but not limited to:
(a) the Borrowing Base Properties and the working interests and the net revenue
interests with respect thereto listed on
Schedule 5.1(a)
; and
(b) all rights under the Material Contracts listed on
Schedule 5.1(b)
.
5.2.
Intentionally Deleted
.
5.3.
Intentionally Deleted
.
5.4.
Intentionally Deleted
.
5.5.
Intentionally Deleted
.
5.6.
Intentionally Deleted
.
5.7.
Location of Chief Executive Office; FEIN
. The chief executive office of Borrower
and its Subsidiaries is located at the address indicated in
Schedule 5.7
, and the FEIN for
Borrower and each of its Subsidiaries is identified in
Schedule 5.7
.
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5.8.
Due Organization and Qualification; Subsidiaries
.
(a) Borrower and each of its Subsidiaries is duly organized and existing and in good
standing under the laws of the jurisdiction of its organization and qualified to do business
in each state where the failure to be so qualified reasonably could be expected to have a
Material Adverse Change.
(b) Set forth on
Schedule 5.8(b)
, is a complete and accurate description of the
authorized capital Stock of Borrower, by class, and, as of the date hereof, a description of
the number of shares of each such class that are issued and outstanding. Other than as
described on
Schedule 5.8(b)
, there are no subscriptions, options, warrants, or
calls relating to any shares of Borrowers capital Stock, including any right of conversion
or exchange under any outstanding security or other instrument. Borrower is not subject to
any obligation (contingent or otherwise) to repurchase or otherwise acquire or retire any
shares of its capital Stock or any security convertible into or exchangeable for any of its
capital Stock.
(c) Set forth on
Schedule 5.8(c)
, is a complete and accurate list of Borrowers
direct and indirect Subsidiaries, showing: (i) the jurisdiction of their organization; (ii)
the number of shares of each class of common and preferred Stock authorized for each of such
Subsidiaries; (iii) the number and the percentage of the outstanding shares of each such
class owned directly or indirectly by Borrower; and (iv) which Subsidiaries have been
designated as Unrestricted Subsidiaries. All of the outstanding capital Stock of each such
Subsidiary has been validly issued and is fully paid and non-assessable.
(d) Except as set forth on
Schedule 5.8(c)
, there are no subscriptions,
options, warrants, or calls relating to any shares of Borrowers Subsidiaries capital
Stock, including any right of conversion or exchange under any outstanding security or other
instrument. Neither Borrower nor any of its Subsidiaries is subject to any obligation
(contingent or otherwise) to repurchase or otherwise acquire or retire any shares of any
capital Stock or any security convertible into or exchangeable for any such capital Stock.
5.9.
Due Authorization; No Conflict
.
(a) The execution, delivery, and performance by Borrower of this Agreement and by
Borrower and each of its Subsidiaries of the other Loan Documents to which it is a party
have been duly authorized by all necessary action on the part of Borrower and its
Subsidiaries.
(b) The execution, delivery, and performance by Borrower and each of its Subsidiaries
of this Agreement and the Loan Documents to which it is a party do not and will not (i)
violate any provision of federal, state, or local law or regulation applicable to Borrower
or any of its Subsidiaries, the Governing Documents of Borrower or any of its Subsidiaries,
or any order, judgment, or decree of any court or other Governmental Authority binding on
Borrower or any of its Subsidiaries, (ii) conflict with, result in a breach of, or
constitute (with due notice or lapse of time or both) a default under any material
contractual obligation of Borrower or any of its Subsidiaries, (iii) result in or require
the creation or imposition of any Lien of any nature whatsoever upon any properties or
assets of Borrower or any of its Subsidiaries, other than Permitted Liens, or (iv) require
any approval of interestholders of Borrower or any of its Subsidiaries or any approval or
consent of any Person under any material contractual obligation of Borrower or any of its
Subsidiaries.
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(c) Other than the filing of financing statements, fixture filings, and the recordation
of the Mortgages, the execution, delivery, and performance by Borrower and each of its
Subsidiaries of this Agreement and the other Loan Documents to which it is a party do not
and will not require any registration with, consent, or approval of, or notice to, or other
action with or by, any Governmental Authority or other Person.
(d) This Agreement and the other Loan Documents to which Borrower and each of its
Subsidiaries is a party, and all other documents contemplated hereby and thereby, when
executed and delivered by Borrower and each of its Subsidiaries will be the legally valid
and binding obligations of Borrower and its Subsidiaries, enforceable against Borrower and
each such Subsidiary in accordance with their respective terms, except as enforcement may be
limited by equitable principles or by bankruptcy, insolvency, reorganization, moratorium, or
similar laws relating to or limiting creditors rights generally.
(e) The Agents Liens are validly created, perfected, and first priority Liens, subject
only to Permitted Liens.
5.10.
Litigation
. Other than those matters disclosed on
Schedule 5.10
, there
are no actions, suits, or proceedings pending or, to the best knowledge of Borrower, threatened
against Borrower, any of its Subsidiaries, the LLC or any Partnership except for (a) matters that
are fully covered by insurance (subject to customary deductibles), and (b) matters arising after
the date hereof that, if decided adversely to Borrower, any of its Subsidiaries, the LLC or any
Partnership, as applicable, reasonably could not be expected to result in a Material Adverse
Change.
5.11.
No Material Adverse Change
. All financial statements relating to Borrower and
its Subsidiaries that have been delivered by Borrower to Agent and the Lenders have been prepared
in accordance with GAAP (except, in the case of unaudited financial statements, for the lack of
footnotes and schedules and being subject to year-end audit adjustments) and present fairly in all
material respects, the financial condition of Borrower and its Subsidiaries as of the date thereof
and results of operations for the period then ended. There has not been a Material Adverse Change
with respect to Borrower and its Subsidiaries taken as a whole since the date of the latest
financial statements submitted to the Lender Group on or before the date hereof.
5.12.
Fraudulent Transfer
.
(a) Borrower and each of the Pledging Subsidiaries is Solvent.
(b) The value of all properties of each of Borrower and the Pledging Subsidiaries at
their present fair saleable value on a going concern basis (i.e., the amount that may be
realized within a reasonable time, considered to be six months to one year, either through
collection or sale at the regular market value, conceiving the latter as the amount that
could be obtained for such properties within such period by a capable and diligent
businessman from an interested buyer who is willing to purchase under ordinary selling
conditions), exceeds the amount of all its debts and liabilities (including contingent,
subordinated, unmatured and unliquidated liabilities);
(c) Neither Borrower nor any of the Pledging Subsidiaries has unreasonably small
capital with which to conduct its business operations as heretofore conducted;
(d) Each of Borrower and the Pledging Subsidiaries has sufficient cash flow to enable
it to pay its debts as they mature; and
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(e) No transfer of property is being made by Borrower or any of the Pledging
Subsidiaries and no obligation is being incurred by Borrower or any of the Pledging
Subsidiaries in connection with the transactions contemplated by this Agreement or the other
Loan Documents with the intent to hinder, delay, or defraud either present or future
creditors of Borrower or any of the Pledging Subsidiaries.
5.13.
Employee Benefits
. Neither Borrower, nor any of its Subsidiaries, or any of
their ERISA Affiliates maintains or contributes to any Benefit Plan.
5.14.
Environmental Condition
. Except as set forth on
Schedule 5.14
, (a) to
Borrowers knowledge, none of the properties or assets of Borrower or any of its Subsidiaries has
ever been used by Borrower or any of its Subsidiaries or by previous owners or operators in the
disposal of, or to produce, store, handle, treat, release, or transport, any Hazardous Materials,
where such use, production, storage, handling, treatment, release or transport was in violation, in
any material respect, of applicable Environmental Law, (b) to Borrowers knowledge, none of the
properties or assets of Borrower or any of its Subsidiaries has ever been designated or identified
in any manner pursuant to any environmental protection statute as a Hazardous Materials disposal
site, (c) neither Borrower nor any of its Subsidiaries has received notice that a Lien arising
under any Environmental Law has attached to any revenues or to any Real Property or Oil and Gas
Properties owned or operated by Borrower or any of its Subsidiaries, and (d) neither Borrower nor
any of its Subsidiaries has received a summons, citation, notice, or directive from the United
States Environmental Protection Agency or any other federal or state governmental agency concerning
any action or omission by Borrower or any of its Subsidiaries resulting in the releasing or
disposing of Hazardous Materials into the environment.
5.15.
Brokerage Fees
. Neither Borrower nor any of its Subsidiaries has utilized the
services of any broker or finder in connection with Borrowers obtaining financing from the Lender
Group under this Agreement and no brokerage commission or finders fee is payable by Borrower or any
of its Subsidiaries in connection herewith.
5.16.
Intellectual Property
. Borrower and each of its Subsidiaries owns, or holds
licenses in, all trademarks, trade names, copyrights, patents, patent rights, and licenses that are
necessary to the conduct of its business as currently conducted. Attached hereto as
Schedule
5.16
is a true, correct, and complete listing of all material patents, patent applications,
trademarks, trademark applications, copyrights, and copyright registrations as to which Borrower or
any of its Subsidiaries is the owner or is an exclusive licensee.
5.17.
Leases
. Borrower and its Subsidiaries enjoy peaceful and undisturbed possession
under all leases material to the business of Borrower and its Subsidiaries and to which Borrower or
any of its Subsidiaries is a party or under which Borrower and its Subsidiaries are operating. All
of such leases are valid and subsisting and no material default by Borrower or any of its
Subsidiaries exists under any of them.
5.18.
DDAs
. Set forth on
Schedule 5.18
are all of the DDAs of Borrower and
its Subsidiaries, including, with respect to each depository (i) the name and address of such
depository, and (ii) the account numbers of the accounts maintained with such depository.
5.19.
Complete Disclosure
. All factual information (taken as a whole) furnished by or
on behalf of Borrower and its Subsidiaries in writing to Agent or any Lender (including all
information contained in the Schedules hereto or in the other Loan Documents) for purposes of or in
connection with this Agreement, the other Loan Documents or any transaction contemplated herein or
therein is, and all other such factual information (taken as a whole) hereafter furnished by or on
behalf of Borrower and its
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Subsidiaries in writing to the Agent or any Lender will be, true and accurate, in all material
respects, on the date as of which such information is dated or certified and not incomplete by
omitting to state any fact necessary to make such information (taken as a whole) not misleading in
any material respect at such time in light of the circumstances under which such information was
provided. On the date hereof, the Projections represent, and as of the date on which any other
Projections are delivered to Agent, such additional Projections represent Borrowers good faith
best estimate of the future performance of Borrower and its Subsidiaries for the periods covered
thereby.
5.20.
Permitted Indebtedness
. Set forth on
Schedule 5.20
is a true and
complete list of all Indebtedness of Borrower and its Subsidiaries outstanding immediately prior to
the date hereof that is to remain outstanding after the date hereof and such Schedule accurately
reflects the aggregate principal amount of such Indebtedness and the principal terms thereof.
5.21.
Investment and Holding Company Status
. Neither Borrower nor any of its
Subsidiaries is (a) an investment company as defined in, or subject to regulation under, the
Investment Company Act of 1940, as amended, or (b) a holding company, or a subsidiary company
of a holding company, or an affiliate of a holding company or of a subsidiary company of a
holding company as defined in, or subject to regulation under, the Public Utility Holding Company
Act of 1935, as amended.
5.22.
Taxes
. Except as set forth in
Schedule 5.22
, Borrower and each of its
Subsidiaries has timely filed or caused to be filed all Tax returns and reports required to have
been filed and has paid or caused to be paid all Taxes required to have been paid by it, except (a)
Taxes that are being contested in good faith by appropriate proceedings and for which Borrower has
set aside on its books adequate reserves or (b) to the extent that the failure to do so could not
reasonably be expected to result in a Material Adverse Change.
5.23.
Insurance
.
Schedule 5.23
sets forth a description of all insurance
maintained by or on behalf of Borrower and its Subsidiaries as of the date hereof. As of the date
hereof, all premiums in respect of such insurance have been paid.
5.24.
Labor Matters
. As of the date hereof, there are no strikes, lockouts or
slowdowns against Borrower and its Subsidiaries pending or, to the knowledge of Borrower and its
Subsidiaries, threatened. The hours worked by and payments made to employees of Borrower and its
Subsidiaries have not been in material violation of the Fair Labor Standards Act or any other
applicable Federal, state, local or foreign law dealing with such matters. All payments due from
Borrower and its Subsidiaries, or for which any claim may be made against Borrower or any of its
Subsidiaries, on account of wages and employee health and welfare insurance and other benefits,
have been paid or accrued as a liability on the books of Borrower and its Subsidiaries.
5.25.
Claims and Liabilities
. Except as disclosed in
Schedule 5.25
, neither
Borrower nor any of its Subsidiaries nor any of the Partnerships nor the LLC has accrued any
liabilities under gas purchase contracts for gas not taken, but for which it is liable to pay if
not made up and which, if not paid, would result in a Material Adverse Change. Except as disclosed
in
Schedule 5.25
, no claims exist against Borrower, any of its Subsidiaries, the LLC or any
of the Partnerships for gas imbalances which claims if adversely determined could result in a
Material Adverse Change. No purchaser of product supplied by Borrower, any of its Subsidiaries,
the LLC or any of the Partnerships has any claim against Borrower, any of its Subsidiaries, the LLC
or any of the Partnerships for product paid for, but for which delivery was not taken as and when
paid for, which claim if adversely determined could result in a Material Adverse Change.
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5.26.
Borrowing Base Properties
.
(a) Each of the Pledging Subsidiaries, the LLC, and each of the Partnerships has good
and indefeasible title to all its Borrowing Base Properties which are Hydrocarbon Interests
and good title to all its Borrowing Base Properties which are personal property, free and
clear of Liens (other than Permitted Liens). With respect to the Borrowing Base Properties
set forth on
Schedule 5.1(a)
, after giving full effect to the Permitted Liens, the
net revenue interest is no less than that designated for the Pledging Subsidiaries, the LLC,
and the Partnerships in and to such Borrowing Base Properties and the working interest is no
greater than as set forth for the Pledging Subsidiaries, the LLC, and the Partnerships in
and to such Borrowing Base Properties, and there are no back-in or reversionary
interests held by third parties which could reduce the net revenue interest or increase the
working interest of the Pledging Subsidiaries, the LLC, or the Partnerships in such
Borrowing Base Properties except as expressly set forth in
Schedule 5.1(a)
. All
wells drilled and Hydrocarbons produced with respect to the Borrowing Base Properties were
drilled and produced in compliance in all material respects with all applicable Governmental
Rules. All of the Borrowing Base Properties described in
Schedule 5.1(a)
, are
covered by the Initial Reserve Report and other reports which Borrower has previously
delivered to and which have been relied upon by Agent and Lenders in connection with this
Agreement and are covered by Mortgages or are owned by (i) Partnerships in which the
Pledging Subsidiaries have granted security interests to Agent pursuant to a Partnership
Pledge Agreement or (ii) by LLC in which A&W has granted a security interest to Agent
pursuant to the LLC Pledge Agreement. No bills are past due and do not give rise to a Lien
(other than Liens arising in the ordinary course of business for sums which are not yet due
and payable under customary agreements or arising by operation of law) and taxes have been
paid with respect to the Borrowing Base Properties other than those which are the subject of
a bona fide dispute which is being contested in good faith by the Pledging Subsidiaries, the
LLC, or the Partnerships by appropriate proceedings as to which a reserve is established in
an amount that is satisfactory to Agent (and if a Lien secures the same or may secure the
same, such Lien is subject to a Permitted Protest).
(b) All of the marketing arrangements of the Pledging Subsidiaries, the LLC, and the
Partnerships with respect to the Borrowing Base Properties are valid, enforceable and in
full force and effect. As of the date of this Agreement, there do not exist any cumulative
imbalances in gas production or receipt of take or pay payments except as disclosed as to
both existence and extent on
Schedule 5.26(b)
attached hereto.
(c) There has not been any Material Adverse Change in any of the Borrowing Base
Properties since the date of the most recent Reserve Report.
5.27.
Operations of Borrowing Base Properties
. A Pledging Subsidiary is the operator
of each of the Borrowing Base Properties except as set forth in
Schedule 5.27
.
5.28.
Hedging Agreement
.
Schedule 5.28
sets forth as of the date hereof, a
true and complete list of all Hedging Agreements (including commodity price swap agreements,
forward agreements or contracts of sale which provide for prepayment for deferred shipment or
delivery of oil, gas or other commodities) of Borrower and its Subsidiaries, the material terms
thereof (including the type, term, effective date, termination date, and notional amounts or
volumes), the net mark to market value thereof, all credit support agreements relating thereto
(including any margin required or supplied), and the counterpart to each such agreement. Borrower
has delivered true and correct copies of each of the Hedging Agreements to Agent prior to the date
of this Agreement.
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5.29.
Operating Costs
. As of the date hereof, all costs and expenses incurred in
connection with the operation of the Borrowing Base Properties have been fully paid and discharged
by the Pledging Subsidiaries, the LLC and the Partnerships, except (a) normal costs and expenses
incurred in operating such Borrowing Base Properties for which the Pledging Subsidiaries, the LLC
and the Partnerships have not yet been billed, (b) costs and expenses which are the subject of a
bona fide dispute which is being contested in good faith by the Pledging Subsidiaries, the LLC or
Partnerships by appropriate proceedings as to which a reserve is established on the books of such
Pledging Subsidiary, the LLC or such Partnerships in an amount that is satisfactory to Agent (and
if a Lien secures or may secure such obligation, such Lien is subject to a Permitted Protest).
5.30.
Leases
. The oil and gas leases, farm-out agreements, and other agreements
associated with the Borrowing Base Properties are in full force and effect in accordance with their
respective terms and there exist no material violations or defaults in the performance of any
obligation thereunder. Additionally, Borrower is not aware of any event that with notice or lapse
of time or both would constitute a material violation or default under any such oil and gas leases,
farm-out agreements, or other agreements.
5.31.
Material Contracts
. Set forth on
Schedule 5.1(b)
is a complete and
correct list of all Material Contracts in effect or to be in effect as of the date hereof.
Borrower has delivered to the Agent true and complete copies of each Material Contract, as each may
have been amended, that have been requested by the Agent. Each of the Material Contracts is in
full force and effect and no default exists under the terms of any of the Material Contracts.
5.32.
Intentionally Deleted
.
5.33.
Common Enterprise
. The successful operation and condition of each of the
Borrower, the Pledging Subsidiaries and the other Subsidiaries to which Borrower advances loans
pursuant to
Section 6.20
(the
Obligors
) is dependent on the continued successful
performance of the functions of the group of Obligors as a whole and the successful operation of
each of the Obligors is dependent on the successful performance and operation of each other
Obligor. Each Obligor expects to derive benefit (and its board of directors or other governing
body has determined that it may reasonably be expected to derive benefit), directly and indirectly,
from successful operations of each of the other Obligors. Each Obligor expects to derive benefit
(and the boards of directors or other governing body of each Obligor has determined that it may
reasonably be expected to derive benefit), directly and indirectly, from the credit extended by the
Lender Group to Borrower hereunder, both in their separate capacities and as members of the group
of companies. Each Obligor has determined that execution, delivery, and performance of this
Agreement and any other Loan Documents to be executed by such Obligor is within its purpose, will
be of direct and indirect benefit to such Obligor, and is in its best interest.
5.34.
Gathering Systems
. The Gathering Systems covered by the Mortgages grant to
Agent, for the benefit of Lenders, a perfected lien upon all transportation facilities necessary to
transport Hydrocarbons produced from the Wells included within the Mortgaged Properties to a
transit point for sale or transportation by a Person who is not an affiliate of Borrower or any of
its Subsidiaries.
6. AFFIRMATIVE COVENANTS.
Borrower covenants and agrees that, so long as any credit hereunder shall be available and
until full and final payment of the Obligations, Borrower shall do, and shall cause each of its
Subsidiaries to do, all of the following:
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6.1.
Accounting System
. Maintain a system of accounting that enables Borrower to
produce financial statements in accordance with GAAP and maintain records pertaining to the
Collateral that contain information as from time to time reasonably may be requested by Agent.
Borrower also shall maintain a joint interest billing and remittance system with respect to the Oil
and Gas Properties of Borrower, its Subsidiaries, the LLC and the Partnerships on which Borrower or
any of its Subsidiaries is the operator and other systems that enable Borrower to show, among other
things, the value, revenues and profits/losses of the Oil and Gas Properties of Borrower and its
Subsidiaries, volume of production, and value of sales of Hydrocarbon production, and positions and
liability exposure of Borrower and its Subsidiaries under the Hedging Agreements on a separate
company-by-company basis, as well as on a consolidated basis.
6.2.
Collateral Reporting
. Provide Agent (and if so requested by Agent, with copies
for each Lender) with the following documents at the following times in form satisfactory to Agent:
(a) by September 1st of each year, a Reserve Report prepared by an Approved Engineer
and reviewed and approved by Agent; and by March 1st of each year, a Reserve Report prepared
by Borrower or an Approved Engineer, as applicable, and reviewed and approved by Agent, all
in accordance with the terms of
Section 2.16
;
(b) with the delivery of each Reserve Report, Borrower shall provide to Agent, a
certificate from the president or chief financial officer of Borrower certifying that, to
the best of his knowledge: (i) the information contained in such Reserve Report and any
other information delivered in connection therewith is true and correct; (ii) each of the
Pledging Subsidiaries, the LLC and the Partnerships own good and defensible title to its
Borrowing Base Properties evaluated in such Reserve Report and are free of all Liens except
for Permitted Liens; (iii) except as set forth on an exhibit to the certificate, on a net
basis there are no gas imbalances, take or pay or other prepayments with respect to the
Borrowing Base Properties evaluated in such Reserve Report which would require the Pledging
Subsidiaries, the LLC or the Partnerships to deliver Hydrocarbons produced from such
Borrowing Base Properties at some future time without then or thereafter receiving full
payment therefor; (iv) none of the Borrowing Base Properties has been sold since the date of
the last Borrowing Base determination; (v) if requested by Agent, attached to the
certificate is a list of all Persons disbursing proceeds to Borrower, the Pledging
Subsidiaries, the LLC or the Partnerships from the Borrowing Base Properties; and (vi) set
forth on a schedule attached to the certificate is the PV-10 Value Reserve Report value of
all Borrowing Base Properties together with a list of the Wells that are owned by the
Partnerships and the LLC;
(c) as soon as available and in any event within 10 Business Days after the end of each
quarter-annual period, a report setting forth, in form substantially similar to the form set
forth on
Schedule 6.2(c)
, the calculation as of the last Business Day of the
quarter-annual period preceding the date of the delivery by the Borrower of such report, of
the Total Value as determined by the Reserve Report most recently delivered by the Borrower
under
Section 6.2(a)
, each such report shall be accompanied by a certificate of the
president or chief financial officer of Borrower certifying to the completeness and accuracy
of the report, including the calculation of the Total Value comprising the Borrowing Base
Properties;
(d) as soon as available and in any event within 30 days after the end of each month, a
report setting forth the amount of funds held for future distribution as of the close of
the month reported on as reflected in the monthly financial statements of Borrower, together
with a certificate from the president or chief financial officer of Borrower certifying that
Borrower and the Pledging Subsidiaries have paid and are current with respect to all
royalties, overriding
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royalties and operating expenses relating to the Borrowing Base Properties except for
those which are subject to a Permitted Protest;
(e) upon request by Agent from time to time, copies of lease files, well files and
contract files (including production reports on each Well, marketing contracts, and
information regarding locations of and equipment located on each Well) of each of the
Pledging Subsidiaries, the LLC and the Partnerships with respect to the Borrowing Base
Properties;
(f) such other information reports, statements, materials and data as to the wells
operated by the Pledging Subsidiaries, the LLC or the Partnerships or in which the Pledging
Subsidiaries, the LLC or Partnerships otherwise have an interest and the accounting and
billing procedures utilized by the Pledging Subsidiaries in connection with such wells as
shall be reasonably requested by Agent including, without limitation, relevant computer
programs, disks and tapes; and
(g) such other reports as to the Collateral or the business or financial condition of
Borrower, each of its Subsidiaries, the LLC and the Partnerships as Agent may reasonably
request from time to time.
6.3.
Financial Statements, Reports, Certificates
. Deliver to Agent, with copies to
each Lender:
(a) as soon as available, but in any event (i) prior to the occurrence of an Event of
Default, within 45 days after the end of each fiscal quarter of each fiscal year of Borrower
and (ii) after the occurrence of an Event of Default within 30 days after the end of each
calendar month:
(i) a company prepared consolidated balance sheet, income statement, and
statement of cash flow covering Borrower and its Subsidiaries operations during
such period,
(ii) a company prepared report detailing the aggregate amount of cash dividends
made by the Borrower from July 2002 through such period,
(iii) a company prepared report detailing the aggregate amount of common and
Class A stock of Borrower repurchased by Borrower during the immediately preceding
twelve month period,
(iv) a certificate signed by the chief financial officer of Borrower to the
effect that:
A. the financial statements and reports delivered hereunder have been
prepared in accordance with GAAP (except for the lack of footnotes and being
subject to year-end audit adjustments) and fairly present in all material
respects the financial condition of Borrower and its Subsidiaries,
B. the representations and warranties of Borrower and its Subsidiaries
contained in this Agreement and the other Loan Documents are true and
correct in all material respects on and as of the date of such certificate,
as though made on and as of such date (except to the extent that such
representations and warranties relate solely to an earlier date),
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C. there does not exist any condition or event that constitutes a
Default or Event of Default (or, to the extent of any non-compliance,
describing such non-compliance as to which he or she may have knowledge and
what action Borrower has taken, is taking, or proposes to take with respect
thereto), and
(v) a Compliance Certificate demonstrating, in reasonable detail, compliance at
the end of such period with the applicable financial covenants contained in
Section 7.20
,
(vi) a company prepared report (A) listing all of the Hedging Agreements of
Borrower, its Subsidiaries and Affiliates and (B) detailing the aggregate amount of
Hedging Obligations of Borrower, its Subsidiaries and Affiliates under the Hedging
Agreements,
(b) as soon as available, but in any event within 90 days after the end of each of
Borrowers fiscal years,
(i) financial statements of Borrower and its Subsidiaries for each such fiscal
year, audited by independent certified public accountants reasonably acceptable to
Agent and certified, without any qualifications, by such accountants to have been
prepared in accordance with GAAP (such audited financial statements to include a
balance sheet, income statement, and statement of cash flow and, if prepared, such
accountants letter to management),
(ii) a certificate of such accountants addressed to Agent and Lenders stating
that such accountants do not have knowledge of the existence of any Default or Event
of Default under
Section 7.20
,
(c) as soon as available, but in any event within 30 days prior to the start of each of
Borrowers fiscal years,
(i) copies of Borrowers Projections, in form and substance (including as to
scope and underlying assumptions) satisfactory to Agent, in its sole discretion, for
the forthcoming fiscal year, quarter by quarter, certified by the chief financial
officer of Borrower as being such officers good faith best estimate of the
financial performance of Borrower and its Subsidiaries during the period covered
thereby,
(d) if and when filed by Borrower,
(i) 10-Q quarterly reports, Form 10-K annual reports, and Form 8-K current
reports,
(ii) any other filings made by Borrower with the SEC,
(iii) copies of Borrowers federal income tax returns, and any amendments
thereto, filed with the Internal Revenue Service, and
(iv) any other information that is provided by Borrower to its shareholders
generally,
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(e) if and when filed by Borrower and as requested by Agent, satisfactory evidence of
payment of applicable excise taxes in each jurisdictions in which (i) Borrower or any of its
Subsidiaries conducts business or is required to pay any such excise tax, (ii) where the
failure by Borrower or any of its Subsidiaries to pay any such applicable excise tax would
result in a Lien on the properties or assets of Borrower, or (iii) where Borrowers failure
to pay any such applicable excise tax reasonably could be expected to result in a Material
Adverse Change,
(f) as soon as Borrower has knowledge of any event or condition that constitutes a
Default or an Event of Default, notice thereof and a statement of the curative action that
Borrower proposes to take with respect thereto, and
(g) upon the request of Agent, any other report reasonably requested relating to the
financial condition of Borrower and its Subsidiaries.
In addition to the financial statements referred to above, Borrower agrees to deliver
financial statements prepared on both a consolidated and consolidating basis and that no Subsidiary
of Borrower (other than Eastern Capital Corporation), will have a fiscal year different from that
of Borrower. Borrower agrees that its independent certified public accountants are authorized to
communicate with Agent and to release to Agent whatever financial information concerning Borrower
and its Subsidiaries that Agent reasonably may request. Borrower waives the right to assert a
confidential relationship, if any, it may have with any accounting firm or service bureau in
connection with any information requested by Agent pursuant to or in accordance with this
Agreement, and agrees that Agent may contact directly any such accounting firm or service bureau in
order to obtain such information.
6.4.
Intentionally Deleted
.
6.5.
Intentionally Deleted
.
6.6.
Maintenance of Properties
. Maintain and preserve all of its properties which are
necessary or useful in the proper conduct to its business in good working order and condition,
ordinary wear and tear excepted, and comply at all times with the provisions of all leases to which
it is a party as lessee, so as to prevent any loss or forfeiture thereof or thereunder.
6.7.
Taxes
. Cause all assessments and taxes, whether real, personal, or otherwise,
due or payable by, or imposed, levied, or assessed against Borrower or any of its Subsidiaries or
any of their assets to be paid in full, before delinquency or before the expiration of any
extension period, except to the extent that the validity of such assessment or tax shall be the
subject of a Permitted Protest. Borrower will make, and will cause its Subsidiaries to make,
timely payment or deposit of all tax payments and withholding taxes required of it by applicable
laws, including those laws concerning F.I.C.A., F.U.T.A., state disability, and local, state, and
federal income taxes, and will, upon request, furnish Agent with proof satisfactory to Agent
indicating that Borrower and each of its Subsidiaries has made such payments or deposits. Borrower
shall deliver satisfactory evidence of payment of applicable excise taxes in each jurisdiction in
which Borrower or any Subsidiary is required to pay any such excise tax.
6.8.
Insurance
.
(a) At Borrowers expense, maintain insurance respecting its property and assets
wherever located, covering loss or damage by fire, theft, explosion, and all other hazards
and risks as ordinarily are insured against by other Persons engaged in the same or similar
businesses. Borrower also shall maintain, and shall cause each of its Subsidiaries to
maintain, business interruption, public liability, and product liability insurance, as well
as insurance against larceny,
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embezzlement, and criminal misappropriation. All such policies of insurance shall be
in such amounts and with such insurance companies as are reasonably satisfactory to Agent.
Borrower shall deliver copies of all such policies to Agent with a satisfactory lenders
loss payable endorsement naming Agent as sole loss payee or additional insured, as
appropriate. Each policy of insurance or endorsement shall contain a clause requiring the
insurer to give not less than 30 days prior written notice to Agent in the event of
cancellation of the policy for any reason whatsoever.
(b) Borrower shall give Agent prompt notice of any loss covered by such insurance.
With respect to the Mortgaged Properties, Agent shall have the exclusive right to adjust any
losses payable under any such insurance policies in excess of $50,000, without any liability
to Borrower or any of its Subsidiaries whatsoever in respect of such adjustments. Any
monies received as payment for any loss under any insurance policy mentioned above (other
than liability insurance policies) or as payment of any award or compensation for
condemnation or taking by eminent domain, shall be paid over to Agent to be applied at the
option of the Required Lenders either to the prepayment of the Obligations or shall be
disbursed to Borrower under staged payment terms reasonably satisfactory to the Required
Lenders for application to the cost of repairs, replacements, or restorations. Any such
repairs, replacements, or restorations shall be effected with reasonable promptness and
shall be of a value at least equal to the value of the items or property destroyed prior to
such damage or destruction.
(c) Neither Borrower nor any Subsidiary shall take out separate insurance concurrent in
form or contributing in the event of loss with that required to be maintained under this
Section 6.8
, unless Agent is included thereon as named insured with the loss payable
to Agent under a lenders loss payable endorsement or its equivalent. Borrower immediately
shall notify Agent whenever such separate insurance is taken out, specifying the insurer
thereunder and full particulars as to the policies evidencing the same, and copies of such
policies promptly shall be provided to Agent.
6.9.
Hedging Agreements
. Borrower will, and will cause each Pledging Subsidiary, the
Partnerships and the LLC (for purpose of this Section the Borrower, Pledging Subsidiaries, the
Partnerships and the LLC are called the
Borrowing Base Entities
) to, maintain in effect at all
times on a continuous basis one or more Hedging Agreements with respect to their natural gas
production with the Bank Product Provider or other investment grade counterparties, rated Aa3 or
better by Moodys, A+ or better according to Standard & Poors, or the equivalent by a rating
agency acceptable to Agent or other Persons acceptable to Lender which Hedging Agreements taken
together shall at all times extend at least twelve (12) months into the future and cover aggregate
notional volumes of natural gas equal to not less than 30% and not more than 85% of the forecasted
natural gas production from Oil and Gas Properties of the Borrowing Base Entities, classified as
Proved Developed Producing Reserves as of the date of the most recent Reserve Report. The Hedging
Agreements shall be used solely as a part of normal and prudent business operations as a risk
management strategy and/or hedge against changes resulting from market conditions related to the
Borrowing Base Entities oil and gas operations and not as a means to speculate for investment
purposes on trends and shifts in financial or commodities markets. Borrower shall notify Agent
immediately upon becoming aware (in any event not later than the close of business on the same
Business Day) that the production of natural gas by any of the Borrowing Base Entities could
reasonably be expected to be insufficient to meet its obligations under any Hedging Agreements.
6.10.
Compliance with Laws
. Comply with all Governmental Rules applicable to
Borrower, each of its Subsidiaries, and their respective Properties.
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6.11.
Payment of Trade Liabilities
. Within sixty (60) days after the same become
due pay all liabilities and debt owed by Borrower and each of its Subsidiaries on ordinary trade
terms to vendors, suppliers and other Persons providing goods and services used by Borrower and
each Subsidiary in the ordinary course of its business.
6.12.
Brokerage Commissions
. Pay any and all brokerage commission or finders fees
incurred in connection with or as a result of Borrowers obtaining financing from the Lender Group
under this Agreement. Borrower agrees and acknowledges that payment of all such brokerage
commissions or finders fees shall be the sole responsibility of Borrower, and Borrower agrees to
indemnify, defend, and hold Agent and the Lender Group harmless from and against any claim of any
broker or finder arising out of Borrowers obtaining financing from the Lender Group under this
Agreement.
6.13.
Existence
. At all times preserve and keep in full force and effect the valid
existence and good standing of Borrower and each of its Subsidiaries and any rights and franchises
material to the business of Borrower and its Subsidiaries.
6.14.
Environmental
.
(a) Keep any property either owned or operated by Borrower or any of its Subsidiaries
free of any Environmental Liens or post bonds or other financial assurances sufficient to
satisfy the obligations or liability evidenced by such Environmental Liens,
(b) comply, in all material respects, with Environmental Laws and provide to Agent
documentation of such compliance which Agent reasonably requests,
(c) promptly notify Agent of any release of a Hazardous Material of any reportable
quantity from or onto property owned or operated by Borrower or any of its Subsidiaries and
take any Remedial Actions required to abate said release or otherwise to come into
compliance with applicable Environmental Law, and
(d) promptly provide Agent with written notice within 10 days of the receipt of any of
the following: (i) notice that an Environmental Lien has been filed against any of the real
or personal property of Borrower or any of its Subsidiaries, (ii) commencement of any
Environmental Action or notice that an Environmental Action will be filed against Borrower
or any of its Subsidiaries, and (iii) notice of a violation, citation, or other
administrative order which reasonably could be expected to result in a Material Adverse
Change.
6.15.
Disclosure Updates
. Promptly and in no event later than 5 Business Days after
obtaining knowledge thereof, (a) notify Agent if any written information, exhibit, or report
furnished to Agent or the Lender Group contained any untrue statement of a material fact or omitted
to state any material fact necessary to make the statements contained therein not misleading in
light of the circumstances in which made, and (b) correct any defect or error that may be
discovered therein or in any Loan Document or in the execution, acknowledgement, filing, or
recordation thereof. The foregoing to the contrary notwithstanding, any notification pursuant to
the foregoing provision will not cure or remedy the effect of the prior untrue statement of a
material fact or omission of any material fact nor shall any such notification have the affect of
amending or modifying this Agreement or any of the Schedules hereto.
6.16.
Notices of Material Events
. Promptly, and in any event within three (3)
Business Days upon Borrowers becoming aware of the following events, furnish to Agent and each
Lender written notice of the following:
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(a) the occurrence of any Default;
(b) (i) the filing or commencement of any action, suit or proceeding by or before any
arbitrator or Governmental Authority against or affecting Borrower, any of its Subsidiaries,
the LLC or any of the Partnerships or (ii) the occurrence of any adverse development with
respect to any action, suit or proceeding previously disclosed to the Agent or the Lenders
pursuant to this Agreement, in each case if such action, suit or proceeding could reasonably
be expected to result in a Material Adverse Change;
(c) (i) any claim by any Person against Borrower or any of its Subsidiaries of
nonpayment of, or (ii) any attempt by any Person to collect upon or enforce, any accounts
payable of Borrower or any of its Subsidiaries, in the case of any single account payable in
excess of $500,000.00, or in the case of all accounts payable in the aggregate in excess of
$3,000,000.00;
(d) (i) any and all enforcement, cleanup, removal or other governmental or regulatory
actions instituted, completed or threatened or other environmental claims against Borrower
or any of its Subsidiaries or any of their respective Properties pursuant to any applicable
Environmental Laws which could result in a Material Adverse Change, and (ii) any
environmental or similar condition on any real property adjoining or in the vicinity of the
property of Borrower or any of its Subsidiaries that could reasonably be anticipated to
cause such property or any part thereof to be subject to any material restrictions on the
ownership, occupancy, transferability or use of such property under any Environmental Laws;
and
(e) any other development that results in, or could reasonably be expected to result
in, a Material Adverse Change. Each notice delivered under this
Section 6.16
shall
be accompanied by a statement of the president or chief financial officer of Borrower
setting forth the details of the event or development requiring such notice and any action
taken or proposed to be taken with respect thereto.
6.17.
Information Regarding Collateral
. Promptly, and in any event within five (5)
Business Days upon becoming aware of the following changes, furnish to the Agent written notice of
any change (i) in the corporate name of Borrower or any of its Subsidiaries or in any trade name
used by Borrower or any of its Subsidiaries to identify it in the conduct of its business or in the
ownership of its properties, (ii) in the location of Borrowers or any of its Subsidiaries chief
executive office, its principal place of business, any office in which it maintains books or
records relating to Collateral or any office or facility at which Collateral is located (including
the establishment of any such new office or facility), (iii) in Borrowers, any of its
Subsidiaries, the LLCs or any of the Partnerships identity, corporate structure, or jurisdiction
of incorporation, organization or formation, or (iv) in Borrowers, any of its Subsidiaries, the
LLCs or any Partnerships Federal Taxpayer Identification Number. Borrower agrees not to effect
or permit any change referred to in the preceding sentence unless all filings have been made under
the Uniform Commercial Code or otherwise that are required in order for the Agent to continue at
all times following such change to have a valid, legal and perfected liens and security interest in
all the Collateral. Borrower also agrees promptly to notify the Agent if any material portion of
the Collateral is damaged or destroyed.
6.18.
Payment of Indebtedness
. Pay the Indebtedness of Borrower and its Subsidiaries
and other obligations, including Tax liabilities of Borrower and its Subsidiaries, before the same
shall become delinquent or in default, except where (a) the validity or amount thereof is being
contested in good faith by appropriate proceedings, (b) Borrower has set aside on its books
adequate reserves with respect thereto in accordance with GAAP, (c) such contest effectively
suspends collection of the contested obligation and
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the enforcement of any Lien securing such obligation and (d) the failure to make payment
pending such contest could not reasonably be expected to result in a Material Adverse Change.
6.19.
Books and Records; Inspection and Audit Rights
.
(a) Keep proper books of record and account in which full, true and correct entries are
made of all dealings and transactions in relation to the business and activities of Borrower
and its Subsidiaries. Borrower will permit, and will cause each of its Subsidiaries to
permit, any representatives designated by the Agent or any Lender to visit and inspect the
properties of Borrower and its Subsidiaries, to examine and make extracts from their books
and records, and to discuss their affairs, finances and condition with their officers and
independent accountants, all at such reasonable times and as often as reasonably requested.
Borrower shall pay any reasonable fees of such independent public accountant incurred in
connection with the Agents or such Lenders exercise of its rights pursuant to this
Section. Furthermore, Borrower will permit the Agent or any Lender, or its agents, at the
cost and expense of the Borrower, to enter upon the Mortgaged Properties and all parts
thereof, for the purpose of investigating and inspecting the condition and operation
thereof, and shall permit reasonable access to the field offices and other offices,
including the principal place of business, of Borrower and its Subsidiaries to inspect and
examine the Mortgaged Properties and the records of Borrower and its Subsidiaries with
respect thereto.
(b) Without limiting the generality of
Section 6.19(a)
, permit any
representatives designated by the Agent (including any consultants, accountants, engineers,
lawyers and appraisers retained by the Agent) to conduct evaluations, inspections of the
Borrowing Base Properties or of the Borrowers or any Approved Engineers assessment of the
condition or value thereof, all at such reasonable times and as often as reasonably
requested. Borrower shall pay the reasonable fees and expenses of any representatives
retained by the Agent to conduct any such evaluation or inspection.
6.20.
Use of Proceeds and Letters of Credit
. The proceeds of the Term Loan and
Advances will be used by Borrower, subject to the terms of
Section 7.20
, for (a) Energy
Business activities and (b) the advancing of loans for Energy Business activities to the
Subsidiaries, provided that, with respect to such loans, Borrower and such Subsidiaries have
complied with the provisions of
Section 7.13(b)
. For avoidance of doubt, as of the date
hereof, loans by the Borrower with proceeds of the Term Loan and Advances to the Pledging
Subsidiaries and ECA Holdings, LP comply with
Section 7.13(b)
. No part of the proceeds of
the Term Loan or any Advance will be used, whether directly or indirectly, for any purpose that
entails a violation of any of the regulations of the Board, including Regulations G, U and X.
Letters of Credit will be issued only to support normal and customary oil and gas operations
undertaken by the Pledging Subsidiaries in the ordinary course of business.
6.21.
Further Assurances
.
(a) Execute, and cause the appropriate Subsidiaries to execute, any and all further
documents, financing statements, agreements and instruments, and take all such further
actions (including the filing and recording of financing statements, fixture filings,
mortgages, deeds of trust and other documents), which may be required under any applicable
law, or which the Agent may request, to effectuate the transactions contemplated by the Loan
Documents or to grant, preserve, protect or perfect the Liens created or intended to be
created by the Loan Documents or the validity or priority of any such Lien, all at the
expense of the Borrower. Borrower also agrees to provide to the Agent, from time to time
upon request of the Agent, information which is in the possession of the Borrower or
otherwise reasonably obtainable by it, satisfactory to the Agent as
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to the ownership of the Collateral, and the perfection and priority of the Liens
created or intended to be created by the Loan Documents.
(b) Borrower hereby authorizes the Agent to file one or more financing or continuation
statements, and amendments thereto, relative to all or any part of the Collateral without
the signature of Borrower or any of its Subsidiaries where permitted by law. A carbon,
photographic or other reproduction of the Loan Documents or any financing statement covering
the Collateral or any part thereof shall be sufficient as a financing statement where
permitted by law.
(c) Without limiting any other provision of this
Section 6.21
, take such
actions and execute and deliver such documents and instruments as the Agent shall require to
ensure that the Agent shall, at all times, have received currently effective, duly executed
Loan Documents encumbering (i) the Gathering Systems and (ii) Oil and Gas Properties of
Borrower and its Subsidiaries constituting 80% of the value of the Total Proved Developed
Producing Reserves as reflected in the Initial Reserve Report (with accompanying letters in
lieu of transfer orders) and satisfactory title evidence in form and substance reasonably
acceptable to the Agent in its business judgment as to ownership of such Gathering Systems
and Oil and Gas Properties.
(d) If the Agent shall determine that, as of the date of any Borrowing Base
redetermination, Borrower shall have failed to comply with the preceding
Section
6.21(c)
, the Agent may notify the Borrower in writing of such failure and, within thirty
(30) days from and after receipt of such written notice by the Borrower, the Borrower shall
cause the Pledging Subsidiaries or any other Subsidiary of Borrower to, execute and deliver
to the Agent for the benefit of the Lender Group supplemental or additional Mortgages, in
form and substance satisfactory to the Agent and its counsel, securing payment of the
Obligations and covering additional Oil and Gas Properties of the Pledging Subsidiaries or
such other Subsidiary not then encumbered by any Mortgage (together with current valuations,
engineering reports, and title evidence (which title evidence shall be consistent with
customarily accepted title information in the geographical region in which such additional
Oil and Gas Properties are situated) applicable to the additional Oil and Gas Properties to
be mortgaged and such other documents as the Agent may require, including opinions of
counsel, each of which shall be in form and substance reasonably satisfactory to the Agent)
such that the Agent shall have received currently effective duly executed Mortgages
encumbering Oil and Gas Properties of Borrower or any of its Subsidiaries constituting at
least 80% of the Total Proved Developed Producing Reserves (with accompanying letters in
lieu of transfer orders) and satisfactory title evidence (which title evidence shall be
consistent with customarily accepted title information in the geographical region in which
such additional Oil and Gas Properties are situated) as to ownership of such additional Oil
and Gas Properties.
6.22.
Maintenance and Operation of Borrowing Base Properties
. Consistent with the
standards of a reasonably prudent operator:
(a) maintain, develop, and operate the Borrowing Base Properties and the oil and gas
gathering assets of Borrower and its Subsidiaries in a good and workmanlike manner, and
observe and comply with all of the terms and provisions, express or implied, of all
Hydrocarbon Interests relating to the Borrowing Base Properties so long as the Hydrocarbon
Interests are capable of producing Hydrocarbons and accompanying elements in quantities and
at prices providing for continued efficient and profitable operation of business;
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(b) comply in all material respects with the Material Contracts and all other contracts
and agreements applicable to or relating to the Borrowing Base Properties or the production
and sale of Hydrocarbons and accompanying elements therefrom;
(c) at all times, maintain, preserve, and keep all operating Equipment used with
respect to the Borrowing Base Properties, and oil and gas gathering assets of Borrower and
its Subsidiaries in proper repair, working order and condition, and make all necessary or
appropriate repairs, renewals, replacements, additions and improvements thereto so that the
efficiency of the operating Equipment shall at all times be properly preserved and
maintained; and
(d) with respect to the Borrowing Base Properties, and oil and gas gathering assets of
Borrower and its Subsidiaries which are operated by operators other than Borrower or its
Subsidiaries, seek to enforce the operators contractual obligations to maintain, develop,
and operate such properties subject to the applicable operating agreements.
6.23.
Collateral Value
. Unless otherwise consented to by Agent in writing, within
sixty (60) days after a Reserve Report or other report or information is delivered pursuant to
Section 6.2
that shows the Total Value is less than the amount determined by multiplying
the Maximum Loan Amount by 1.5 (
Collateral Value Amount
), Borrower shall either (a) execute,
and/or cause to be executed and delivered to the Agent supplemental or additional Mortgages, in
form and substance satisfactory to the Agent and its counsel, securing payment of the Obligations
and covering other Oil and Gas Properties directly owned by Borrower, one or more of the Pledging
Subsidiaries or any other Subsidiary of Borrower which are not then covered by any Mortgage and
having a value (as determined by Agent in its sole discretion), in addition to the other Oil and
Gas Properties already subject to a Mortgage, sufficient to cause the Total Value to exceed the
Collateral Value Amount, or (b) reduce the Total Usage to an amount equal to or less than 65% of
the newly established Total Value.
6.24.
Obligation to Pay
. Borrower hereby unconditionally promises to pay Agent for
the benefit of the Lenders, in accordance with the terms and conditions of this Credit Agreement
including, without limitation,
Section 2.6(d)
hereof, the Obligations, and to pay the
Obligations in full on the Maturity Date.
6.25.
Intentionally Deleted
.
7. NEGATIVE COVENANTS.
Borrower covenants and agrees that, so long as any credit hereunder shall be available and
until full and final payment of the Obligations, Borrower will not, and will not permit any of its
Subsidiaries to do any of the following:
7.1.
Indebtedness
. Create, incur, assume, permit, guarantee, or otherwise become or
remain, directly or indirectly, liable with respect to any Indebtedness, except:
(a) Indebtedness evidenced by this Agreement and the other Loan Documents, together
with Indebtedness owed to Underlying Issuers with respect to Underlying Letters of Credit;
(b) Indebtedness of Borrower and its Subsidiaries set forth on
Schedule 5.20
;
(c) refinancings, renewals, or extensions of Indebtedness permitted under clause (b) of
this
Section 7.1
(and continuance or renewal of any Permitted Liens associated
therewith) so
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long as: (i) the terms and conditions of such refinancings, renewals, or extensions do
not, in Agents reasonable judgment, materially impair the prospects of repayment of the
Obligations by Borrower or materially impair Borrowers creditworthiness, (ii) such
refinancings, renewals, or extensions do not result in an increase in the principal amount
of the Indebtedness so refinanced, renewed, or extended or add one or more of the Borrowers
Subsidiaries or Affiliates as liable with respect thereto if such additional Subsidiary or
Affiliate were not liable with respect to the original Indebtedness, (iii) such
refinancings, renewals, or extensions do not result in a shortening of the average weighted
maturity of the Indebtedness so refinanced, renewed, or extended, nor are they on terms or
conditions, that, taken as a whole, are materially more burdensome or restrictive to the
Borrower, and (iv) if the Indebtedness that is refinanced, renewed, or extended was
subordinated in right of payment to the Obligations, then the terms and conditions of the
refinancing, renewal, or extension Indebtedness must include subordination terms and
conditions that are at least as favorable to Agent and the Lender Group as those that were
applicable to the refinanced, renewed, or extended Indebtedness;
(d) Indebtedness of Borrower not secured by or subject to a Lien in respect of
performance, completion, guarantee, surety, or similar bonds, bankers acceptances, bills of
exchange, or letters of credit provided by Borrower in the ordinary course of its Energy
Business provided that such Indebtedness does not exceed $2,000,000.00 in the aggregate at
any one time outstanding;
(e) accounts payable or other obligations of Borrower and its Subsidiaries to trade
creditors created in the ordinary course of its Energy Business in connection with the
obtaining of goods and services provided that all such obligations and liabilities are paid
within 60 days when due;
(f) Indebtedness of Borrower consisting of obligations in respect of purchase price
adjustments, guaranties or indemnities in connection with the acquisition of assets or
Permitted Dispositions;
(g) Non-Recourse Debt of any Unrestricted Subsidiary provided such Non-Recourse Debt is
incurred in connection with an acquisition of assets by an Unrestricted Subsidiary permitted
under
Section 7.13
;
(h) Unsecured Indebtedness of the Subsidiaries to Borrower;
(i) Hedging Obligations of the Borrower and its Subsidiaries,
provided:
(i) Hedging Obligations of Borrower and its Subsidiaries other than those of
the Pledging Subsidiaries, the Partnerships, and the LLC and of the Borrower
relating thereto (which are subject to the restriction under (ii) below) shall only
be under contracts entered into in the ordinary course of business for the purpose
of limiting risks that arise in the ordinary course of business of Borrower and its
Subsidiaries and not for the purpose of speculation; and
(ii) Hedging Obligations of the Pledging Subsidiaries, the Partnerships, and
the LLC and of the Borrower relating thereto shall only be permitted to the extent
set forth in
Section 6.9
;
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(j) additional Indebtedness of Borrower not to exceed $5,000,000.00 in the aggregate
during the term of this Agreement provided that the terms and conditions of such
Indebtedness are reasonably satisfactory to Agent; and
(k) liabilities of Borrower resulting from the sale of Production Payments with respect
to oil, gas, or mineral leases or interests (other than Borrowing Base Properties) to the
extent Borrower does not transfer control of the interest sold to the buyer, and such
liabilities are recorded in accordance with GAAP.
7.2.
Liens
. Create, incur, assume, or permit to exist, directly or indirectly, any
Lien on or with respect to any of its assets, of any kind, whether now owned or hereafter acquired,
or any income or profits therefrom, except for:
(a) Permitted Liens (including Liens that are replacements of Permitted Liens to the
extent that the original Indebtedness is refinanced, renewed, or extended under
Section
7.1(e)
and so long as the replacement Liens only encumber those assets that secured the
refinanced, renewed, or extended Indebtedness);
(b) any Lien on Borrowing Base Properties existing on the Closing Date and set forth on
Schedule 7.2
; provided that (i) such Lien shall not apply to any other Property or
asset of Borrower or any Subsidiary, and (ii) such Lien shall secure only those obligations
which it secured on the Closing Date; and
(c) any Lien existing on any Property or asset prior to the acquisition thereof by the
Borrower or any Subsidiary (other than Pledging Subsidiaries) or existing on any Property or
asset of any Person that becomes a Subsidiary after the date of this Agreement prior to the
time such Person becomes a Subsidiary; provided that (i) such Lien is not created in
contemplation of or in connection with such acquisition or such Person becoming a
Subsidiary, as the case may be, (ii) such Lien shall not apply to any other Property or
assets of Borrower or any Subsidiary, and (iii) such Lien shall secure only those
obligations which it secures on the date of such acquisition or the date such Person becomes
a Subsidiary;
(d) Liens on fixed or capital assets acquired, constructed or improved by Borrower or
any Subsidiary which do not constitute Collateral; provided that (i) such security interests
secure Indebtedness permitted by clause (j) of
Section 7.1
, (ii) such security
interests and the Indebtedness secured thereby are incurred prior to or within 90 days after
such acquisition or the completion of such asset, (iii) the Indebtedness secured thereby
does not exceed 75% of the cost of acquiring or improving such Oil and Gas Property or fixed
or capital asset, and (iv) such Lien does not apply to any other Property or assets of the
Borrower or any of its Subsidiaries; and
(e) Liens securing Non-Recourse Debt permitted by
Section 7.1
provided the Lien
is limited to the assets acquired by the Unrestricted Subsidiary with the proceeds of the
Non-Recourse Debt.
7.3.
Restrictions on Fundamental Changes
.
(a) Enter into any merger, consolidation, reorganization, or recapitalization, or
reclassify its Stock, except to the extent permitted by the terms of
Section 7.11
.
(b) Liquidate, wind up, or dissolve itself (or suffer any liquidation or dissolution).
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(c) Convey, sell, lease, license, assign, transfer, or otherwise dispose of, in one
transaction or a series of transactions, all or any substantial part of its assets.
7.4.
Disposal of Assets
. Other than Permitted Dispositions, convey, sell, lease,
license, assign, transfer, or otherwise dispose of (or enter into an agreement to convey, sell,
lease, license, assign, transfer, or otherwise dispose of) any of the assets of Borrower or any of
its Subsidiaries.
7.5.
Change Name
. Change Borrowers or any Subsidiaries name, FEIN, corporate
structure or identity, or add any new fictitious name;
provided
,
however
, that
Borrower or any of its Subsidiaries may change its name upon at least 30 days prior written notice
by Borrower to Agent of such change and so long as, at the time of such written notification,
Borrower or any such Subsidiary provides any financing statements or fixture filings necessary to
perfect and continue perfected Agents Liens.
7.6.
Guarantee
. Guarantee or otherwise become in any way liable with respect to the
obligations of any third Person except by endorsement of instruments or items of payment for
deposit to the account of Borrower or which are transmitted or turned over to Agent;
provided
,
however
, that Borrower may execute guarantees of Indebtedness of its
Subsidiaries to the extent the Indebtedness of such Subsidiary is permitted by the terms of this
Agreement.
7.7.
Nature of Business
. Make any change in the principal nature of Borrowers or any
Subsidiaries business.
7.8.
Prepayments and Amendments
.
(a) Except in connection with a refinancing permitted by
Section 7.1(c)
,
prepay, redeem, defease, purchase, or otherwise acquire any Indebtedness of Borrower or any
of its Subsidiaries, other than the Obligations in accordance with this Agreement.
(b) Except in connection with a refinancing permitted by
Section 7.1(c)
,
directly or indirectly, amend, modify, alter, increase, or change any of the terms or
conditions of any agreement, instrument, document, indenture, or other writing evidencing
or concerning Indebtedness permitted under
Sections 7.1(b)
.
7.9.
Change of Control
. Cause, permit, or suffer, directly or indirectly, any Change
of Control.
7.10.
Intentionally Deleted
.
7.11.
Distributions
. Other than distributions or declaration and payment of dividends
by a Subsidiary to Borrower, make any distribution or declare or pay any dividends (in cash or
other property, other than common Stock) on, or purchase, acquire, redeem, or retire any of
Borrowers Stock, of any class, whether now or hereafter outstanding;
provided
,
however
, so long as no Default or Event of Default has occurred and is continuing, the
foregoing restrictions shall not apply to:
(a) Borrowers paying annual cash dividends in the aggregate not to exceed 15% of
EBITDAX, determined on a rolling four-quarter basis, provided at the time of payment of such
dividends, after giving effect to such payment, either (i) Excess Availability exceeds
$20,000,000.00 or (ii) in the event Excess Availability is equal to or less than
$20,000,000.00, the Fixed Charge Coverage Ratio is equal to or in excess of 1.0 to 1.0 and
Borrower, prior to making any such payment, delivers to Agent a report prepared by the Chief
Financial Officer of Borrower
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setting forth the information and calculations necessary to demonstrate compliance with
the Fixed Charge Coverage Ratio requirement;
(b) any Subsidiary paying cash dividends to the Borrower or any other Subsidiary at
such times and in such amounts during any fiscal year, as shall be necessary to permit
Borrower to discharge its permitted liabilities;
(c) Borrowers repurchasing common and Class A stock of Borrower owned by employees who
terminate their employment or whose employment is terminated by Borrower consistent with the
existing programs between the Borrower and its employees in an amount which when added to
the amounts expended by Borrower pursuant to
Section 7.11(d)
does not exceed
$2,000,000.00 in any twelve (12) month period;
(d) Borrowers repurchasing common and Class A stock of Borrower consistent with
existing programs and practices of Borrower in an amount which when added to the amounts
expended by Borrower pursuant to
Section 7.11(c)
does not exceed $2,000,000.00 in
any twelve (12) month period;
provided
,
however
, if the amount expended by
Borrower pursuant to
Section 7.11(c)
and
Section 7.11(d)
is less than
$2,000,000.00 in the aggregate in any twelve (12) month period, an amount equal to the
difference between $2,000,000.00 and the amount expended (the
Carried Over Amount
)
in such twelve (12) month period may be carried over into one or more subsequent years so
long as the aggregate amount expended in any twelve (12) month period, after adding the
Carried Over Amount to the $2,000,000.00 expenditure otherwise permitted under
Section
7.11(c)
and
Section 7.11(d)
, does not exceed $5,000,000.00; and
(e) Borrowers repurchasing common and Class A stock of Borrower consistent with
existing programs and practices of Borrower from the estate of deceased members of the Board
of Directors of Borrower in an amount not to exceed $5,000,000.00 in any twelve (12) month
period.
7.12.
Accounting Methods
. Modify or change its method of accounting (other than as
may be required to conform to GAAP) or enter into, modify, or terminate any agreement currently
existing, or at any time hereafter entered into with any third party accounting firm or service
bureau for the preparation or storage of the accounting records of Borrower and its Subsidiaries
without said accounting firm or service bureau agreeing to provide Agent information regarding the
Collateral or the financial condition of the Borrower and its Subsidiaries.
7.13.
Investments
. Directly or indirectly, make or acquire any Investment, or incur
any liabilities (including contingent obligations) for or in connection with any Investment,
except:
(a) Permitted Investments;
(b) unsecured loans and advances (including loans and advances made by Borrower to any
Subsidiary, including the Pledging Subsidiaries, with the proceeds of the Term Loan and
Advances) from Borrower to any Subsidiary, including the Pledging Subsidiaries, provided
that (i) each such Subsidiary and Pledging Subsidiary executes and delivers to Borrower a
promissory note (the
Intercompany Notes
) evidencing such loans and advances
payable to the order of Borrower, all in form, scope, and content acceptable to Agent, and
(ii) Borrower pledges and assigns the Intercompany Notes to Agent as security for the
payment of the Obligations pursuant to the Borrowers Security Agreement and endorses the
Intercompany Notes to the order of Agent, all in a form and manner satisfactory to Agent;
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(c) Investments by Borrower and/or any Subsidiary made or entered into in the ordinary
course of the Energy Business; provided that immediately before and immediately after giving
effect to such Investments, no Default or Event of Default exists;
(d) capital expenditures by Borrower and the Subsidiaries with respect to the assets
used or useful in the Energy Business conducted by Borrower and the Subsidiaries, to the
extent permitted by
Section 7.20(b)
;
(e) Investments by Borrower in its Subsidiaries;
(f) Investments by an Unrestricted Subsidiary with the proceeds of Non-Recourse Debt;
and
(g) Investments of Borrower and the Subsidiaries existing as of the date of this
Agreement and reflected on
Schedule 7.13
.
7.14.
Transactions with Affiliates
. Directly or indirectly enter into or permit to
exist any transaction with any Affiliate of Borrower except for transactions that are in the
ordinary course of Borrowers business, upon fair and reasonable terms, that are fully disclosed to
Lender, and that are no less favorable to Borrower than would be obtained in an arms length
transaction with a non-Affiliate;
provided
,
however
, that Borrower and its
Subsidiaries may engage in drilling program transactions with Borrowers officers, employees and
directors consistent with past practices of Borrower.
7.15.
Suspension
. Suspend or go out of a substantial portion of its business.
7.16.
Intentionally Deleted
.
7.17.
Use of Proceeds
. Use the proceeds of the Term Loan and the Advances for any
purpose other than (a) on the date hereof, to pay transactional fees, costs, and expenses incurred
in connection with this Agreement, the other Loan Documents, and the transactions contemplated
hereby and thereby, and (b) thereafter, only for the purposes set forth in
Section 6.20
.
7.18.
Change in Location of Chief Executive Office; Inventory and Equipment with
Bailees
. Relocate its chief executive office to a new location without Borrower providing 30
days prior written notification thereof to Agent and so long as, at the time of such written
notification, the Borrower or applicable Subsidiary provides any financing statements or fixture
filings necessary to perfect and continue perfected the Agents Liens and also provides to Agent a
Collateral Access Agreement with respect to such new location.
7.19.
Securities Accounts
. Establish or maintain any Securities Account unless Agent
shall have received a Control Agreement in respect of such Securities Account. Borrower will not
transfer, and will not permit any of its Subsidiaries to transfer, assets out of any Securities
Account;
provided
,
however
, that, so long as no Event of Default has occurred and
is continuing or would result therefrom, Borrower may use such assets (and the proceeds thereof) to
the extent not prohibited by this Agreement.
7.20.
Financial Covenants
.
(a) Fail to maintain:
(i) Minimum EBITDAX. EBITDAX in an amount equal to or greater than
$40,000,000.00 at the close of each fiscal quarter of Borrower after the date
hereof.
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Compliance of the foregoing covenant will be tested quarterly on a rolling four
quarter basis, commencing with the quarter ending September 30, 2007.
(ii) Book Net Worth. Book Net Worth of at least $37,000,000.00 at the close of
each fiscal quarter of Borrower after the date hereof; provided that the calculation
of Book Net Worth shall exclude all unrealized losses over all unrealized profits
arising from Hedging Agreements. Compliance of the foregoing covenant will be
tested quarterly, commencing with the quarter ending September 30, 2007.
(b) Make:
(i) Capital Expenditures. Upon Excess Availability falling below
$10,000,000.00 in any fiscal year, capital expenditures in such fiscal year of
Borrower in an amount in excess of 120% of the Projections for such fiscal year
delivered to Agent in accordance with the terms of this Agreement and approved by
Agent.
7.21.
Intentionally Deleted
.
7.22.
Intentionally Deleted
.
8. EVENTS OF DEFAULT.
Any one or more of the following events shall constitute an event of default (each, an
Event
of Default
) under this Agreement:
8.1. If Borrower or any of its Subsidiaries fails to pay when due and payable or when declared
due and payable, all or any portion of the Obligations (whether of principal, interest (including
any interest which, but for the provisions of the Bankruptcy Code, would have accrued on such
amounts), fees and charges due Agent or any member of the Lender Group, reimbursement of Lender
Expenses, or other amounts constituting Obligations);
8.2. If Borrower or any of its Subsidiaries fails to perform, keep, or observe (a) any term,
provision, condition, covenant, or agreement contained in
Sections 6.1, 6.2, 6.3, 6.6, 6.7,
6.10, 6.11, 6.12, 6.14, 6.15, 6.16, 6.17, 6.19, 6.21, or 6.22
of this Agreement and such
failure continues for a period of fifteen (15) days after the date of failure; or (b) any other
term, provision, condition, covenant, or agreement in this Agreement or any of the other Loan
Documents;
8.3. If any material portion of Borrowers or any of its Subsidiaries assets is attached,
seized, subjected to a writ or distress warrant, levied upon, or comes into the possession of any
third Person;
8.4. If an Insolvency Proceeding is commenced by Borrower or any of its Subsidiaries;
8.5. If an Insolvency Proceeding is commenced against Borrower or any of its Subsidiaries, and
any of the following events occur: (a) the Borrower or any Subsidiary consents to the institution
of the Insolvency Proceeding against it, (b) the petition commencing the Insolvency Proceeding is
not timely controverted;
provided
,
however
, that during the pendency of such
period, each member of the Lender Group shall be relieved of its obligations to extend credit
hereunder, (c) the petition commencing the Insolvency Proceeding is not dismissed within 45
calendar days of the date of the filing thereof;
provided
,
however
, that, during
the pendency of such period, Agent (including any successor agent) and each other member of the
Lender Group shall be relieved of its obligation to extend credit hereunder, (d) an interim trustee
is appointed to take possession of all or any substantial portion of the properties or assets of,
or to
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operate all or any substantial portion of the business of, Borrower or any of its
Subsidiaries, or (e) an order for relief shall have been entered therein;
8.6. If Borrower or any of its Subsidiaries is enjoined, restrained, or in any way prevented
by court order from continuing to conduct all or any material part of its business affairs;
8.7. If a notice of Lien, levy, or assessment is filed of record with respect to any
Borrowers or any of its Subsidiaries assets by the United States, or any department, agency, or
instrumentality thereof, or by any state, county, municipal, or governmental agency, or if any
taxes or debts owing at any time hereafter to any one or more of such entities becomes a Lien,
whether choate or otherwise, upon Borrowers or any of its Subsidiaries assets and the same is not
paid before such payment is delinquent;
8.8. If a judgment or other claim becomes a Lien or encumbrance upon any material portion of
Borrowers or any of its Subsidiaries assets or any material portion of the Borrowing Base
Properties located in the State of West Virginia owned by either of the Pledging Subsidiaries;
8.9. If there is a default in any material agreement to which Borrower or any of its
Subsidiaries is a party and such default (a) occurs at the final maturity of the obligations
thereunder, or (b) results in a right by the other party thereto, irrespective of whether
exercised, to accelerate the maturity of the Borrowers or its Subsidiaries obligations
thereunder, to terminate such agreement, or to refuse to renew such agreement pursuant to an
automatic renewal right therein;
8.10. If Borrower or any of its Subsidiaries makes any payment on account of Indebtedness that
has been contractually subordinated in right of payment to the payment of the Obligations, except
to the extent such payment is permitted by the terms of the subordination provisions applicable to
such Indebtedness;
8.11. If any misstatement or misrepresentation exists now or hereafter in any warranty,
representation, statement, or Record made to the Lender Group by Borrower, its Subsidiaries, or any
officer, employee, agent, or director of Borrower or any of its Subsidiaries;
8.12. Intentionally Deleted;
8.13. If this Agreement or any other Loan Document that purports to create a Lien, shall, for
any reason, fail or cease to create a valid and perfected and, except to the extent permitted by
the terms hereof or thereof, first priority Lien on or security interest in the Collateral covered
hereby or thereby; or
8.14. Any provision of any Loan Document shall at any time for any reason be declared to be
null and void, or the validity or enforceability thereof shall be contested by Borrower or any of
its Subsidiaries, or a proceeding shall be commenced by Borrower or any of its Subsidiaries, or by
any Governmental Authority having jurisdiction over Borrower or any of its Subsidiaries, seeking to
establish the invalidity or unenforceability thereof, or Borrower or any of its Subsidiaries shall
deny that Borrower or such Subsidiary has any liability or obligation purported to be created under
any Loan Document.
9. THE LENDER GROUPS RIGHTS AND REMEDIES.
9.1.
Rights and Remedies
. Upon the occurrence, and during the continuation, of an
Event of Default, the Required Lenders (at their election but without notice of their election and
without demand) may authorize and instruct Agent to do any one or more of the following on behalf
of the Lender Group (and Agent, acting upon the instructions of the Required Lenders, shall do the
same on behalf of the Lender Group), all of which are authorized by Borrower:
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(a) Declare all Obligations, whether evidenced by this Agreement, by any of the other
Loan Documents, or otherwise, immediately due and payable;
provided
,
however
, that upon the occurrence of any Event of Default described in
Section
8.4
or
Section 8.5
, all Commitments shall automatically and immediately expire
and all Obligations shall automatically become immediately due and payable without notice or
demand of any kind;
(b) Cease advancing money or extending credit to or for the benefit of Borrower under
this Agreement, under any of the Loan Documents, or under any other agreement between any
Obligor and the Lender Group;
(c) Terminate this Agreement and any of the other Loan Documents as to any future
liability or obligation of the Lender Group, but without affecting any of the Agents Liens
in the Collateral and without affecting the Obligations;
(d) Settle or adjust disputes and claims directly with Account Debtors for amounts and
upon terms which Agent considers advisable, and in such cases, Agent will credit the Loan
Account with only the net amounts received by Agent in payment of such disputed Accounts
after deducting all Lender Group Expenses incurred or expended in connection therewith;
(e) Without notice to or demand upon Borrower, make such payments and do such acts as
Agent considers necessary or reasonable to protect its liens and security interests in the
Collateral;
(f) Without notice to Borrower (such notice being expressly waived), and without
constituting a retention of any collateral in satisfaction of an obligation (within the
meaning of the Code), set off and apply to the Obligations any and all (i) balances and
deposits of Borrower held by the Lender Group (including any amounts received in the Cash
Management Accounts), or (ii) Indebtedness at any time owing to or for the credit or the
account of Borrower held by the Lender Group;
(g) Hold, as cash collateral, any and all balances and deposits of Borrower held by the
Lender Group, and any amounts received in the Cash Management Accounts, to secure the full
and final repayment of all of the Obligations;
(h) Pursue any and all remedies afforded Agent and/or the Lender Group under the Loan
Documents; and
(i) The Lender Group shall have all other rights and remedies available to it at law or
in equity pursuant to any other Loan Documents.
9.2.
Remedies Cumulative
. The rights and remedies of the Lender Group under this
Agreement, the other Loan Documents, and all other agreements shall be cumulative. The Lender
Group shall have all other rights and remedies not inconsistent herewith as provided under the
Code, by law, or in equity. No exercise by the Lender Group of one right or remedy shall be deemed
an election, and no waiver by the Lender Group of any Event of Default shall be deemed a continuing
waiver. No delay by the Lender Group shall constitute a waiver, election, or acquiescence by it.
10. TAXES AND EXPENSES.
If Borrower fails to pay any monies (whether taxes, royalties, overriding royalties, operating
costs or expenses, assessments, insurance premiums, or, in the case of leased properties or assets,
rents or other
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amounts payable under such leases) due to third Persons, or fails to make any deposits or
furnish any required proof of payment or deposit, all as required under the terms of this
Agreement, then, Agent, in its sole discretion and without prior notice to Borrower, may do any or
all of the following: (a) make payment of the same or any part thereof, (b) set up such reserves
in Borrowers Loan Account as Agent deems necessary to protect the Lender Group from the exposure
created by such failure, or (c) in the case of the failure to comply with
Section 6.8
hereof, obtain and maintain insurance policies of the type described in
Section 6.8
and
take any action with respect to such policies as Agent deems prudent. Any such amounts paid by
Agent shall constitute Lender Group Expenses and any such payments shall not constitute an
agreement by the Lender Group to make similar payments in the future or a waiver by the Lender
Group of any Event of Default under this Agreement. Agent need not inquire as to, or contest the
validity of, any such expense, tax, or Lien and the receipt of the usual official notice for the
payment thereof shall be conclusive evidence that the same was validly due and owing.
11. WAIVERS; INDEMNIFICATION.
11.1.
Demand; Protest
. Borrower waives demand, protest, notice of protest, notice of
default or dishonor, notice of payment and nonpayment, nonpayment at maturity, release, compromise,
settlement, extension, or renewal of documents, instruments, chattel paper, and guarantees at any
time held by the Lender Group on which Borrower may in any way be liable.
11.2.
The Lender Groups Liability for Collateral
. Borrower hereby agrees that: (a)
so long as the Lender Group complies with its obligations, if any, under the Code, Agent shall not
in any way or manner be liable or responsible for: (i) the safekeeping of the Collateral, (ii) any
loss or damage thereto occurring or arising in any manner or fashion from any cause, (iii) any
diminution in the value thereof, or (iv) any act or default of any carrier, warehouseman, bailee,
forwarding agency, or other Person, and (b) all risk of loss, damage, or destruction of the
Collateral shall be borne by Borrower.
11.3.
Indemnification
. Borrower shall pay, indemnify, defend, and hold the
Agent-Related Persons, the Lender-Related Persons with respect to each Lender, each Participant,
and each of their respective officers, directors, employees, agents, and attorneys-in-fact (each,
an
Indemnified Person
) harmless (to the fullest extent permitted by law) from and against any and
all claims, demands, suits, actions, investigations, proceedings, liabilities, fines, costs,
penalties and damages, and all reasonable fees and disbursements of attorneys, experts, or
consultants and all other costs and expenses actually incurred in connection therewith or in
connection with the enforcement of this indemnification (as and when they are incurred and
irrespective of whether suit is brought), at any time asserted against, imposed upon, or incurred
by any of them (a) in connection with or as a result of or related to the execution, delivery,
enforcement, performance, or administration (including any restructuring or workout with respect
hereto) of this Agreement, any of the other Loan Documents, or the transactions contemplated hereby
or thereby or the monitoring of Borrowers and its Subsidiaries compliance with the terms of the
Loan Documents, (b) with respect to any investigation, litigation, or proceeding related to this
Agreement, any other Loan Document, or the use of the proceeds of the credit provided hereunder
(irrespective of whether any Indemnified Person is a party thereto), or any act, omission, event,
or circumstance in any manner related thereto, and (c) in connection with or arising out of any
presence or release of Hazardous Materials at, on, under, to or from any assets or properties
owned, leased or operated by Borrower or any of its Subsidiaries or any Environmental Actions,
Environmental Liabilities and Costs or Remedial Action related in any way to any such assets or
properties of Borrower or any of its Subsidiaries (all the foregoing, collectively, the
Indemnified Liabilities
). The foregoing to the contrary notwithstanding, Borrower shall have no
obligation to any Indemnified Person under this
Section 11.3
with respect to any
Indemnified Liability that a court of competent jurisdiction finally determines to have resulted
from the gross negligence or willful misconduct of such Indemnified Person. This provision shall
survive the termination of this Agreement and the repayment of the Obligations. If any Indemnified
Person makes
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any payment to any other Indemnified Person with respect to an Indemnified Liability as to
which Borrower was required to indemnify the Indemnified Person receiving such payment, the
Indemnified Person making such payment is entitled to be indemnified and reimbursed by Borrower
with respect thereto. WITHOUT LIMITATION, THE FOREGOING INDEMNITY SHALL APPLY TO EACH INDEMNIFIED
PERSON WITH RESPECT TO INDEMNIFIED LIABILITIES WHICH IN WHOLE OR IN PART ARE CAUSED BY OR ARISE OUT
OF ANY NEGLIGENT ACT OR OMISSION OF SUCH INDEMNIFIED PERSON OR OF ANY OTHER PERSON.
12. NOTICES.
Unless otherwise provided in this Agreement, all notices or demands by Borrower or Agent to
the other relating to this Agreement or any other Loan Document shall be in writing and (except for
financial statements and other informational documents which may be sent by first-class mail,
postage prepaid) shall be personally delivered or sent by registered or certified mail (postage
prepaid, return receipt requested), overnight courier, electronic mail (at such email addresses as
Borrower or Agent, as applicable, may designate to each other in accordance herewith), or
telefacsimile to Borrower in care of Borrower or to Agent, as the case may be, at its address set
forth below:
|
If to Borrower:
|
|
Energy Corporation of America
4643 South Ulster Street, Suite 1100
Denver, Colorado 80237
Attn: Michael S. Fletcher
Fax No. 303.694.2763
|
|
|
with copies to:
|
|
Goodwin & Goodwin, LLP
330 Summers Street, Suite 1500
Charleston, West Virginia 25301-1678
Attn: Tammy J. Owen, Esq.
Fax No. 304.344.9692
|
|
|
If to Agent:
|
|
WELLS FARGO FOOTHILL, INC.
2450 Colorado Avenue
Suite 3000 West
Santa Monica, California 90404
Attn: Business Finance Division Manager
Fax No. 310.453.7443
|
|
|
with copies to:
|
|
Wells Fargo Foothill, Inc.
1100 Abernathy Road, Suite 1600
Atlanta, Georgia 30328
Attn: Business Division Manager
Fax No. 770.804.0551
|
|
|
with copies to:
|
|
Munsch Hardt Kopf & Harr, P.C.
3800 Lincoln Plaza
500 N. Akard
Dallas, Texas 75201-6659
Attn: William A. Lang, Esq.
Fax No. 214.855.7520
|
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Agent and Borrower may change the address at which they are to receive notices hereunder,
by notice in writing in the foregoing manner given to the other party. All notices or demands sent
in accordance with this
Section 12
, other than notices by Agent in connection with
enforcement rights against the Collateral under the provisions of the Code, shall be deemed
received on the earlier of the date of actual receipt or 3 Business Days after the deposit thereof
in the mail. Borrower acknowledges and agrees that notices sent by the Lender Group in connection
with the exercise of enforcement rights against Collateral under the provisions of the Code shall
be deemed sent when deposited in the mail or personally delivered, or, where permitted by law,
transmitted by telefacsimile or any other method set forth above.
13. CHOICE OF LAW AND VENUE; JURY TRIAL WAIVER.
(a) THE VALIDITY OF THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS (UNLESS EXPRESSLY
PROVIDED TO THE CONTRARY IN ANOTHER LOAN DOCUMENT IN RESPECT OF SUCH OTHER LOAN DOCUMENT),
THE CONSTRUCTION, INTERPRETATION, AND ENFORCEMENT HEREOF AND THEREOF, AND THE RIGHTS OF THE
PARTIES HERETO AND THERETO WITH RESPECT TO ALL MATTERS ARISING HEREUNDER OR THEREUNDER OR
RELATED HERETO OR THERETO SHALL BE DETERMINED UNDER, GOVERNED BY, AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF THE STATE OF GEORGIA.
(b) THE PARTIES AGREE THAT ALL ACTIONS OR PROCEEDINGS ARISING IN CONNECTION WITH THIS
AGREEMENT AND THE OTHER LOAN DOCUMENTS SHALL BE TRIED AND LITIGATED ONLY IN THE STATE AND,
TO THE EXTENT PERMITTED BY APPLICABLE LAW, FEDERAL COURTS LOCATED IN THE COUNTY OF FULTON,
STATE OF GEORGIA,
PROVIDED
,
HOWEVER
, THAT ANY SUIT SEEKING ENFORCEMENT
AGAINST ANY COLLATERAL OR OTHER PROPERTY MAY BE BROUGHT, AT AGENTS OPTION, IN THE COURTS OF
ANY JURISDICTION WHERE AGENT ELECTS TO BRING SUCH ACTION OR WHERE SUCH COLLATERAL OR OTHER
PROPERTY MAY BE FOUND. BORROWER AND EACH MEMBER OF THE LENDER GROUP WAIVE, TO THE EXTENT
PERMITTED UNDER APPLICABLE LAW, ANY RIGHT EACH MAY HAVE TO ASSERT THE DOCTRINE OF
FORUM
NON
CONVENIENS
OR TO OBJECT TO VENUE TO THE EXTENT ANY
PROCEEDING IS BROUGHT IN ACCORDANCE WITH THIS
SECTION 13(b)
.
BORROWER AND EACH MEMBER OF THE LENDER GROUP HEREBY WAIVE THEIR RESPECTIVE RIGHTS TO A JURY TRIAL
OF ANY CLAIM OR CAUSE OF ACTION BASED UPON OR ARISING OUT OF ANY OF THE LOAN DOCUMENTS OR ANY OF
THE TRANSACTIONS CONTEMPLATED THEREIN, INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY
CLAIMS, AND ALL OTHER COMMON LAW OR STATUTORY CLAIMS. BORROWER AND EACH MEMBER OF THE LENDER GROUP
REPRESENT THAT EACH HAS REVIEWED THIS WAIVER AND EACH KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY
TRIAL RIGHTS FOLLOWING CONSULTATION WITH LEGAL COUNSEL. IN THE EVENT OF LITIGATION, A COPY OF THIS
AGREEMENT MAY BE FILED AS A WRITTEN CONSENT TO A TRIAL BY THE COURT.
14. ASSIGNMENTS AND PARTICIPATIONS; SUCCESSORS.
14.1.
Assignments and Participations
.
(a) Any Lender may, with the written consent of Agent (provided that no written consent
of Agent shall be required in connection with any assignment and delegation by a Lender
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to an Eligible Transferee), assign and delegate to one or more assignees (each an
Assignee
) all, or any ratable part of all, of the Obligations, the Commitments and the
other rights and obligations of such Lender hereunder and under the other Loan Documents, in
a minimum amount of $10,000,000.00;
provided
,
however
, that Borrower and
Agent may continue to deal solely and directly with such Lender in connection with the
interest so assigned to an Assignee until (i) written notice of such assignment, together
with payment instructions, addresses, and related information with respect to the Assignee,
have been given to Borrower and Agent by such Lender and the Assignee, (ii) such Lender and
its Assignee have delivered to Borrower and Agent an Assignment and Acceptance in form and
substance satisfactory to Agent, and (iii) the assignor Lender or Assignee has paid to Agent
for Agents separate account a processing fee in the amount of $5,000.00. Anything
contained herein to the contrary notwithstanding, the consent of Agent shall not be required
(and payment of any fees shall not be required) if such assignment is in connection with any
merger, consolidation, sale, transfer, or other disposition of all or any substantial
portion of the business or loan portfolio of such Lender.
(b) From and after the date that Agent notifies the assignor Lender (with a copy to
Borrower) that it has received an executed Assignment and Acceptance and payment of the
above-referenced processing fee, (i) the Assignee thereunder shall be a party hereto and, to
the extent that rights and obligations hereunder have been assigned to it pursuant to such
Assignment and Acceptance, shall have the rights and obligations of a Lender under the Loan
Documents, and (ii) the assignor Lender shall, to the extent that rights and obligations
hereunder and under the other Loan Documents have been assigned by it pursuant to such
Assignment and Acceptance, relinquish its rights (except with respect to
Section
11.3
hereof) and be released from its obligations under this Agreement (and in the case
of an Assignment and Acceptance covering all or the remaining portion of an assigning
Lenders rights and obligations under this Agreement and the other Loan Documents, such
Lender shall cease to be a party hereto and thereto), and such assignment shall affect a
novation between Borrower and the Assignee.
(c) By executing and delivering an Assignment and Acceptance, the assigning Lender
thereunder and the Assignee thereunder confirm to and agree with each other and the other
parties hereto as follows: (1) other than as provided in such Assignment and Acceptance,
such assigning Lender makes no representation or warranty and assumes no responsibility with
respect to any statements, warranties or representations made in or in connection with this
Agreement or the execution, legality, validity, enforceability, genuineness, sufficiency or
value of this Agreement or any other Loan Document furnished pursuant hereto, (2) such
assigning Lender makes no representation or warranty and assumes no responsibility with
respect to the financial condition of Borrower or the performance or observance by Borrower
of any of its obligations under this Agreement or any other Loan Document furnished pursuant
hereto, (3) such Assignee confirms that it has received a copy of this Agreement, together
with such other documents and information as it has deemed appropriate to make its own
credit analysis and decision to enter into such Assignment and Acceptance, (4) such Assignee
will, independently and without reliance upon Agent, such assigning Lender or any other
Lender, and based on such documents and information as it shall deem appropriate at the
time, continue to make its own credit decisions in taking or not taking action under this
Agreement, (5) such Assignee appoints and authorizes Agent to take such actions and to
exercise such powers under this Agreement as are delegated to Agent, by the terms hereof,
together with such powers as are reasonably incidental thereto, and (6) such Assignee agrees
that it will perform all of the obligations which by the terms of this Agreement are
required to be performed by it as a Lender.
(d) Immediately upon each Assignees making its processing fee payment under the
Assignment and Acceptance and receipt and acknowledgment by Agent of such fully executed
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Assignment and Acceptance, this Agreement shall be deemed to be amended to the extent,
but only to the extent, necessary to reflect the addition of the Assignee and the resulting
adjustment of the Commitments arising therefrom. The Commitment allocated to each Assignee
shall reduce such Commitments of the assigning Lender pro tanto.
(e) Any Lender may at any time, with the written consent of Agent, sell to one or more
commercial banks, financial institutions, or other Persons not Affiliates of such Lender (a
Participant
) participating interests in its Obligations, the Commitment, and the other
rights and interests of that Lender (the
Originating Lender
) hereunder and under the other
Loan Documents (provided that no written consent of Agent shall be required in connection
with any sale of any such participating interests by a Lender to an Eligible Transferee);
provided
,
however
, that (i) the Originating Lender shall remain a Lender
for all purposes of this Agreement and the other Loan Documents and the Participant
receiving the participating interest in the Obligations, the Commitments, and the other
rights and interests of the Originating Lender hereunder shall not constitute a Lender
hereunder or under the other Loan Documents and the Originating Lenders obligations under
this Agreement shall remain unchanged, (ii) the Originating Lender shall remain solely
responsible for the performance of such obligations, (iii) Borrower, Agent, and the Lenders
shall continue to deal solely and directly with the Originating Lender in connection with
the Originating Lenders rights and obligations under this Agreement and the other Loan
Documents, (iv) no Lender shall transfer or grant any participating interest under which the
Participant has the right to approve any amendment to, or any consent or waiver with respect
to, this Agreement or any other Loan Document, except to the extent such amendment to, or
consent or waiver with respect to this Agreement or of any other Loan Document would (A)
extend the final maturity date of the Obligations hereunder in which such Participant is
participating, (B) reduce the interest rate applicable to the Obligations hereunder in which
such Participant is participating, (C) release all or a material portion of the Collateral
or guaranties (except to the extent expressly provided herein or in any of the Loan
Documents) supporting the Obligations hereunder in which such Participant is participating,
(D) postpone the payment of, or reduce the amount of, the interest or fees payable to such
Participant through such Lender, or (E) change the amount or due dates of scheduled
principal repayments or prepayments or premiums; and (v) all amounts payable by Borrower
hereunder shall be determined as if such Lender had not sold such participation; except
that, if amounts outstanding under this Agreement are due and unpaid, or shall have been
declared or shall have become due and payable upon the occurrence of an Event of Default,
each Participant shall be deemed to have the right of set-off in respect of its
participating interest in amounts owing under this Agreement to the same extent as if the
amount of its participating interest were owing directly to it as a Lender under this
Agreement. The rights of any Participant only shall be derivative through the Originating
Lender with whom such Participant participates and no Participant shall have any rights
under this Agreement or the other Loan Documents or any direct rights as to the other
Lenders, Agent, Borrower, the Collections, the Collateral, or otherwise in respect of the
Obligations. No Participant shall have the right to participate directly in the making of
decisions by the Lenders among themselves.
(f) In connection with any such assignment or participation or proposed assignment or
participation, a Lender may disclose all documents and information which it now or hereafter
may have relating to Borrower or Borrowers business.
(g) Any other provision in this Agreement notwithstanding, any Lender may at any time
create a security interest in, or pledge, all or any portion of its rights under and
interest in this Agreement in favor of any Federal Reserve Bank in accordance with
Regulation A of the Federal Reserve Bank or U.S. Treasury Regulation 31 CFR §203.14, and
such Federal Reserve Bank may enforce such pledge or security interest in any manner
permitted under applicable law.
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14.2.
Successors
. This Agreement shall bind and inure to the benefit of the
respective successors and assigns of each of the parties;
provided
,
however
, that
Borrower may not assign this Agreement or any rights or duties hereunder without the Lenders prior
written consent and any prohibited assignment shall be absolutely void ab initio. No consent to
assignment by the Lenders shall release Borrower from its Obligations. A Lender may assign this
Agreement and the other Loan Documents and its rights and duties hereunder and thereunder pursuant
to
Section 14.1
hereof and, except as expressly required pursuant to
Section 14.1
hereof, no consent or approval by Borrower is required in connection with any such assignment.
15. AMENDMENTS; WAIVERS.
15.1.
Amendments and Waivers
. No amendment or waiver of any provision of this
Agreement or any other Loan Document, and no consent with respect to any departure by Borrower
therefrom, shall be effective unless the same shall be in writing and signed by the Required
Lenders (or by Agent at the written request of the Required Lenders) and Borrower and then any such
waiver or consent shall be effective only in the specific instance and for the specific purpose for
which given;
provided
,
however
, that no such waiver, amendment, or consent shall,
unless in writing and signed by all of the Lenders affected thereby and Borrower and acknowledged
by Agent, do any of the following:
(a) increase or extend any Commitment of any Lender,
(b) postpone or delay any date fixed by this Agreement or any other Loan Document for
any payment of principal, interest, fees, or other amounts due hereunder or under any other
Loan Document,
(c) reduce the principal of, or the rate of interest on, any loan or other extension of
credit hereunder, or reduce any fees or other amounts payable hereunder or under any other
Loan Document,
(d) change the percentage of the Commitments that is required to take any action
hereunder,
(e) amend this Section or any provision of the Agreement providing for consent or other
action by all Lenders,
(f) release Collateral other than as permitted by
Section 16.12
,
(g) change the definition of Required Lenders,
(h) contractually subordinate any of the Agents Liens,
(i) release Borrower from any obligation for the payment of money,
(j) change the definition of Borrowing Base or change
Section 2.1(b)
, or
(k) amend any of the provisions of
Section 16
.
and,
provided further
,
however
, that no amendment, waiver or consent shall, unless
in writing and signed by Agent, Issuing Lender, or Swing Lender, affect the rights or duties of
Agent, Issuing Lender, or Swing Lender, as applicable, under this Agreement or any other Loan
Document. The foregoing notwithstanding, any amendment, modification, waiver, consent,
termination, or release of, or with
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respect to, any provision of this Agreement or any other Loan Document that relates only to the
relationship of the Lender Group among themselves, and that does not affect the rights or
obligations of Borrower, shall not require consent by or the agreement of Borrower.
15.2.
Replacement of Holdout Lender
. If any action to be taken by the Lender Group or
Agent hereunder requires the unanimous consent, authorization, or agreement of all Lenders, and a
Lender (
Holdout Lender
) fails to give its consent, authorization, or agreement, then Agent, upon
at least 5 Business Days prior irrevocable notice to the Holdout Lender, may permanently replace
the Holdout Lender with one or more substitute Lenders (each, a
Replacement Lender
), and the
Holdout Lender shall not have the right to refuse to be replaced hereunder. Such notice to replace
the Holdout Lender shall specify an effective date for such replacement, which date shall not be
later than 15 Business Days after the date such notice is given.
Prior to the effective date of such replacement, the Holdout Lender and each Replacement
Lender shall execute and deliver an Assignment and Acceptance Agreement, subject only to the
Holdout Lender being repaid its share of the outstanding Obligations (including an assumption of
its Pro Rata Share of the Risk Participation Liability) without any premium or penalty of any kind
whatsoever. If the Holdout Lender shall refuse or fail to execute and deliver any such Assignment
and Acceptance Agreement prior to the effective date of such replacement, the Holdout Lender shall
be deemed to have executed and delivered such Assignment and Acceptance Agreement. The replacement
of any Holdout Lender shall be made in accordance with the terms of
Section 14.1
. Until
such time as the Replacement Lenders shall have acquired all of the Obligations, the Commitments,
and the other rights and obligations of the Holdout Lender hereunder and under the other Loan
Documents, the Holdout Lender shall remain obligated to make the Holdout Lenders Pro Rata Share of
Advances and to purchase a participation in each Letter of Credit, in an amount equal to its Pro
Rata Share of the Risk Participation Liability of such Letter of Credit.
15.3.
No Waivers; Cumulative Remedies
. No failure by Agent or any Lender to exercise
any right, remedy, or option under this Agreement or, any other Loan Document, or delay by Agent or
any Lender in exercising the same, will operate as a waiver thereof. No waiver by Agent or any
Lender will be effective unless it is in writing, and then only to the extent specifically stated.
No waiver by Agent or any Lender on any occasion shall affect or diminish Agents and each Lenders
rights thereafter to require strict performance by Borrower of any provision of this Agreement.
Agents and each Lenders rights under this Agreement and the other Loan Documents will be
cumulative and not exclusive of any other right or remedy that Agent or any Lender may have.
16. AGENT; THE LENDER GROUP.
16.1.
Appointment and Authorization of Agent
. Each Lender hereby designates and
appoints Foothill as its representative under this Agreement and the other Loan Documents and each
Lender hereby irrevocably authorizes Agent to take such action on its behalf under the provisions
of this Agreement and each other Loan Document and to exercise such powers and perform such duties
as are expressly delegated to Agent by the terms of this Agreement or any other Loan Document,
together with such powers as are reasonably incidental thereto. Agent agrees to act as such on the
express conditions contained in this
Section 16
. The provisions of this
Section 16
are solely for the benefit of Agent, and the Lenders, and Borrower shall have no rights as a third
party beneficiary of any of the provisions contained herein. Any provision to the contrary
contained elsewhere in this Agreement or in any other Loan Document notwithstanding, Agent shall
not have any duties or responsibilities, except those expressly set forth herein, nor shall Agent
have or be deemed to have any fiduciary relationship with any Lender, and no implied covenants,
functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement
or any other Loan Document or otherwise exist against Agent; it being expressly
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understood and agreed that the use of the word Agent is for convenience only, that Foothill
is merely the representative of the Lenders, and only has the contractual duties set forth herein.
Except as expressly otherwise provided in this Agreement, Agent shall have and may use its sole
discretion with respect to exercising or refraining from exercising any discretionary rights or
taking or refraining from taking any actions that Agent expressly is entitled to take or assert
under or pursuant to this Agreement and the other Loan Documents. Without limiting the generality
of the foregoing, or of any other provision of the Loan Documents that provides rights or powers to
Agent, Lenders agree that Agent shall have the right to exercise the following powers as long as
this Agreement remains in effect: (a) maintain, in accordance with its customary business
practices, ledgers and records reflecting the status of the Obligations, the Collateral, the
Collections, and related matters, (b) execute or file any and all financing or similar statements
or notices, amendments, renewals, supplements, documents, instruments, proofs of claim, notices and
other written agreements with respect to the Loan Documents, (c) make Advances, for itself or on
behalf of Lenders as provided in the Loan Documents, (d) exclusively receive, apply, and distribute
the Collections as provided in the Loan Documents, (e) open and maintain such bank accounts and
cash management accounts as Agent deems necessary and appropriate in accordance with the Loan
Documents for the foregoing purposes with respect to the Collateral and the Collections, (f)
perform, exercise, and enforce any and all other rights and remedies of the Lender Group with
respect to Borrower, the Obligations, the Collateral, the Collections, or otherwise related to any
of same as provided in the Loan Documents, and (g) incur and pay such Lender Group Expenses as
Agent may deem necessary or appropriate for the performance and fulfillment of its functions and
powers pursuant to the Loan Documents.
16.2.
Delegation of Duties
. Agent may execute any of its duties under this Agreement
or any other Loan Document by or through agents, employees or attorneys-in-fact and shall be
entitled to advice of counsel concerning all matters pertaining to such duties. Agent shall not be
responsible for the negligence or misconduct of any agent or attorney-in-fact that it selects as
long as such selection was made without gross negligence or willful misconduct.
16.3.
Liability of Agent
. None of the Agent-Related Persons shall (i) be liable for
any action taken or omitted to be taken by any of them under or in connection with this Agreement
or any other Loan Document or the transactions contemplated hereby (except for its own gross
negligence or willful misconduct), or (ii) be responsible in any manner to any of the Lenders for
any recital, statement, representation or warranty made by Borrower or any Subsidiary or Affiliate
of Borrower, or any officer or director thereof, contained in this Agreement or in any other Loan
Document, or in any certificate, report, statement or other document referred to or provided for
in, or received by Agent under or in connection with, this Agreement or any other Loan Document, or
the validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement or any
other Loan Document, or for any failure of Borrower or any other party to any Loan Document to
perform its obligations hereunder or thereunder. No Agent-Related Person shall be under any
obligation to any Lender to ascertain or to inquire as to the observance or performance of any of
the agreements contained in, or conditions of, this Agreement or any other Loan Document, or to
inspect the Books or properties of Borrower or the books or records or properties of Borrowers
Subsidiaries or Affiliates.
16.4.
Reliance by Agent
. Agent shall be entitled to rely, and shall be fully
protected in relying, upon any writing, resolution, notice, consent, certificate, affidavit,
letter, telegram, facsimile, telex or telephone message, statement or other document or
conversation believed by it to be genuine and correct and to have been signed, sent, or made by the
proper Person or Persons, and upon advice and statements of legal counsel (including counsel to
Borrower or counsel to any Lender), independent accountants and other experts selected by Agent.
Agent shall be fully justified in failing or refusing to take any action under this Agreement or
any other Loan Document unless Agent shall first receive such advice or concurrence of the Lenders
as it deems appropriate and until such instructions are received,
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Agent shall act, or refrain from acting, as it deems advisable. If Agent so requests, it
shall first be indemnified to its reasonable satisfaction by Lenders against any and all liability
and expense that may be incurred by it by reason of taking or continuing to take any such action.
Agent shall in all cases be fully protected in acting, or in refraining from acting, under this
Agreement or any other Loan Document in accordance with a request or consent of the Lenders and
such request and any action taken or failure to act pursuant thereto shall be binding upon all of
the Lenders.
16.5.
Notice of Default or Event of Default
. Agent shall not be deemed to have
knowledge or notice of the occurrence of any Default or Event of Default, except with respect to
defaults in the payment of principal, interest, fees, and expenses required to be paid to Agent for
the account of the Lenders, except with respect to Events of Default of which Agent has actual
knowledge, unless Agent shall have received written notice from a Lender or Borrower referring to
this Agreement, describing such Default or Event of Default, and stating that such notice is a
notice of default. Agent promptly will notify the Lenders of its receipt of any such notice or
of any Event of Default of which Agent has actual knowledge. If any Lender obtains actual
knowledge of any Event of Default, such Lender promptly shall notify the other Lenders and Agent of
such Event of Default. Each Lender shall be solely responsible for giving any notices to its
Participants, if any. Subject to
Section 16.4
, Agent shall take such action with respect
to such Default or Event of Default as may be requested by the Required Lenders in accordance with
Section 9
;
provided
,
however
, that unless and until Agent has received any
such request, Agent may (but shall not be obligated to) take such action, or refrain from taking
such action, with respect to such Default or Event of Default as it shall deem advisable.
16.6.
Credit Decision
. Each Lender acknowledges that none of the Agent-Related
Persons has made any representation or warranty to it, and that no act by Agent hereinafter taken,
including any review of the affairs of Borrower and its Subsidiaries or Affiliates, shall be deemed
to constitute any representation or warranty by any Agent-Related Person to any Lender. Each
Lender represents to Agent that it has, independently and without reliance upon any Agent-Related
Person and based on such documents and information as it has deemed appropriate, made its own
appraisal of and investigation into the business, prospects, operations, property, financial and
other condition and creditworthiness of Borrower and any other Person (other than the Lender Group)
party to a Loan Document, and all applicable bank regulatory laws relating to the transactions
contemplated hereby, and made its own decision to enter into this Agreement and to extend credit to
Borrower. Each Lender also represents that it will, independently and without reliance upon any
Agent-Related Person and based on such documents and information as it shall deem appropriate at
the time, continue to make its own credit analysis, appraisals and decisions in taking or not
taking action under this Agreement and the other Loan Documents, and to make such investigations as
it deems necessary to inform itself as to the business, prospects, operations, property, financial
and other condition and creditworthiness of Borrower and any other Person (other than the Lender
Group) party to a Loan Document. Except for notices, reports, and other documents expressly herein
required to be furnished to the Lenders by Agent, Agent shall not have any duty or responsibility
to provide any Lender with any credit or other information concerning the business, prospects,
operations, property, financial and other condition or creditworthiness of Borrower and any other
Person party to a Loan Document that may come into the possession of any of the Agent-Related
Persons.
16.7.
Costs and Expenses; Indemnification
. Agent may incur and pay Lender Group
Expenses to the extent Agent reasonably deems necessary or appropriate for the performance and
fulfillment of its functions, powers, and obligations pursuant to the Loan Documents, including
court costs, reasonable attorneys fees and expenses, fees and expenses of financial accountants,
advisors, consultants, and appraisers, costs of collection by outside collection agencies and
auctioneer fees and costs of security guards or insurance premiums paid to maintain the Collateral,
whether or not Borrower is obligated to reimburse Agent or Lenders for such expenses pursuant to
the Credit Agreement or
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otherwise. Agent is authorized and directed to deduct and retain sufficient amounts from
Collections received by Agent to reimburse Agent for such out-of-pocket costs and expenses prior to
the distribution of any amounts to Lenders. In the event Agent is not reimbursed for such costs
and expenses from Collections received by Agent, each Lender hereby agrees that it is and shall be
obligated to pay to or reimburse Agent for the amount of such Lenders Pro Rata Share thereof.
Whether or not the transactions contemplated hereby are consummated, the Lenders shall indemnify
upon demand the Agent-Related Persons (to the extent not reimbursed by or on behalf of Borrower and
without limiting the obligation of Borrower to do so), according to their Pro Rata Shares, from and
against any and all Indemnified Liabilities;
provided
,
however
, that no Lender
shall be liable for the payment to any Agent-Related Person of any portion of such Indemnified
Liabilities resulting solely from such Persons gross negligence or willful misconduct nor shall
any Lender be liable for the obligations of any Defaulting Lender in failing to make an Advance or
other extension of credit hereunder. Without limitation of the foregoing, each Lender shall
reimburse Agent upon demand for such Lenders ratable share of any costs or out-of-pocket expenses
(including attorneys, accountants, advisors, and consultants fees and expenses) incurred by Agent
in connection with the preparation, execution, delivery, administration, modification, amendment,
or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice
in respect of rights or responsibilities under, this Agreement, any other Loan Document, or any
document contemplated by or referred to herein, to the extent that Agent is not reimbursed for such
expenses by or on behalf of Borrower. The undertaking in this Section shall survive the payment of
all Obligations hereunder and the resignation or replacement of Agent.
16.8.
Agent in Individual Capacity
. Foothill and its Affiliates may make loans to,
issue letters of credit for the account of, accept deposits from, acquire equity interests in, and
generally engage in any kind of banking, trust, financial advisory, underwriting, or other business
with Borrower and its Subsidiaries and Affiliates and any other Person (other than the Lender
Group) party to any Loan Documents as though Foothill were not Agent hereunder, and, in each case,
without notice to or consent of the other members of the Lender Group. The other members of the
Lender Group acknowledge that, pursuant to such activities, Foothill or its Affiliates may receive
information regarding Borrower or its Affiliates and any other Person (other than the Lender Group)
party to any Loan Documents that is subject to confidentiality obligations in favor of Borrower or
such other Person and that prohibit the disclosure of such information to the Lenders, and the
Lenders acknowledge that, in such circumstances (and in the absence of a waiver of such
confidentiality obligations, which waiver Agent will use its reasonable best efforts to obtain),
Agent shall not be under any obligation to provide such information to them. The terms
Lender
and
Lenders
include Foothill in its individual capacity.
16.9.
Successor Agent
. Agent may resign as Agent upon 45 days notice to the Lenders.
If Agent resigns under this Agreement, the Required Lenders shall appoint a successor Agent for the
Lenders. If no successor Agent is appointed prior to the effective date of the resignation of
Agent, Agent may appoint, after consulting with the Lenders, a successor Agent. If Agent has
materially breached or failed to perform any material provision of this Agreement or of applicable
law, the Required Lenders may agree in writing to remove and replace Agent with a successor Agent
from among the Lenders. In any such event, upon the acceptance of its appointment as successor
Agent hereunder, such successor Agent shall succeed to all the rights, powers, and duties of the
retiring Agent and the term Agent shall mean such successor Agent and the retiring Agents
appointment, powers, and duties as Agent shall be terminated. After any retiring Agents
resignation hereunder as Agent, the provisions of this
Section 16
shall inure to its
benefit as to any actions taken or omitted to be taken by it while it was Agent under this
Agreement. If no successor Agent has accepted appointment as Agent by the date which is 45 days
following a retiring Agents notice of resignation, the retiring Agents resignation shall
nevertheless thereupon become effective and the Lenders shall perform all of the duties of Agent
hereunder until such time, if any, as the Lenders appoint a successor Agent as provided for above.
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16.10.
Lender in Individual Capacity
. Any Lender and its respective Affiliates may
make loans to, issue letters of credit for the account of, accept deposits from, acquire equity
interests in and generally engage in any kind of banking, trust, financial advisory, underwriting
or other business with Borrower and its Subsidiaries and Affiliates and any other Person (other
than the Lender Group) party to any Loan Documents as though such Lender were not a Lender
hereunder without notice to or consent of the other members of the Lender Group. The other members
of the Lender Group acknowledge that, pursuant to such activities, such Lender and its respective
Affiliates may receive information regarding Borrower or its Affiliates and any other Person (other
than the Lender Group) party to any Loan Documents that is subject to confidentiality obligations
in favor of Borrower or such other Person and that prohibit the disclosure of such information to
the Lenders, and the Lenders acknowledge that, in such circumstances (and in the absence of a
waiver of such confidentiality obligations, which waiver such Lender will use its reasonable best
efforts to obtain), such Lender shall not be under any obligation to provide such information to
them. With respect to the Swing Loans and Agent Advances, Swing Lender shall have the same rights
and powers under this Agreement as any other Lender and may exercise the same as though it were not
the sub-agent of the Agent.
16.11.
Withholding Taxes
.
(a) If any Lender is a foreign corporation, partnership or trust within the meaning
of the IRC and such Lender claims exemption from, or a reduction of, U.S. withholding tax
under Sections 1441 or 1442 of the IRC, such Lender agrees with and in favor of Agent and
Borrower, to deliver to Agent and Borrower:
(i) if such Lender claims an exemption from withholding tax pursuant to its
portfolio interest exception, (a) a statement of the Lender, signed under penalty of
perjury, that it is not a (I) bank as described in Section 881(c)(3)(A) of the
IRC, (II) 10% shareholder (within the meaning of Section 881(c)(3)(B) of the IRC),
or (III) controlled foreign corporation described in Section 881(c)(3)(C) of the
IRC, and (B) a properly completed IRS Form W-8BEN, before the first payment of any
interest under this Agreement and at any other time reasonably requested by Agent or
Borrower;
(ii) if such Lender claims an exemption from, or a reduction of, withholding
tax under a United States tax treaty, properly completed IRS Form W-8BEN before the
first payment of any interest under this Agreement and at any other time reasonably
requested by Agent or Borrower;
(iii) if such Lender claims that interest paid under this Agreement is exempt
from United States withholding tax because it is effectively connected with a United
States trade or business of such Lender, two properly completed and executed copies
of IRS Form W-8ECI before the first payment of any interest is due under this
Agreement and at any other time reasonably requested by Agent or Borrower;
(iv) such other form or forms as may be required under the IRC or other laws of
the United States as a condition to exemption from, or reduction of, United States
withholding tax.
Such Lender agrees promptly to notify Agent and Borrower of any change in circumstances which would
modify or render invalid any claimed exemption or reduction.
(b) If any Lender claims exemption from, or reduction of, withholding tax under a
United States tax treaty by providing IRS Form W-8BEN and such Lender sells, assigns, grants
a
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participation in, or otherwise transfers all or part of the Obligations of Borrower to
such Lender, such Lender agrees to notify Agent of the percentage amount in which it is no
longer the beneficial owner of Obligations of Borrower to such Lender. To the extent of
such percentage amount, Agent will treat such Lenders IRS Form W-8BEN as no longer valid.
(c) If any Lender is entitled to a reduction in the applicable withholding tax, Agent
may withhold from any interest payment to such Lender an amount equivalent to the applicable
withholding tax after taking into account such reduction. If the forms or other
documentation required by subsection (a) of this Section are not delivered to Agent, then
Agent may withhold from any interest payment to such Lender not providing such forms or
other documentation an amount equivalent to the applicable withholding tax.
(d) If the IRS or any other Governmental Authority of the United States or other
jurisdiction asserts a claim that Agent did not properly withhold tax from amounts paid to
or for the account of any Lender (because the appropriate form was not delivered, was not
properly executed, or because such Lender failed to notify Agent of a change in
circumstances which rendered the exemption from, or reduction of, withholding tax
ineffective, or for any other reason) such Lender shall indemnify and hold Agent harmless
for all amounts paid, directly or indirectly, by Agent as tax or otherwise, including
penalties and interest, and including any taxes imposed by any jurisdiction on the amounts
payable to Agent under this Section, together with all costs and expenses (including
attorneys fees and expenses). The obligation of the Lenders under this subsection shall
survive the payment of all Obligations and the resignation or replacement of Agent.
(e) All payments made by Borrower hereunder or under any note or other Loan Document
will be made without setoff, counterclaim, or other defense, except as required by
applicable law other than for Taxes (as defined below). All such payments will be made free
and clear of, and without deduction or withholding for, any present or future taxes, levies,
imposts, duties, fees, assessments or other charges of whatever nature now or hereafter
imposed by any jurisdiction (other than the United States) or by any political subdivision
or taxing authority thereof or therein (other than of the United States) with respect to
such payments (but excluding, any tax imposed by any jurisdiction or by any political
subdivision or taxing authority thereof or therein (i) measured by or based on the net
income or net profits of a Lender, or (ii) to the extent that such tax results from a change
in the circumstances of the Lender, including a change in the residence, place of
organization, or principal place of business of the Lender, or a change in the branch or
lending office of the Lender participating in the transactions set forth herein) and all
interest, penalties or similar liabilities with respect thereto (all such non-excluded
taxes, levies, imposts, duties, fees, assessments or other charges being referred to
collectively as
Taxes
). If any Taxes are so levied or imposed, Borrower agrees to pay the
full amount of such Taxes, and such additional amounts as may be necessary so that every
payment of all amounts due under this Agreement or under any note, including any amount paid
pursuant to this
Section 16.11(e)
after withholding or deduction for or on account
of any Taxes, will not be less than the amount provided for herein;
provided
,
however
, that Borrower shall not be required to increase any such amounts payable to
Agent or any Lender (i) that is not organized under the laws of the United States, if such
Person fails to comply with the other requirements of this
Section 16.11
, or (ii) if
the increase in such amount payable results from Agents or such Lenders own willful
misconduct or gross negligence. Borrower will furnish to Agent as promptly as possible
after the date the payment of any Taxes is due pursuant to applicable law certified copies
of tax receipts evidencing such payment by Borrower.
16.12.
Collateral Matters
.
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(a) The Lenders hereby irrevocably authorize Agent, at its option and in its sole
discretion, to release any Lien on any Collateral (i) upon the termination of the
Commitments and payment and satisfaction in full by Borrower of all Obligations, (ii)
constituting property being sold or disposed of if a release is required or desirable in
connection therewith and if Borrower certifies to Agent that the sale or disposition is
permitted under
Section 7.4
of this Agreement or the other Loan Documents (and Agent
may rely conclusively on any such certificate, without further inquiry), (iii) constituting
property in which Borrower does not own any interest at the time the security interest was
granted or at any time thereafter, or (iv) constituting property leased to Borrower under a
lease that has expired or is terminated in a transaction permitted under this Agreement.
Except as provided above, Agent will not execute and deliver a release of any Lien on any
Collateral without the prior written authorization of (y) if the release is of all or
substantially all of the Collateral, all of the Lenders, or (z) otherwise, the Required
Lenders. Upon request by Agent or Borrower at any time, the Lenders will confirm in writing
Agents authority to release any such Liens on particular types or items of Collateral
pursuant to this
Section 16.12
;
provided
,
however
, that (1) Agent
shall not be required to execute any document necessary to evidence such release on terms
that, in Agents opinion, would expose Agent to liability or create any obligation or entail
any consequence other than the release of such Lien without recourse, representation, or
warranty, and (2) such release shall not in any manner discharge, affect, or impair the
Obligations or any Liens (other than those expressly being released) upon (or obligations of
Borrower in respect of) all interests retained by Borrower, including, the proceeds of any
sale, all of which shall continue to constitute part of the Collateral.
(b) Agent shall have no obligation whatsoever to any of the Lenders to assure that the
Collateral exists or is owned by Borrower or any of its Subsidiaries or is cared for,
protected, or insured or has been encumbered, or that the Agents Liens have been properly
or sufficiently or lawfully created, perfected, protected, or enforced or are entitled to
any particular priority, or to exercise at all or in any particular manner or under any duty
of care, disclosure or fidelity, or to continue exercising, any of the rights, authorities
and powers granted or available to Agent pursuant to any of the Loan Documents, it being
understood and agreed that in respect of the Collateral, or any act, omission, or event
related thereto, subject to the terms and conditions contained herein, Agent may act in any
manner it may deem appropriate, in its sole discretion given Agents own interest in the
Collateral in its capacity as one of the Lenders and that Agent shall have no other duty or
liability whatsoever to any Lender as to any of the foregoing, except as otherwise provided
herein.
16.13.
Restrictions on Actions by Lenders; Sharing of Payments
.
(a) Each of the Lenders agrees that it shall not, without the express consent of Agent,
and that it shall, to the extent it is lawfully entitled to do so, upon the request of
Agent, set off against the Obligations, any amounts owing by such Lender to any Borrower or
any deposit accounts of Borrower now or hereafter maintained with such Lender. Each of the
Lenders further agrees that it shall not, unless specifically requested to do so by Agent,
take or cause to be taken any action, including, the commencement of any legal or equitable
proceedings, to foreclose any Lien on, or otherwise enforce any security interest in, any of
the Collateral the purpose of which is, or could be, to give such Lender any preference or
priority against the other Lenders with respect to the Collateral.
(b) If, at any time or times any Lender shall receive (i) by payment, foreclosure,
setoff, or otherwise, any proceeds of Collateral or any payments with respect to the
Obligations arising under, or relating to, this Agreement or the other Loan Documents,
except for any such proceeds or payments received by such Lender from Agent pursuant to the
terms of this
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Agreement, or (ii) payments from Agent in excess of such Lenders ratable portion of
all such distributions by Agent, such Lender promptly shall (1) turn the same over to Agent,
in kind, and with such endorsements as may be required to negotiate the same to Agent, or in
immediately available funds, as applicable, for the account of all of the Lenders and for
application to the Obligations in accordance with the applicable provisions of this
Agreement, or (2) purchase, without recourse or warranty, an undivided interest and
participation in the Obligations owed to the other Lenders so that such excess payment
received shall be applied ratably as among the Lenders in accordance with their Pro Rata
Shares;
provided
,
however
, that if all or part of such excess payment
received by the purchasing party is thereafter recovered from it, those purchases of
participations shall be rescinded in whole or in part, as applicable, and the applicable
portion of the purchase price paid therefor shall be returned to such purchasing party, but
without interest except to the extent that such purchasing party is required to pay interest
in connection with the recovery of the excess payment.
16.14.
Agency for Perfection
. Agent hereby appoints each other Lender as its agent
(and each Lender hereby accepts such appointment) for the purpose of perfecting the Agents Liens
in assets which, in accordance with Article 9 of the Code can be perfected only by possession.
Should any Lender obtain possession of any such Collateral, such Lender shall notify Agent thereof,
and, promptly upon Agents request therefor shall deliver such Collateral to Agent or in accordance
with Agents instructions.
16.15.
Payments by Agent to the Lenders
. All payments to be made by Agent to the
Lenders shall be made by bank wire transfer or internal transfer of immediately available funds
pursuant to such wire transfer instructions as each party may designate for itself by written
notice to Agent. Concurrently with each such payment, Agent shall identify whether such payment
(or any portion thereof) represents principal, premium, or interest of the Obligations.
16.16.
Concerning the Collateral and Related Loan Documents
. Each member of the
Lender Group authorizes and directs Agent to enter into this Agreement and the other Loan Documents
relating to the Collateral, for the benefit of the Lender Group. Each member of the Lender Group
agrees that any action taken by Agent in accordance with the terms of this Agreement or the other
Loan Documents relating to the Collateral and the exercise by Agent of its powers set forth therein
or herein, together with such other powers that are reasonably incidental thereto, shall be binding
upon all of the Lenders.
16.17.
Field Audits and Examination Reports; Confidentiality; Disclaimers by Lenders;
Other Reports and Information
.
By becoming a party to this Agreement, each Lender:
(a) is deemed to have requested that Agent furnish such Lender, promptly after it
becomes available, a copy of each field audit or examination report (each a
Report
and
collectively,
Reports
) prepared by Agent, and Agent shall so furnish each Lender with such
Reports,
(b) expressly agrees and acknowledges that Agent does not (i) make any representation
or warranty as to the accuracy of any Report, and (ii) shall not be liable for any
information contained in any Report,
(c) expressly agrees and acknowledges that the Reports are not comprehensive audits or
examinations, that Agent or other party performing any audit or examination will inspect
only specific information regarding Borrower and will rely significantly upon the Books, as
well as on representations of Borrowers personnel,
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(d) agrees to keep all Reports and other material, non-public information regarding
Borrower and its Subsidiaries and their operations, assets, and existing and contemplated
business plans in a confidential manner; it being understood and agreed by Borrower that in
any event such Lender may make disclosures (i) to counsel for and other advisors,
accountants, and auditors to such Lender, (ii) reasonably required by any bona fide
potential or actual Assignee or Participant in connection with any contemplated or actual
assignment or transfer by such Lender of an interest herein or any participation interest in
such Lenders rights hereunder, (iii) of information that has become public by disclosures
made by Persons other than such Lender, its Affiliates, assignees, transferees, or
Participants, or (iv) as required or requested by any court, governmental or administrative
agency, pursuant to any subpoena or other legal process, or by any law, statute, regulation,
or court order;
provided
,
however
, that, unless prohibited by applicable
law, statute, regulation, or court order, such Lender shall notify Borrower of any request
by any court, governmental or administrative agency, or pursuant to any subpoena or other
legal process for disclosure of any such non-public material information concurrent with, or
where practicable, prior to the disclosure thereof, and
(e) without limiting the generality of any other indemnification provision contained in
this Agreement, agrees: (i) to hold Agent and any such other Lender preparing a Report
harmless from any action the indemnifying Lender may take or conclusion the indemnifying
Lender may reach or draw from any Report in connection with any loans or other credit
accommodations that the indemnifying Lender has made or may make to Borrower, or the
indemnifying Lenders participation in, or the indemnifying Lenders purchase of, a loan or
loans of Borrower; and (ii) to pay and protect, and indemnify, defend and hold Agent, and
any such other Lender preparing a Report harmless from and against, the claims, actions,
proceedings, damages, costs, expenses, and other amounts (including, attorneys fees and
costs) incurred by Agent and any such other Lender preparing a Report as the direct or
indirect result of any third parties who might obtain all or part of any Report through the
indemnifying Lender.
In addition to the foregoing: (x) any Lender may from time to time request of Agent in writing
that Agent provide to such Lender a copy of any report or document provided by Borrower to Agent
that has not been contemporaneously provided by Borrower to such Lender, and, upon receipt of such
request, Agent shall provide a copy of same to such Lender, (y) to the extent that Agent is
entitled, under any provision of the Loan Documents, to request additional reports or information
from Borrower, any Lender may, from time to time, reasonably request Agent to exercise such right
as specified in such Lenders notice to Agent, whereupon Agent promptly shall request of Borrower
the additional reports or information reasonably specified by such Lender, and, upon receipt
thereof from Borrower, Agent promptly shall provide a copy of same to such Lender, and (z) any time
that Agent renders to Borrower a statement regarding the Loan Account, Agent shall send a copy of
such statement to each Lender.
16.18.
Several Obligations; No Liability
. Notwithstanding that certain of the Loan
Documents now or hereafter may have been or will be executed only by or in favor of Agent in its
capacity as such, and not by or in favor of the Lenders, any and all obligations on the part of
Agent (if any) to make any credit available hereunder shall constitute the several (and not joint)
obligations of the respective Lenders on a ratable basis, according to their respective
Commitments, to make an amount of such credit not to exceed, in principal amount, at any one time
outstanding, the amount of their respective Commitments. Nothing contained herein shall confer
upon any Lender any interest in, or subject any Lender to any liability for, or in respect of, the
business, assets, profits, losses, or liabilities of any other Lender. Each Lender shall be solely
responsible for notifying its Participants of any matters relating to the Loan Documents to the
extent any such notice may be required, and no Lender shall have any obligation, duty, or liability
to any Participant of any other Lender. Except as provided in
Section 16.7
, no member of
the Lender Group shall have any liability for the acts of any other member of the Lender Group. No
Lender
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shall be responsible to Borrower or any other Person for any failure by any other Lender to
fulfill its obligations to make credit available hereunder, nor to advance for it or on its behalf
in connection with its Commitment, nor to take any other action on its behalf hereunder or in
connection with the financing contemplated herein.
16.19.
Bank Product Providers
. Each Bank Product Provider shall be deemed a party
hereto for purposes of any reference in a Loan Document to the parties for whom Agent is acting; it
being understood and agreed that the rights and benefits of such Bank Product Provider under the
Loan Documents consist exclusively of such Bank Product Providers right to share in payments and
collections out of the Collateral as more fully set forth herein. In connection with any such
distribution of payments and collections, Agent shall be entitled to assume no amounts are due to
any Bank Product Provider unless such Bank Product Provider has notified Agent in writing of the
amount of any such liability owed to it prior to such distribution.
16.20.
Legal Representation of Agent
. In connection with the negotiation, drafting,
and execution of this Agreement and the other Loan Documents, or in connection with future legal
representation relating to loan administration, amendments, modifications, waivers, or enforcement
of remedies, Munsch Hardt Kopf & Harr, P.C. (
Munsch Hardt
) only has represented and only shall
represent Foothill in its capacity as Agent and as a Lender. Each other Lender hereby acknowledges
that Munsch Hardt does not represent it in connection with any such matters.
17. GENERAL PROVISIONS.
17.1.
Effectiveness
. This Agreement shall be binding and deemed effective when
executed by Borrower, the Pledging Subsidiaries, Agent, and each Lender whose signature is provided
for on the signature pages hereof.
17.2.
Section Headings
. Headings and numbers have been set forth herein for
convenience only. Unless the contrary is compelled by the context, everything contained in each
Section applies equally to this entire Agreement.
17.3.
Interpretation
. Neither this Agreement nor any uncertainty or ambiguity herein
shall be construed or resolved against the Lender Group or Borrower, whether under any rule of
construction or otherwise. On the contrary, this Agreement has been reviewed by all parties and
shall be construed and interpreted according to the ordinary meaning of the words used so as to
accomplish fairly the purposes and intentions of all parties hereto.
17.4.
Severability of Provisions
. Each provision of this Agreement shall be severable
from every other provision of this Agreement for the purpose of determining the legal
enforceability of any specific provision.
17.5.
Amendments in Writing
. This Agreement only can be amended by a writing in
accordance with
Section 15.1
.
17.6.
Counterparts; Telefacsimile Execution
. This Agreement may be executed in any
number of counterparts and by different parties on separate counterparts, each of which, when
executed and delivered, shall be deemed to be an original, and all of which, when taken together,
shall constitute but one and the same Agreement. Delivery of an executed counterpart of this
Agreement by telefacsimile shall be equally as effective as delivery of an original executed
counterpart of this Agreement. Any party delivering an executed counterpart of this Agreement by
telefacsimile also shall deliver an original executed counterpart of this Agreement but the failure
to deliver an original executed counterpart shall
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not affect the validity, enforceability, and binding effect of this Agreement. The foregoing
shall apply to each other Loan Document
mutatis mutandis
.
17.7.
Revival and Reinstatement of Obligations
. If the incurrence or payment of the
Obligations by Borrower or the transfer to the Lender Group of any property should for any reason
subsequently be declared to be void or voidable under any state or federal law relating to
creditors rights, including provisions of the Bankruptcy Code relating to fraudulent conveyances,
preferences, or other voidable or recoverable payments of money or transfers of property
(collectively, a
Voidable Transfer
), and if the Lender Group is required to repay or restore, in
whole or in part, any such Voidable Transfer, or elects to do so upon the reasonable advice of its
counsel, then, as to any such Voidable Transfer, or the amount thereof that the Lender Group is
required or elects to repay or restore, and as to all reasonable costs, expenses, and attorneys
fees of the Lender Group related thereto, the liability of Borrower automatically shall be revived,
reinstated, and restored and shall exist as though such Voidable Transfer had never been made.
17.8.
Confidentiality
. Agent and Lenders each individually (and not jointly or
jointly and severally) agree that material, non-public information regarding Borrower and its
Subsidiaries, their operations, assets, and existing and contemplated business plans shall be
treated by Agent and the Lenders in a confidential manner, and shall not be disclosed by Agent and
the Lenders to Persons who are not parties to this Agreement, except: (a) to attorneys for and
other advisors, accountants, auditors, and consultants to any member of the Lender Group, (b) to
Subsidiaries and Affiliates of any member of the Lender Group (including the Bank Product
Providers), provided that any such Subsidiary or Affiliate shall have agreed to receive such
information hereunder subject to the terms of this
Section 17.8
, (c) as may be required by
statute, decision, or judicial or administrative order, rule, or regulation, (d) as may be agreed
to in advance by Borrower or its Subsidiaries or as requested or required by any Governmental
Authority pursuant to any subpoena or other legal process, (e) as to any such information that is
or becomes generally available to the public (other than as a result of prohibited disclosure by
Agent or the Lenders), (f) in connection with any assignment, prospective assignment, sale,
prospective sale, participation or prospective participations, or pledge or prospective pledge of
any Lenders interest under this Agreement, provided that any such assignee, prospective assignee,
purchaser, prospective purchaser, participant, prospective participant, pledgee, or prospective
pledgee shall have agreed in writing to receive such information hereunder subject to the terms of
this Section, and (g) in connection with any litigation or other adversary proceeding involving
parties hereto which such litigation or adversary proceeding involves claims related to the rights
or duties of such parties under this Agreement or the other Loan Documents. The provisions of this
Section 17.8
shall survive for 2 years after the payment in full of the Obligations.
17.9.
Integration
. This Agreement, together with the other Loan Documents, reflects
the entire understanding of the parties with respect to the transactions contemplated hereby and
shall not be contradicted or qualified by any other agreement, oral or written, before the date
hereof.
17.10.
License to Gathering Systems
. In the event that the Gathering Systems are
foreclosed upon pursuant to the Mortgages, Agent, on behalf of Lenders, hereby grants to each
Pledging Subsidiary a non-royalty bearing license to transport Hydrocarbons produced from Wells not
included within the Mortgaged Properties under any then existing agreement regarding transport and
for the life of such transportation agreement or in the absence of a written agreement consistent
with the past practices and customs of the parties in the industry.
17.11.
Agency of the Borrower for Each Pledging Subsidiary
. Each of the Pledging
Subsidiaries irrevocably appoints the Borrower as its agent for all purposes relevant to this
Agreement, including the giving and receipt of notices and execution and delivery of all documents,
instruments, and
-95-
certificates contemplated herein (including, without limitation, execution and delivery to the
Agent of Reserve Reports and all modifications hereto). Any acknowledgment, consent, direction,
certification, or other action which might otherwise be valid or effective only if given or taken
by all or any of the Borrower and the Pledging Subsidiaries or acting singly, shall be valid and
effective if given or taken only by the Borrower, whether or not any of the Pledging Subsidiaries
joins therein, and the Agent and the Lenders shall have no duty or obligation to make further
inquiry with respect to the authority of the Borrower under this
Section 17.11
, provided
that nothing in this
Section 17.11
shall limit the effectiveness of, or the right of the
Agent and the Lenders to rely upon, any notice, document, instrument, certificate, acknowledgment,
consent, direction, certification, or other action delivered by any Pledging Subsidiary pursuant to
this Agreement.
17.12.
Development Projects
. Nothing contained in the Loan Documents shall prohibit
any Pledging Subsidiary from developing any Oil and Gas Properties that do not constitute
Collateral.
17.13.
Reserve Arbitration
. In the event of any dispute as to the amount of a reserve
established by Agent under
Section 2.1(b)
clauses (i) through (vi) inclusive, Agent and
Borrower shall use good faith efforts to resolve any such dispute through full and meaningful
discussions, which shall include one face-to-face meeting and a written exchange of positions. In
the event this written exchange indicates that the dispute cannot be resolved, the dispute shall be
referred to arbitration in the city of Atlanta, Georgia by one arbitrator (selected by the American
Arbitration Association but having extensive work experience in establishing such type of reserves
under oil and gas secured credit facilities), in accordance with the provisions set forth herein
and the Commercial Arbitration Rules of the American Arbitration Association then in effect. The
decision of the arbitrator shall establish the amount of such reserve.
17.14.
USA PATRIOT Act
.
Each Lender that is subject to the requirements of the USA
Patriot Act (Title 111 of Pub. L. 107-56 (signed into law October 26, 2001)) (the
Act
)
hereby notifies Borrower that pursuant to the requirements of the Act, it is required to obtain,
verify and record information that identifies Borrower, which information includes the name and
address of Borrower and other information that will allow such Lender to identify Borrower in
accordance with the Act.
[Signature page to follow.]
-96-
IN WITNESS WHEREOF,
the parties hereto have caused this Agreement to be executed and
delivered as of the date first above written.
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ENERGY CORPORATION OF AMERICA
,
a West Virginia corporation
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By:
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/s/ Michael
S. Fletcher
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Name:
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Michael
S. Fletcher
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Title:
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CFO
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WELLS FARGO FOOTHILL, INC.
,
a California corporation, as Agent and as a Lender
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By:
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/s/ Gary
Forlenza
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Name:
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Gary
Forlenza
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Title:
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VP
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BANK OF AMERICA, N.A.
,
as a Lender
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By:
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/s/ Charles
W. Patterson
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Name:
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Charles
W. Patterson
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Title:
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Managing
Director
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For purposes of acknowledging agreement to the terms, provisions, and conditions of this
Agreement (including, without limitation, the terms of
Section 17.11
, Eastern American and
A&W are executing this Agreement.
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EASTERN AMERICAN ENERGY CORPORATION
,
a West Virginia corporation
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By:
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/s/ Donald
C. Suploe
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Name:
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Donald
C. Suploe
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Title:
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President
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ALLEGHENY & WESTERN ENERGY CORPORATION
,
a West Virginia corporation
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By:
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/s/ Donald
C. Suploe
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Name:
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Donald
C. Suploe
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Title:
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President
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Signature Page
EXHIBIT A-1
FORM OF ASSIGNMENT AND ACCEPTANCE AGREEMENT
This
ASSIGNMENT AND ACCEPTANCE AGREEMENT
(
Assignment Agreement
) is entered into as
of
between
(
Assignor
) and
(
Assignee
). Reference is made to the Agreement
described in
Item 2
of
Annex I
annexed hereto (the
Credit Agreement
).
Capitalized terms used herein and not otherwise defined shall have the meanings ascribed to them in
the Credit Agreement.
1. In accordance with the terms and conditions of
Section 14
of the Credit Agreement,
the Assignor hereby sells and assigns to the Assignee, and the Assignee hereby purchases and
assumes from the Assignor, that interest in and to the Assignors rights and obligations under the
Loan Documents as of the date hereof with respect to the Obligations owing to the Assignor, and
Assignors portion of the Total Commitments and the Revolver Commitments, all as specified in
Item 4.b
and
Item 4.c
of
Annex I
. After giving effect to such sale and
assignments, the Assignees portion of the Total Commitments and Revolver Commitments will be as
set forth in
Item 4.b
of
Annex I
. After giving effect to such sale and assignment,
the Assignors amount and portion of the Total Commitments and Revolver Commitments will be as set
forth in
Item 4.d
and
Item 4.e
of
Annex I
.
2. The Assignor (a) represents and warrants that it is the legal and beneficial owner of the
interest being assigned by it hereunder and that such interest is free and clear of any adverse
claim; (b) makes no representation or warranty and assumes no responsibility with respect to any
statements, warranties or representations made in or in connection with the Loan Documents or the
execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan
Documents or any other instrument or document furnished pursuant thereto; and (c) makes no
representation or warranty and assumes no responsibility with respect to the financial condition of
Borrower or the performance or observance by Borrower of any of its obligations under the Loan
Documents or any other instrument or document furnished pursuant thereto.
3. The Assignee (a) confirms that it has received copies of the Credit Agreement and the other
Loan Documents, together with copies of the financial statements referred to therein and such other
documents and information as it has deemed appropriate to make its own credit analysis and decision
to enter into this Assignment Agreement; (b) agrees that it will, independently and without
reliance, as it shall deem appropriate at the time, continue to make its own credit decisions in
taking or not taking action under the Loan Documents; (c) confirms that it is eligible as an
assignee under the terms of the Credit Agreement; (d) appoints and authorizes the Agent to take
such action as agent on its behalf and to exercise such powers under the Loan Documents as are
delegated to Agent by the terms thereof, together with such powers as are reasonably incidental
thereto; (e) agrees that it will perform in accordance with their terms all of the obligations
which by the terms of the Loan Documents are required to be performed by it as a Lender[; and (f)
attaches the forms prescribed by the Internal Revenue Service of the United States certifying as to
the Assignees status for purposes of determining exemption from United States withholding taxes
with respect to all payments to be made to the Assignee under the Credit Agreement or such other
documents as are necessary to indicate that all such payments are subject to such rates at a rate
reduced by an applicable tax treaty.]
4. Following the execution of this Assignment Agreement by the Assignor and Assignee, it will
be delivered by the Assignor to the Agent for recording by the Agent. The effective date of this
Assignment (the
Settlement Date
) shall be the later of (a) the date of the execution hereof by
the Assignor and the Assignee, the payment by Assignor or Assignee to Agent for Agents sole and
separate
EXHIBIT A-1
Page
1
account a processing fee in the amount of $5,000, and the receipt of any required consent of
the Agent, and (b) the date specified in
Item 5
of
Annex I
.
5. Upon recording by the Agent, as of the Settlement Date (a) the Assignee shall be a party to
the Credit Agreement and, to the extent of the interest assigned pursuant to this Assignment
Agreement, have the rights and obligations of a Lender thereunder and under the other Loan
Documents, and (b) the Assignor shall, to the extent of the interest assigned pursuant to this
Assignment Agreement, relinquish its rights and be released from its obligations under the Credit
Agreement and the other Loan Documents.
6. Upon recording by the Agent, from and after the Settlement Date, the Agent shall make all
payments under the Credit Agreement and the other Loan Documents in respect of the interest
assigned hereby (including, without limitation, all payments of principal, interest and commitment
fees (if applicable) with respect thereto) to the Assignee. Upon the Settlement Date, the Assignee
shall pay to the Assignor the Assigned Share (as set forth in
Item 4.b
of
Annex I
)
of the principal amount of any outstanding loans under the Credit Agreement and the other Loan
Documents. The Assignor and Assignee shall make all appropriate adjustments in payments under the
Credit Agreement and the other Loan Documents for periods prior to the Settlement Date directly
between themselves on the Settlement Date.
7. THIS ASSIGNMENT AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED AND ENFORCED IN ACCORDANCE
WITH, THE LAWS OF THE STATE OF
.
[Remainder of page left intentionally blank.]
EXHIBIT A-1
Page
2
IN WITNESS WHEREOF, the parties hereto have caused this Assignment Agreement and
Annex I
hereto to be executed by their respective officers thereunto duly authorized, as of
the first date above written.
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[NAME OF ASSIGNOR]
as Assignor
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By:
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Title:
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[NAME OF ASSIGNEE]
as Assignee
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By:
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Title:
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ACCEPTED THIS _____ DAY
OF
WELLS FARGO FOOTHILL, INC.
AS AGENT
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By:
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Title:
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EXHIBIT A-1
Page
3
ANNEX FOR ASSIGNMENT AND ACCEPTANCE AGREEMENT
ANNEX I
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1.
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Borrower
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2.
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Name and Date of Credit Agreement:
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Second Amended and Restated Credit Agreement dated as of September
7, 2007, among Borrower, the lenders signatory thereto as the
Lenders, and Wells Fargo Foothill, Inc., a California corporation,
as the arranger and administrative agent for the Lenders.
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3.
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Date of Assignment Agreement
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4
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Amounts:
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a.
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Assignors Total Commitment
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$
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Assignors Revolver Commitment
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$
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Assignors Term Loan Commitment
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$
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b.
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Assigned Share of Total Commitment
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%
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Assigned Share of Revolver Commitment
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%
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Assigned Share of Term Loan Commitment
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%
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c.
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Assigned Amount of Total Commitment
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$
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Assigned Amount of Revolver Commitment
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$
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Assigned Amount of Term Loan Commitment
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$
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d.
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Resulting Amount of Assignors Total Commitment after giving effect to the sale
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and Assignment to Assignee
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$
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Resulting Amount of Assignors Revolver Commitment
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$
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Resulting Amount of Assignors Term Loan Commitment
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$
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e.
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Assignors Resulting Share of Total Commitment after giving effect to the
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Assignment to Assignee
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%
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Assignors Resulting Share of Revolving
Commitment
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%
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Assignors Resulting Share of Term Loan
Commitment
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%
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EXHIBIT A-1
Page
4
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5.
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Settlement Date
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6.
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Notice and Payment Instructions, etc.
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Assignee:
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Assignor
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7
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Agreed and Accepted:
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[ASSIGNOR]
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[ASSIGNEE]
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By:
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By:
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Title:
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Title:
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Accepted:
WELLS FARGO FOOTHILL, INC., as Agent
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By:
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Title:
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EXHIBIT A-1
Page
5
EXHIBIT C-1
(Form of Compliance Certificate)
[on Borrowers letterhead]
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To:
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Wells Fargo Foothill, Inc., as Agent
under the below-referenced Credit Agreement
1110 Abernathy Road, Suite 1600
Atlanta, Georgia 30328
Attn.: Business Finance Division Manager
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Re:
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Compliance Certificate dated
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Ladies and Gentlemen:
Reference is made to that certain Second Amended and Restated Credit Agreement dated as of
September 7, 2007 (the
Credit Agreement
) among Energy Corporation of America, a West
Virginia corporation (the
Borrower
), the lender or lenders signatory thereto (the
Lenders
), and Wells Fargo Foothill, Inc., a California corporation, as the arranger and
administrative agent for the Lenders (
Agent
). Capitalized terms used in this Compliance
Certificate have the meanings set forth in the Credit Agreement unless specifically defined herein.
Pursuant to
Section 6.3
of the Credit Agreement, the undersigned officer of the
Borrower hereby certifies that:
1. The financial information of the Borrower furnished in
Schedule 1
attached hereto,
has been prepared in accordance with GAAP (except for year end adjustments and the lack of
footnotes, in the case of financial statements delivered under
Section 6.3(a)
of the Credit
Agreement) and fairly presents in all material respects the financial condition of the Borrower.
2. Such officer has reviewed the terms of the Credit Agreement and has made, or caused to be
made under his/her supervision, a review in reasonable detail of the transactions and condition of
the Borrower during the accounting period covered by the financial statements delivered pursuant to
Section 6.3
of the Credit Agreement.
3. Such review has not disclosed the existence on and as of the date hereof, and the
undersigned does not have knowledge of the existence as of the date hereof, of any event or
condition that constitutes a Default or Event of Default, except for such conditions or events
listed on
Schedule 2
attached hereto, specifying the nature and period of existence thereof
and what action the Borrower has taken, is taking, or proposes to take with respect thereto.
4. The representations and warranties of the Borrower contained in the Credit Agreement and
the other Loan Documents are true and correct in all material respects on and as of the date of
such certificate, as though made on and as of such date (except to the extent that such
representations and warranties relate solely to an earlier date). Without limiting the generality
of the foregoing, the Borrower is in compliance with the covenants contained in
Section
7.20
of the Credit Agreement as demonstrated on
Schedule 2
hereof.
EXHIBIT C-1
Page
1
IN WITNESS WHEREOF, this Compliance Certificate is executed by the undersigned this ___ day
of
, 200___.
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ENERGY CORPORATION OF AMERICA
,
a West Virginia corporation,
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By:
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Name:
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Title:
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EXHIBIT C-1
Page
2
SCHEDULE 1
EXHIBIT C-1
Schedule
1
SCHEDULE 2
1.
Minimum EBITDAX
. Borrowers EBITDAX (on a consolidated basis), on a rolling
four-quarter basis ending
,
is $
, which amount
[is/is not]
greater
than or equal to the amount set forth in
Section 7.
20(a)(i)
of the Credit Agreement for the
corresponding period.
2.
Book Net Worth
. Borrowers Book Net Worth (on a consolidated basis), for the
quarter ending
,
is $
, which amount
[is/is not]
greater than or
equal to the amount required in
Section 7.
20(a)(ii)
of the Credit Agreement for the
corresponding period.
3.
Maximum Capital Expenditures
. If applicable under
Section 7.20(b)
of the
Credit Agreement, the aggregate amount of capital expenditures made or committed to be made to date
in the current fiscal year is $
, which amount
[is/is not]
in excess of 120% of
Projections set forth in
Section 7.20(b)
of the Credit Agreement for the corresponding
period.
EXHIBIT C-1
Schedule
2
EXHIBIT L-1
FORM OF LIBOR NOTICE
Wells Fargo Foothill, Inc., as Agent
under the below referenced Credit Agreement
2450 Colorado Avenue
Suite 3000 West
Santa Monica, California 90404
Attention:
Ladies and Gentlemen:
Reference is made to that certain Second Amended and Restated Credit Agreement dated as of
September 7, 2007 (the
Credit Agreement
) among Energy Corporation of America, a West
Virginia corporation (the
Borrower
), the lender or lenders signatory thereto (the
Lenders
), and Wells Fargo Foothill, Inc., a California corporation, as the arranger and
administrative agent for the Lenders (
Agent
). Capitalized terms used in this LIBOR
Notice have the meanings set forth in the Credit Agreement unless specifically defined herein.
This LIBOR Notice represents Borrowers request to elect the LIBOR Option with respect to
outstanding Advances in the amount of $
(the
LIBOR Rate Advance
)[, and is a
written confirmation of the telephonic notice of such election given to Agent].
Such LIBOR Rate Advance will have an Interest Period of 1, 3, 6 or 12 month(s) commencing on
.
This LIBOR Notice further confirms Borrowers acceptance, for purposes of determining the rate
of interest based on the LIBOR Rate under the Credit Agreement, of the LIBOR Rate as determined
pursuant to the Credit Agreement.
Exhibit L-1
Page
1
Borrower represents and warrants that (i) as of the date hereof, each representation or
warranty contained in or pursuant to any Loan Document, any agreement, instrument, certificate,
document or other writing furnished at any time under or in connection with any Loan Document, and
as of the effective date of any advance, continuation or conversion requested above is true and
correct in all material respects (except to the extent any representation or warranty expressly
related to an earlier date), (ii) each of the covenants and agreements contained in any Loan
Document have been performed (to the extent required to be performed on or before the date hereof
or each such effective date), and (iii) no Default or Event of Default has occurred and is
continuing on the date hereof, nor will any thereof occur after giving effect to the request above.
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Dated:
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ENERGY CORPORATION OF AMERICA
,
a West Virginia corporation,
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By:
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Name:
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Title:
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Acknowledged by:
WELLS FARGO FOOTHILL, INC.
as Agent
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By:
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Name:
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Title:
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Exhibit L-1
Page
2
SCHEDULE C-1
COMMITMENTS
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Lender
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Revolver Commitment
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Term Loan
Commitment
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Total Commitment
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Wells Fargo
Foothill, Inc.
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$
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50,000,000
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$
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50,000,000
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$
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100,000,000
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Bank of America, N.A.
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$
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50,000,000
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$
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50,000,000
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$
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100,000,000
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All Lenders
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$
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100,000,000
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$
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100,000,000
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$
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200,000,000
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Schedule C-1
Page
1
SCHEDULE D-1
DESIGNATED ACCOUNT
Account number _____ of Borrower maintained with the Designated Account Bank, or such other deposit
account of Borrower (located within the United States) that has been designated as such, in writing
by, Borrower to Agent.
Designated Account Bank means Wells Fargo Bank, National Association.
Schedule D-1
Page Solo
SCHEDULE P-1
PARTNERSHIPS
PARTNERSHIP OR JOINT VENTURE
Arcadia Drilling Fund, a limited partnership
Arcadia Drilling Fund No. 2, a limited partnership
Arcadia Drilling Fund No. 3, a limited partnership
Arcadia Drilling Fund No. 4, a general partnership
Arcadia Drilling Fund No. 6, a general partnership
Arcadia Drilling Fund No. 7, a general partnership
Bent Branch Project, a general partnership
Bevins Branch Partners Ltd.
Number II, Bevins Branch, Ltd.
Burning Fork Partners, a general partnership
Drift Branch Project
Eastern Producing Limited Partnership
Feds Creek Gas Project, a joint venture
JBC Drilling Company No. 4
JBC Drill Co. No. 5
Long Branch Partners, a general partnership
Lowe Farm Project, Ltd.
Marshalls Branch Partners, Ltd., a limited partnership
Shelby Creek Partners, Ltd., a limited partnership
Swinge Camp General Partners
Swinge Camp Partners
Sycamore Creek Partners
VICC Mineral Project No. 8 an unincorporated joint venture
Willow River Fund (aka Consol Partnership No. One)
Wisconsin Fund Partnership Number One
Schedule P-1 Page 1
SCHEDULE 2.7(a)
CASH MANAGEMENT BANKS
Wells Fargo Bank, National Association
Schedule
2.7(A)
Page 1
SCHEDULE 5.1(a)
BORROWING BASE PROPERTIES
[see attached]
Schedule
5.1(a)
Page 1
SCHEDULE 5.1(b)
MATERIAL CONTRACTS
[see attached]
Schedule
5.1(b)
Page 1
SCHEDULE 5.7
CHIEF EXECUTIVE OFFICE AND FEIN OF BORROWER AND SUBSIDIARIES
[see attached]
Schedule 5.7 Page 1
SCHEDULE 5.8(b)
CAPITALIZATION OF BORROWER
[see attached]
Schedule
5.8(b)
Page 1
SCHEDULE 5.8(c)
CAPITALIZATION OF BORROWERS SUBSIDIARIES
[see attached]
Schedule
5.8(c)
Page 1
SCHEDULE 5.10
LITIGATION
[see attached]
Schedule
5.10
Page 1
SCHEDULE 5.14
ENVIRONMENTAL MATTERS
[see attached]
Schedule 5.14 Page 1
SCHEDULE 5.16
INTELLECTUAL PROPERTY
[see attached]
Schedule 5.16 Page 1
SCHEDULE 5.18
DEMAND DEPOSIT ACCOUNTS
[see attached]
Schedule 5.18 Page 1
SCHEDULE 5.20
PERMITTED INDEBTEDNESS
[see attached]
Schedule 5.20 Page 1
SCHEDULE 5.22
TAXES
[see attached]
Schedule 5.22 Page 1
SCHEDULE 5.23
INSURANCE
[see attached]
Schedule 5.23 Page 1
SCHEDULE 5.25
CLAIMS AND LIABILITIES
[see attached]
Schedule 5.25 Page 1
SCHEDULE 5.26(b)
CUMULATIVE IMBALANCES IN GAS PRODUCTION AND TAKE OR PAY PAYMENTS
[see attached]
Schedule
5.26(b)
Page 1
SCHEDULE 5.27
Operations of Borrowing Base Properties
[see attached]
Schedule 5.27 Page 1
SCHEDULE 5.28
HEDGING AGREEMENTS
[see attached]
Schedule 5.28 Page 1
SCHEDULE 6.2(c)
TOTAL VALUE OF TOTAL PROVED DEVELOPED PRODUCING PRESERVES
[see attached]
Schedule
6.2(c)
Page 1
SCHEDULE 7.2
LIENS
[see attached]
Schedule 7.2 Page 1
SCHEDULE 7.13
EXISTING INVESTMENTS
[see attached]
Schedule 7.13 Page 1