Nevada
|
88-0422242
|
|
(State
or other jurisdiction of incorporation or organization)
|
(I.R.S.
Employer Identification
No.)
|
27
Corporate Woods, Suite 350
|
|
10975
Grandview Drive
|
|
Overland
Park, Kansas
|
66210
|
(Address
of principal executive offices)
|
(Zip
Code)
|
7300
W. 110
th
,
7
th
Floor
|
|
Overland
Park, Kansas
|
66210
|
(Former
Address of principal executive offices)
|
(Zip
Code)
|
Large
accelerated filer
¨
|
Accelerated
filer
¨
|
|
Non-accelerated
filer
¨
(Do not check if a smaller reporting company)
|
|
Smaller
reporting company
x
|
Page
|
|||
PART
I
|
2
|
||
Items
1 and 2.
|
Business
and Properties
|
2
|
|
Item
1A.
|
Risk
Factors
|
28
|
|
Item
1B.
|
Unresolved
Staff Comments
|
48
|
|
Item
3.
|
Legal
Proceedings
|
48
|
|
Item
4.
|
Submission
of Matters to a Vote of Security Holders
|
48
|
|
PART
II
|
49
|
||
Item
5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
49
|
|
Item
6.
|
Selected
Financial Data
|
51
|
|
Item
7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
51
|
|
Item
7A.
|
Quantitative
and Qualitative Disclosures about Market Risk
|
65
|
|
Item
8.
|
Financial
Statements and Supplementary Data
|
66
|
|
Item
9.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
66
|
|
Item
9A(T).
|
Controls
and Procedures
|
66
|
|
Item
9B.
|
Other
Information
|
67
|
|
Part
III
|
67
|
||
Item
10.
|
Directors,
Executive Officers and Corporate Governance
|
67
|
|
Item
11.
|
Executive
Compensation
|
72
|
|
Item
12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
74
|
|
Item
13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
76
|
|
Item
14.
|
Principal
Accountant Fees and Services
|
76
|
|
Part
IV
|
78
|
||
Item
15.
|
|
Exhibits,
Financial Statement Schedules
|
78
|
|
·
|
inability
to attract and obtain additional development
capital;
|
|
·
|
inability
to achieve sufficient future sales levels or other operating
results;
|
|
·
|
inability
to efficiently manage our
operations;
|
|
·
|
potential
default under our secured obligations or material debt
agreements;
|
|
·
|
estimated
quantities and quality of oil and natural gas
reserves;
|
|
·
|
declining
local, national and worldwide economic
conditions;
|
|
·
|
fluctuations
in the price of oil and natural
gas;
|
|
·
|
the
inability of management to effectively implement our strategies and
business plans;
|
|
·
|
approval
of certain parts of our operations by state
regulators;
|
|
·
|
inability
to hire or retain sufficient qualified operating field
personnel;
|
|
·
|
increases
in interest rates or our cost of
borrowing;
|
|
·
|
deterioration
in general or regional (especially Eastern Kansas) economic
conditions;
|
|
·
|
occurrence
of natural disasters, unforeseen weather conditions, or other events or
circumstances that could impact our operations or could impact the
operations of companies or contractors we depend upon in our
operations;
|
|
·
|
inability
to acquire mineral leases at a favorable economic value that will allow us
to expand our development efforts;
|
|
·
|
adverse
state or federal legislation or regulation that increases the costs of
compliance, or adverse findings by a regulator with respect to existing
operations; and
|
|
·
|
changes
in U.S. GAAP or in the legal, regulatory and legislative environments in
the markets in which we operate.
|
|
·
|
Traditional Roll-Up
Strategy.
We are seeking to employ a traditional roll-up
strategy utilizing a combination of capital resources, operational and
management expertise, technology, and our strategic partnership with Haas
Petroleum, which has experience operating in the region for nearly 70
years.
|
|
·
|
Numerous Acquisition
Opportunities.
There are many small producers and owners
of mineral rights in the region, which afford us numerous opportunities to
pursue negotiated lease transactions instead of having to competitively
bid on fundamentally sound assets.
|
|
·
|
Fragmented Ownership
Structure.
There are numerous opportunities to acquire
producing properties at attractive prices, because of the currently
inefficient and fragmented ownership
structure.
|
Project Name
|
Developed Acreage
|
Undeveloped Acreage
|
Total Acreage
|
|||||||||||||||||||||
Gross
|
Net
(1)
|
Gross
|
Net
(1)
|
Gross
|
Net
(1)
|
|||||||||||||||||||
Black
Oaks Project
|
550 | 522 | 1,850 | 1,758 | 2,400 | 2,280 | ||||||||||||||||||
Thoren
Project
|
135 | 135 | 591 | 591 | 726 | 726 | ||||||||||||||||||
DD
Energy Project
|
400 | 400 | 1,370 | 1,370 | 1,770 | 1,770 | ||||||||||||||||||
Tri-County
Project
|
610 | 606 | 652 | 651 | 1,262 | 1,257 | ||||||||||||||||||
Gas
City Project
|
600 | 600 | 4,713 | 4,713 | 5,313 | 5,313 | ||||||||||||||||||
Total
|
2,295 | 2,263 | 9,176 | 9,083 | 11,471 | 11,346 |
|
(1)
|
Net
acreage is based on our net working interest as of March 31,
2009.
|
Gross STB
(1)
|
Net STB
(2)
|
PV10
(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
420,080 | 197,640 | $ | 3,781,690 | ||||||||
Proved,
Developed Non-Producing
|
50,440 | 30,450 | $ | 650,430 | ||||||||
Proved,
Undeveloped
|
875,300 | 352,370 | $ | 944,100 | ||||||||
Total
Proved
|
1,345,820 | 580,460 | $ | 5,376,220 |
|
(3)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for a reconciliation to the comparable GAAP
financial measure.
|
Gross STB
(1)
|
Net STB
(2)
|
PV10
(3)
(before tax)
|
||||||
Proved,
Developed Producing
|
48,030
|
24,600
|
$
|
539,510
|
||||
Proved,
Developed Non-Producing
|
24,920
|
7,690
|
$
|
146,490
|
||||
Proved,
Undeveloped
|
43,020
|
37,640
|
$
|
85,970
|
||||
Total
Proved
|
115,970
|
69,930
|
$
|
771,970
|
|
(1)
|
STB = one stock-tank
barrel.
|
|
(2)
|
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.
|
|
(3)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for a reconciliation to the comparable GAAP
financial measure.
|
Gross STB
(1)
|
Net STB
(2)
|
PV10
(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
75,510 | 64,700 | $ | 972,220 | ||||||||
Proved,
Developed Non-Producing
|
23,070 | 19,470 | $ | 183,090 | ||||||||
Proved,
Undeveloped
|
39,390 | 31,840 | $ | 85,030 | ||||||||
Total
Proved
|
137,970 | 116,010 | $ | 1,240,340 |
|
(1)
|
STB = one stock-tank
barrel.
|
|
(2)
|
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.
|
|
(3)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for a reconciliation to the comparable
GAAP financial measure.
|
Gross STB
(1)
|
Net STB
(2)
|
PV10
(3)
(before tax)
|
||||||||||
Proved,
Developed Producing
|
177,560 | 141,330 | $ | 1,369,700 | ||||||||
Proved,
Developed Non-Producing
|
48,190 | 37,940 | $ | 479,270 | ||||||||
Proved,
Undeveloped
|
474,210 | 380,030 | $ | 1,361,430 | ||||||||
Total
Proved
|
699,960 | 559,300 | $ | 3,210,400 |
|
(1)
|
STB = one stock-tank
barrel.
|
|
(2)
|
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.
|
|
(3)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for a reconciliation to the comparable
GAAP financial measure.
|
|
·
|
Euramerica
was granted an extension until January 15, 2009 (with no further
grace periods) to pay the remaining $600,000 of the purchase price for its
option to purchase an approximately 6,600 acre portion of the Gas City
Project and $1.5 million in previously due development funds for the Gas
City Project;
|
|
·
|
If
Euramerica fails to fully fund both the purchase price and these
development funds by January 15, 2009, Euramerica will lose all rights to
the Gas City Project and assets and there will be no payout from
the revenue of the wells on this
project;
|
|
·
|
The
oil zones and production from such oil zones in two oil
wells then became 100% owned by
EnerJex;
|
|
·
|
We
may deduct from the development funds all amounts owed to us prior to
applying the funds to any actual
development;
|
|
·
|
Euramerica
specifically recognized that we can shut in or stop the development of the
project if the project is not producing in paying quantities or if the
project is operating at a loss. The decision to shut in the project and
cease all operations was made on October 15,
2008; and
|
|
·
|
If
Euramerica funds the remaining portion of the purchase price for its
option and the development funds in the Gas City Project on or before
January 15, 2009, “Payout” as used in the Assignment and other documents
is now based on “drilling and completion costs on a well-by-well
basis.”
|
Gross
STB
(1)
|
Net
STB
(2)
|
Gross
MCF
(3)
|
Net
MCF
(4)
|
PV10
(5)
(before tax)
|
||||||||||||||||
Proved,
Developed Producing
|
1,400 | 1,150 | - | - | $ | 28,430 | ||||||||||||||
Proved,
Developed Non-Producing
|
- | - | - | - | $ | - | ||||||||||||||
Proved,
Undeveloped
|
11,850 | 9,780 | - | - | $ | 1,970 | ||||||||||||||
Total
Proved
|
13,250 | 10,930 | - | - | $ | 30,400 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.
|
|
(3)
|
MCF = thousand cubic feet of
natural gas. There were no natural gas reserves at March 31,
2009.
|
|
(4)
|
Net MCF is based upon our net
revenue interest. There were no natural gas reserves at March
31, 2009.
|
|
(5)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for reconciliation to the comparable GAAP
financial measure.
|
|
·
|
Develop Our Existing
Properties.
We intend to create reserve and production
growth from over 400 additional drilling locations we have identified on
our properties. We have identified an additional 193
drillable producer locations and 213 drillable injector
locations. The structure and the continuous oil accumulation in
Eastern Kansas, and the expected long-life production and reserves of our
properties,
are
anticipated to enhance our opportunities for long-term
profitability.
|
|
·
|
Maximize Operational
Control.
We seek to operate our properties and maintain
a substantial working interest. We believe the ability to control our
drilling inventory will provide us with the opportunity to more
efficiently allocate capital, manage resources, control operating and
development costs, and utilize our experience and knowledge of oilfield
technologies.
|
|
·
|
Pursue Selective Acquisitions
and Joint Ventures.
Due to our local presence in Eastern
Kansas and strategic partnership with Haas Petroleum, we believe we are
well-positioned to pursue selected acquisitions, subject to availability
of capital, from the fragmented and capital-constrained owners of mineral
rights throughout Eastern Kansas.
|
|
·
|
Reduce Unit Costs Through
Economies of Scale and Ef
ficient
Operations.
As we increase our oil production and
develop our existing properties, we expect that our unit cost structure
will benefit from economies of scale. In particular, we anticipate
reducing unit costs by greater utilization of our existing infrastructure
over a larger number of wells.
|
|
·
|
Acquisition and Development
Strategy.
We have what we believe to be a relatively
low-risk acquisition and development strategy compared to some of our
competitors. We generally buy properties that have proven current
production, with a projected pay-back within a relatively short period of
time, and with potential growth and upside in terms of development,
enhancement and efficiency. We also plan to minimize the risk of natural
gas and oil price volatility by developing a sales portfolio of pricing
for our production as it expands and as market conditions
permit.
|
|
·
|
Significant Production Growth
Opportunities.
We have acquired an attractive acreage
position with favorable lease terms in a region with historical
hydrocarbon production. Based on drilling success we have had within our
acreage position and subject to availability of capital, we expect to
increase our reserves, production and cash
flow.
|
|
·
|
Experienced Management Team
and Strategic Partner with Strong Technical
Capability.
Our CEO has over 20 years of experience in
the energy industry, primarily related to gas/electric utilities, but
including experience related to energy trading and production, and members
of our board of directors have considerable industry experience and
technical expertise in engineering, horizontal drilling, geoscience and
field operations. In addition, our strategic partner, Haas Petroleum, has
over 70 years of experience in Eastern Kansas, including completion and
secondary recovery techniques and technologies. Our board of directors and
Mark Haas of Haas Petroleum work closely with management during the
initial phases of any major project to ensure its feasibility and to
consider the appropriate recovery techniques to be
utilized.
|
|
·
|
Incentivized Management
Ownership.
The equity ownership of our directors and
executive officers is strongly aligned with that of our stockholders. As
of July 14, 2009, our directors and executive officers owned approximately
9.1% of our outstanding common stock, with options that upon exercise
would increase their ownership of our outstanding common stock to
15.6%.
|
|
·
|
On March 6, 2008 we
entered into an agreement with Shell Trading (US) Company,
or
Shell, whereby we agreed to an 18-month fixed-price swap with Shell for
130 BOPD at a fixed price per barrel of $96.90, before transportation
costs from April 1, 2008 through September 30, 2009. This represented
approximately 60% of our total oil production on a net revenue basis at
that time and locked in approximately $6.8 million in gross revenue before
transportation costs over the 18 month period. In addition, we agreed to
sell all of our remaining oil production at current spot market pricing
beginning April 1, 2008 through September 30, 2009 to
Shell. For the fiscal year ended March 31, 2009, the positive
impact on our net revenue from the fixed-price swap was approximately
$506,000.
|
|
·
|
On
July 3, 2008, EnerJex, EnerJex Kansas, and DD Energy entered into a
three-year $50 million Senior Secured Credit Facility (the “Credit
Facility”) with Texas Capital Bank, N.A. Borrowings under the
Credit Facility will be subject to a borrowing base limitation based on
our current proved oil and gas reserves and will be subject to semi-annual
redeterminations and other interim adjustments. The initial
borrowing base was set at $10.75 million and was reduced to $7.428 million
following the liquidation of the BP hedging instrument in November
2008. The borrowing base was reviewed by Texas Capital Bank in
February 2009 and it was determined that it shall be reduced by $200,000
per month beginning April 2009 with the expectation that this
monthly reduction would continue through December 2009. We had borrowings
$7.328 million outstanding at March 31, 2009. Subsequent to
year-end, we have made an additional $200,000 of payments to reduce the
borrowing base. The Credit Facility is secured by a lien on
substantially all assets of the Company and its subsidiaries. The Credit
Facility has a term of three years, and matures on July 3,
2011. The Credit Facility also provides for the issuance of
letters-of-credit up to a $750,000 sub-limit under the borrowing base and
up to an additional $2.25 million limit not subject to the borrowing base
to support our hedging program.
|
|
·
|
On
July 7, 2008, we amended the $2.7 million of aggregate principal amount of
our 10% debentures that remain outstanding to, among other things, permit
the indebtedness under our Credit Facility, subordinate the security
interests of the debentures to the Credit Facility, provide for the
redemption of the remaining debentures with the net proceeds from any next
debt or equity offering, eliminate the covenant to maintain certain
production thresholds and waive all known defaults. Subsequent
to year-end, we again amended the debentures to extend the maturity date
to September 30, 2010, to allow us to pay interest in either cash or
payment-in-kind interest (an increase in the amount of principal due) or
payment of interest through the issuance of shares of common stock, and
add a provision for the conversion of the debentures into shares of our
common stock.
Through May 31, 2010
the conversion price per share equals $3.00. From
June 1, 2010
through t
he Maturity Date,
assuming the d
ebenture has not
been redeemed,
the conversion
price
per share equal
s
that price which
shall be computed as 100.0% of the arithmetic average of the Weighted
Average Price of the Common Stock on each of the thirty (30) consecutive
Trading Days immediately preceding the Conversion Date, and considering
adjustments, if any, as specified in the
amendment.
|
|
·
|
As
of July 3, 2008, we entered into an ISDA master agreement and a costless
collar with BP Corporation North America Inc., or BP, for 130 barrels of
oil per day with a price floor of $132.50 per barrel and a price ceiling
of $155.70 per barrel for NYMEX West Texas Intermediate for the
period of October 1, 2009 until March 31, 2011. We liquidated
this costless collar in November 2008 and received proceeds of
approximately $3.9 million from BP. We reduced the debt
outstanding under our Credit Facility by approximately $3.3 million and
used the remainder for general operating
purposes.
|
|
·
|
On
August 1, 2008, we executed three-year employment agreements with C.
Stephen Cochennet, our chief executive officer, and Dierdre P. Jones, our
chief financial officer. Mr. Cochennet and Ms. Jones have
agreed to amend their employment agreements to reflect options rescinded
in November 2008.
|
|
·
|
Euramerica
failed to fully fund by January 15, 2009 both the balance of the purchase
price and the remaining development capital owed under the Amended and
Restated Well Development Agreement and Option for “Gas City Property”
between us and Euramerica. Therefore, Euramerica has forfeited
all of its interest in the property, including all interests in any wells,
improvements or assets, and all of Euramerica's interest in the property
reverts back to us. In addition, all operating agreements
between us and Euramerica relating to the Gas City Project are null and
void.
|
|
·
|
In
February 2009, we entered into a fixed price swap transaction under the
terms of the BP ISDA for a total of 120,000 gross barrels at a price of
$57.30 per barrel before transportation costs for the period beginning
October 1, 2009 and ending on December 31,
2013.
|
|
·
|
We
recorded a non-cash impairment of $4,777,723 to the carrying value of our
proved oil and gas properties during the fiscal year ended March 31, 2009.
The impairment is primarily attributable to lower prices for both oil and
natural gas. The charge results from the application of the
“ceiling test” under the full cost method of accounting at December 31,
2008. Under full cost accounting requirements, the carrying value may not
exceed an amount equal to the sum of the present value of estimated future
net revenues (adjusted for cash flow hedges) less estimated future
expenditures to be incurred in developing and producing the proved
reserves, less any related income tax effects. In calculating future net
revenues, current prices and costs used are those as of the end of the
appropriate quarterly period. Such prices are utilized except where
different prices are fixed and determinable from applicable contracts for
the remaining term of those contracts, including the effects of
derivatives qualifying as cash flow hedges. A ceiling test charge occurs
when the carrying value of the oil and gas properties exceeds the full
cost ceiling.
|
|
·
|
We
accrued but did not pay interest due at March 31, 2009 to our subordinated
debenture holders on the $2.7 million outstanding as of that
date. Subsequent to year-end, we agreed to pay the accrued
interest on a payment-in-kind
basis.
|
Drilling Activity
|
||||||||||||||||||||||||
Gross Wells
|
Net Wells
(1)
|
|||||||||||||||||||||||
Fiscal Year
|
Total
|
Producing
|
Dry
|
Total
|
Producing
|
Dry
|
||||||||||||||||||
2007
Exploratory
|
-0- | -0- | -0- | -0- | -0- | -0- | ||||||||||||||||||
2008
Exploratory
|
10 | 10 | -0- | 10 | 10 | -0- | ||||||||||||||||||
2009
Exploratory
(2)
|
12 | 12 | -0- | 12 | 12 | -0- | ||||||||||||||||||
2007
Development
|
-0- | -0- | -0- | -0- | -0- | -0- | ||||||||||||||||||
2008
Development
|
59 | 57 | 2 | 58 | 56 | 2 | ||||||||||||||||||
2009
Development
|
96 | 95 | 1 | 96 | 95 | 1 |
|
(1)
|
Net
wells are based on our net working interest as of March 31,
2009.
|
|
(2)
|
We
incurred some exploration costs related to exploratory wells drilled on
behalf of Euramerica.
|
Fiscal Year Ended
March 31, 2009
|
Fiscal Year Ended
March 31, 2008
|
Fiscal Year Ended
March 31,2007
|
||||||||||
Net Production
|
||||||||||||
Oil
(Bbl)
|
74,289 | 43,697 | -0- | |||||||||
Natural
gas (Mcf)
|
12,275 | 17,762 | 19,254 | |||||||||
Average
Sales Prices
|
||||||||||||
Oil
(per Bbl)
|
$ | 85.67 | $ | 79.71 | $ | -0- | ||||||
Natural
gas (per Mcf)
|
$ | 5.57 | $ | 6.20 | $ | 4.72 | ||||||
Average
Production Cost
(1)
|
||||||||||||
Per
Bbl of oil
|
$ | 45.01 | $ | 56.65 | $ | -0- | ||||||
Per
Mcf of natural gas
|
$ | 15.11 | $ | 13.12 | $ | 9.55 | ||||||
Average
Lifting Costs
(2)
|
||||||||||||
Per
Bbl of oil
|
$ | 33.01 | $ | 37.08 | $ | -0- | ||||||
Per
Mcf of natural gas
|
$ | 15.11 | $ | 9.86 | $ | 8.95 |
|
(1)
|
Production
costs include all operating expenses, depreciation, depletion and
amortization, lease operating expenses and all associated taxes.
Impairment of oil and natural gas properties is not included in production
costs.
|
|
(2)
|
Direct
lifting costs do not include impairment expense or depreciation, depletion
and amortization.
|
For the
Fiscal Year
Ended
March 31, 2009
|
For the
Fiscal Year
Ended
March 31, 2008
|
For the
Fiscal Year
Ended
March 31, 2007
|
||||||||||
Production
revenues
|
$ | 6,436,805 | $ | 3,602,798 | $ | 90,800 | ||||||
Production
costs
|
(2,637,333 | ) | (1,795,188 | ) | (172,417 | ) | ||||||
Depreciation,
depletion and amortization
|
(872,230 | ) | (913,224 | ) | (11,477 | ) | ||||||
Results
of operations for producing activities
|
$ | 2,972,242 | $ | 894,386 | $ | (93,094 | ) |
Producing
|
||||||||||||||||
Project
|
Gross Oil
|
Net Oil
(1)
|
Gross
Natural
Gas
|
Net
Natural
Gas
(1)
|
||||||||||||
Black
Oaks Project
|
62 | 59 | -0- | -0- | ||||||||||||
Thoren
Project
|
33 | 33 | -0- | -0- | ||||||||||||
DD
Energy Project
|
114 | 114 | -0- | -0- | ||||||||||||
Tri-County
Project
|
170 | 170 | -0- | -0- | ||||||||||||
Gas
City Project
|
-0- | -0- | 22 | 22 | ||||||||||||
Total
|
379 | 376 | 22 | 22 |
|
(1)
|
Net
wells are based on our net working interest as of March 31,
2009.
|
Proved Reserves
Category
|
Gross
STB
(1)
|
Net
STB
(2)
|
Gross
MCF
(3)
|
Net
MCF
(4)
|
PV10
(5)
(before tax)
|
|||||||||||||||
Proved,
Developed Producing
|
722,590 | 429,420 | - | - | $ | 6,691,550 | ||||||||||||||
Proved,
Developed Non-Producing
|
146,620 | 95,560 | - | - | 1,459,280 | |||||||||||||||
Proved,
Undeveloped
|
1,440,760 | 811,650 | - | - | 2,478,510 | |||||||||||||||
Total
Proved
|
2,309,970 | 1,336,630 | - | - | $ | 10,629,340 |
|
(1)
|
STB
= one stock-tank barrel.
|
|
(2)
|
Net STB is based upon our net
revenue interest, including any applicable reversionary
interest.
|
|
(3)
|
MCF = thousand cubic feet of
natural gas. There we no natural gas reserves at March 31,
2009.
|
|
(4)
|
Net MCF is based upon our net
revenue interest. There we no natural gas reserves at March 31,
2009.
|
|
(5)
|
See
“Glossary” on page 23 for our definition of PV10 and “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations-Reserves” page 57, for a reconciliation to the comparable
GAAP financial measure.
|
|
·
|
require the acquisition of a
permit or other authorization before construction or drilling commences
and for certain other
activities;
|
|
·
|
limit or prohibit construction,
drilling and other activities on certain lands lying within wilderness and
other pro
tected
areas; and
|
|
·
|
impose substantial liabilities for
pollution resulting from its operations, or due to previous operations
conducted on any leased
lands.
|
Term
|
De
finition
|
|
Barrel
(bbl)
|
The standard unit of measurement
of liquids in the petroleum industry, it contains 42 U.S. standard
gallons. Abbreviated to “
bbl”
.
|
|
Basin
|
A depression in the crust of the
Earth, caused by plate tectonic activity and subsidence,
in which sediments accumulate.
Sedimentary basins vary from bowl-shaped to elongated troughs. Basins can
be bounded by faults. Rift basins are commonly symmetrical; basins along
continental margins tend to be asymmetrical. If rich hydrocarbon source
rock
s
occur in combination with
appropriate depth and duration of burial, then a petroleum system can
develop within the basin.
|
|
BOPD
|
Abbreviation for barrels of oil
per day, a common unit of measurement for volume of crude oil. The volume
of a barrel is equiv
alent to 42 U.S. standard
gallons.
|
|
Carried Working
Interest
|
The owner of this type of working
interest in the drilling of a well incurs no capital contribution
requirement for drilling or completion costs associated with a well and,
if specified in the p
articular contract, may not incur
capital contribution requirements beyond the completion of the
well.
|
|
Completion /
Completing
|
A well made ready to produce oil
or natural gas.
|
|
Development
|
The phase in which a proven oil or
natural gas field is brought
into production by drilling
development wells.
|
|
Development
Drilling
|
Wells drilled during the
Development phase.
|
|
Division
order
|
A directive signed by the royalty
owners verifying to the purchaser or operator of a well the decimal
interest of production
owned by the royalty owner. The
Division Order generally includes the decimal interest, a legal
description of the property, the operator
’
s name, and several legal
agreements associated with the process. Completion of this step generally
precedes placing
t
he royalty owner on pay status to
begin receiving revenue payments.
|
|
Drilling
|
Act of boring a hole through which
oil and/or natural gas may be produced.
|
|
Dry Wells
|
A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such
production exceed production expenses and taxes.
|
|
Exploration
|
The phase of operations which
covers the search for oil or natural gas generally in unproven or
semi-proven
territory.
|
Exploratory
Drilling
|
Drilling of a rel
atively high percentage of
properties which are unproven.
|
|
Farm out
|
An arrangement whereby the owner
of a lease assigns all or some portion of the lease or licenses to another
company for undertaking exploration or development
activity.
|
|
Field
|
An area co
nsisting of a single reservoir or
multiple reservoirs all grouped on, or related to, the same individual
geological structural feature or stratigraphic condition. The field name
refers to the surface area, although it may refer to both the surface and
the
underground productive
formations.
|
|
Fixed price
swap
|
A derivative instrument that
exchanges or “
swaps”
the “
floating”
or daily price of a specified
volume of natural gas, oil or NGL, over a specified period, for a fixed
price for the specified volume over
the same period (typically three
months or longer).
|
|
Gathering line /
system
|
Pipelines and other facilities
that transport oil or natural gas from wells and bring it by separate and
individual lines to a central delivery point for delivery into a
transmi
ssion line or
mainline.
|
|
Gross acre
|
The number of acres in which the
Company owns any working interest.
|
|
Gross Producing
Well
|
A well in which a working interest
is owned and is producing oil or natural gas or other liquids or
hydrocarbons. The number o
f
gross producing wells is the total
number of wells producing oil or natural gas or other liquids or
hydrocarbons in which a working interest is
owned.
|
|
Gross well
|
A well in which a working interest
is owned. The number of gross wells is the total number o
f wells in which a working
interest is owned.
|
|
Held-By-Production
(HBP)
|
Refers to an oil and natural gas
property under lease, in which the lease continues to be in force, because
of production from the property.
|
|
Horizontal
drilling
|
A drilling technique
used in certain formations where
a well is drilled vertically to a certain depth and then turned and
drilled horizontally. Horizontal drilling allows the wellbore to follow
the desired formation.
|
|
In-fill
wells
|
In-fill wells refers to wells
drilled betwe
en
established producing wells; a drilling program to reduce the spacing
between wells in order to increase production and recovery of in-place
hydrocarbons.
|
|
Oil and Natural Gas
Lease
|
A legal instrument executed by a
mineral owner granting the right to a
nother to explore, drill, and
produce subsurface oil and natural gas. An oil and natural gas lease
embodies the legal rights, privileges and duties pertaining to the lessor
and lessee.
|
|
Lifting
Costs
|
The expenses of producing oil from
a well. Lifting cost
s
are the operating costs of the wells including the gathering and
separating equipment. Lifting costs do not include the costs of drilling
and completing the wells or transporting the
oil.
|
Mcf
|
Thousand cubic
feet.
|
|
Mmcf
|
Million cubic
feet.
|
|
Net acre
s
|
Determined by multiplying gross
acres by the working interest that the Company owns in such
acres.
|
|
Net Producing
Wells
|
The number of producing wells
multiplied by the working interest in such
wells.
|
|
Net Revenue
Interest
|
A share of production
revenue
s after all
royalties, overriding royalties and other nonoperating interests have been
taken out of production for a well(s).
|
|
Operator
|
A person, acting for itself, or as
an agent for others, designated to conduct the operations on its or the
joint intere
st
owners
’
behalf.
|
|
Overriding
Royalty
|
Ownership in a percentage of
production or production revenues, free of the cost of production, created
by the lessee, company and/or working interest owner and paid by the
lessee, company and/or working interest own
er out of revenue from the
well.
|
|
Pooled Unit
|
A term frequently used
interchangeably with “
Unitization”
but more properly used to
denominate the bringing together of small tracts sufficient for the
granting of a well permit under applicable spacing
rules.
|
|
Proved Developed
Reserves
|
Proved reserves that can be
expected to be recovered from existing wells with existing equipment and
operating methods. This definition of proved developed reserves has been
abbreviated from the applicable definitions contained
in Rule 4-10(a)(2-4)
of
Regulation
S-X.
|
|
Proved Developed
Non-Producing
|
Proved developed reserves expected
to be recovered from zones behind casings in existing
wells.
|
|
Proved Undeveloped
Reserves
|
Proved undeveloped reserves are
the portion of proved r
eserves which can be expected to
be recovered from new wells on undrilled proved acreage, or from existing
wells where a relatively major expenditure is required for completion.
This definition of proved undeveloped reserves has been abbreviated from
the
a
pplicable definitions contained in
Rule 4-10(a)(2-4)
of
Regulation
S-X.
|
|
PV10
|
PV10 means the estimated future
gross revenue to be generated from the production of proved reserves, net
of estimated production and future development and abandonment costs,
u
sing prices and
costs in effect at the determination date, before income taxes, and
without giving effect to non-property related expenses, discounted to a
present value using an annual discount rate of 10% in accordance with the
guidelines of the SEC. PV
1
0 is a non-GAAP financial measure.
See “
Management
’
s Discussion and Analysis of
Financial Condition and Results of Operations-Reserves”
on
page
57
for a reconciliation to the
comparable GAAP financial
measure.
|
Re-completion
|
Completion of an existing
w
ell for production
from one formation or reservoir to another formation or reservoir that
exists behind casing of the same well.
|
|
Reservoir
|
The underground rock formation
where oil and natural gas has accumulated. It consists of a porous rock to
hold the
oil or
natural gas, and a cap rock that prevents its
escape.
|
|
Reservoir
Pressure
|
The pressure at the face of the
producing formation when the well is shut-in. It equals the shut-in
pressure at the wellhead plus the weight of the column of oil and natural
gas in the
well.
|
|
Roll-Up
Strategy
|
A “
roll-up
strategy” is a
common business term used to describe a business plan whereby a company
accumulates multiple small operators in a particular business sector with
a goal to generate synergies, stimulate growth and optimize the value of
the individual pieces.
|
|
Secondary
Recovery
|
The stage of hydrocarbon
production during which an external fluid such as water or natural gas is
injected into the reservoir through injection wells located in rock that
has fluid commu
nication with production wells.
The purpose of secondary recovery is to maintain reservoir pressure and to
displace hydrocarbons toward the wellbore.
The most common secondary recovery
techniques are natural gas injection and waterflooding. Normally,
natu
ral gas is
injected into the natural gas cap and water is injected into the
production zone to sweep oil from the reservoir. A pressure-maintenance
program can begin during the primary recovery stage, but it is a form of
enhanced recovery.
|
|
Shut-in
well
|
A
well which is capable of
producing but is not presently producing. Reasons for a well being shut-in
may be lack of equipment, market or other.
|
|
Stock Tank Barrel or
STB
|
A stock tank barrel of oil is the
equivalent of 42 U.S. Gallons at 60 degrees Fahrenh
eit.
|
|
Undeveloped
acreage
|
Lease acreage on which wells have
not been drilled or completed to a point that would permit the production
of commercial quantities of oil and natural gas regardless of whether such
acreage contains proved reserves.
|
|
Unitize, Un
itization
|
When owners of oil and/or natural
gas reservoir pool their individual interests in return for an interest in
the overall unit.
|
|
Waterflood
|
The injection of water into an oil
reservoir to “
push”
additional oil out of the
reservoir rock and into
the wellbores of producing wells.
Typically a secondary recovery process.
|
|
Water Injection
Wells
|
A well in which fluids are
injected rather than produced, the primary objective typically being to
maintain or increase reservoir pressure, often pursuant to
a
waterflood.
|
Water Supply
Wells
|
A well in which fluids are being
produced for use in a Water Injection Well.
|
|
Wellbore
|
A borehole; the hole drilled by
the bit. A wellbore may have casing in it or it may be open (uncased); or
part of it may be cased,
and part of it may be open. Also
called a borehole or hole.
|
|
Working
Interest
|
An interest in an oil and natural
gas lease 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.
|
|
·
|
the
future prices of natural gas and
oil;
|
|
·
|
our
ability to raise adequate working
capital;
|
|
·
|
success of our development and
exploration efforts;
|
|
·
|
demand
for natural gas and
oil;
|
|
·
|
the level of our
competition;
|
|
·
|
our ability to at
tract and maintain key management,
employees and operators;
|
|
·
|
transportation
and processing fees on our
facilities;
|
|
·
|
fuel conservation
measures;
|
|
·
|
alternate fuel
requirements
or
advancements
;
|
|
·
|
government regulation and
taxation;
|
|
·
|
technical advances in
f
uel economy and
energy generation devices;
and
|
|
·
|
our ability to efficiently
explore, develop and produce sufficient quantities of marketable natural
gas or oil in a highly competitive and speculative environment while
maintaining quality and controlling co
sts.
|
|
·
|
local
, national and
worldwide economic
conditions;
|
|
·
|
worldwide or regional demand for
energy, which is affected by economic
conditions;
|
|
·
|
the domestic and foreign supply of
natural gas and oil;
|
|
·
|
weather
conditions;
|
|
·
|
natural
disasters;
|
|
·
|
acts of
terrorism;
|
|
·
|
domestic and fo
reign governmental regulations and
taxation;
|
|
·
|
political and economic conditions
in oil and natural gas producing countries,
including those in the
Middle East and South America;
|
|
·
|
impact
of the U.S. dollar exchange rates on oil and natural gas
prices;
|
|
·
|
t
he availability of refining
capacity;
|
|
·
|
actions of the Organization of
Petroleum Exporting Countries, or OPEC, and other state controlled oil
companies relating to oil price and production controls;
and
|
|
·
|
the price and availability of
other fuels.
|
|
·
|
geological
conditions;
|
|
·
|
assumptions
governing
future oil and natural gas prices;
|
|
·
|
amount
and timing of actual production;
|
|
·
|
availability
of funds;
|
|
·
|
future
operating and development
costs;
|
|
·
|
actual
prices we receive for natural gas and
oil;
|
|
·
|
supply
and demand for our natural gas and
oil;
|
|
·
|
changes
in government regulations and taxation;
and
|
|
·
|
capital
costs of drilling new wells.
|
|
·
|
unexpected
operational events and/or
conditions;
|
|
·
|
unusual or unexpected geological
formations;
|
|
·
|
reductions in natural gas and oil
prices;
|
|
·
|
limitations in the market for oil
and natural gas;
|
|
·
|
adverse weather
conditions;
|
|
·
|
facility
or equipment malfunctions;
|
|
·
|
title
problems;
|
|
·
|
natural gas and oil quality
issues;
|
|
·
|
pipe, casing, cement or pipeline
failures;
|
|
·
|
natural
disasters;
|
|
·
|
fires, explosions, blowouts,
surface cratering, pollution and other risks or
accidents;
|
|
·
|
environmental hazards, such as
natu
ral gas leaks,
oil spills, pipeline ruptures and discharges of toxic
gases;
|
|
·
|
compliance with environmental and
other governmental requirements;
and
|
|
·
|
uncontrollable flows of oil,
natural gas or well fluids.
|
|
·
|
injury
or loss of
life;
|
|
·
|
severe damage to and destruction
of proper
ty, natural
resources and equipment;
|
|
·
|
pollution and other environmental
damage;
|
|
·
|
clean-up
responsibilities;
|
|
·
|
regulatory investigation and
penalties;
|
|
·
|
suspension of our operations;
and
|
|
·
|
repairs to resume
operations.
|
|
·
|
unable to identify attractive
acquisition candidates or negotiate acceptable
purchase contracts with
them;
|
|
·
|
unable
to obtain financing for these acquisitions on economically acceptable
terms;
or
|
|
·
|
outbid by
competitors.
|
|
·
|
higher than projected operating
costs;
|
|
·
|
lower-than-expected
production;
|
|
·
|
longer
response
times;
|
|
·
|
higher costs associated with
obtaining capital;
|
|
·
|
unusual or unexpected geological
formations;
|
|
·
|
fluctuations in natural gas and
oil prices;
|
|
·
|
regulator
y
changes;
|
|
·
|
shortages of equipment;
and
|
|
·
|
lack of technical
expertise.
|
|
·
|
the validity of our assumptions
about reserves, future production, revenues and costs, including
synergies;
|
|
·
|
an inabil
ity to integrate successfully the
businesses we acquire;
|
|
·
|
a decrease in our liquidity by
using our available cash or borrowing capacity to finance
acquisitions;
|
|
·
|
a significant increase in our
interest expense or financial leverage if we incur additional
debt to finance
acquisitions;
|
|
·
|
the assumption of unknown
liabilities, losses or costs for which we are not indemnified or for which
our indemnity is inadequate;
|
|
·
|
the diversion of
management
’
s attention from other business
concerns;
|
|
·
|
an
inability to hire
, train or retain qualified
personnel to manage the acquired properties or
assets;
|
|
·
|
the incurrence of other
significant charges, such as impairment of goodwill or other intangible
assets, asset devaluation or restructuring
charges;
|
|
·
|
unforeseen difficulti
es encountered in operating in new
geographic or geological areas;
and
|
|
·
|
customer or key employee losses at
the acquired businesses.
|
|
·
|
location
and density of wells;
|
|
·
|
the handling of drilling fluids
and obtaining discharge permits for drilling
operations;
|
|
·
|
accounting for and payment of
royalties on pro
duction from state, federal and
Indian lands;
|
|
·
|
bonds for ownership, development
and production of natural gas and oil
properties;
|
|
·
|
transportation of natural gas and
oil by pipelines;
|
|
·
|
operation of wells and reports
concerning operations; and
|
|
·
|
taxation.
|
|
·
|
limiting
our ability to borrow additional amounts for working capital, capital
expenditures, debt service requirements, execution of our business
strategy, or other general corporate
purposes;
|
|
·
|
being
forced to use cash flow to reduce our outstanding balance as a result of
an unfavorable borrowing base
redetermination;
|
|
·
|
limiting
our ability to use operating cash flow in other areas of our business
because we must dedicate a substantial portion of these funds to service
our indebtedness;
|
|
·
|
increasing
our vulnerability to general adverse economic and industry
conditions;
|
|
·
|
placing
us at a competitive disadvantage as compared to our competitors that have
less leverage;
|
|
·
|
limiting
our ability to capitalize on business opportunities and to react to
competitive pressures and changes in government
regulation;
|
|
·
|
limiting
our ability to, or increasing the cost of, refinancing our
indebtedness; and
|
|
·
|
limiting
our ability to enter into marketing, hedging, optimization and trading
transactions by reducing the number of counterparties with whom we can
enter into such transactions as well as the volume of those
transactions.
|
|
·
|
incur
additional indebtedness and provide additional
guarantees;
|
|
·
|
pay
dividends and make other restricted
payments;
|
|
·
|
create
or permit certain liens;
|
|
·
|
use
the proceeds from the sales of our oil and natural gas
properties;
|
|
·
|
use
the proceeds from the unwinding of certain financial
hedges;
|
|
·
|
engage
in certain transactions with affiliates;
and
|
|
·
|
consolidate,
merge, sell or transfer all or substantially all of our assets or the
assets of our subsidiaries.
|
|
·
|
our
operating and financial performance and
prospects;
|
|
·
|
quarterly
variations in the rate of growth of our financial indicators, such as net
income or loss per share, net income or loss and
revenues;
|
|
·
|
changes
in revenue or earnings estimates or publication of research reports by
analysts about us or the exploration and production
industry;
|
|
·
|
potentially
limited liquidity;
|
|
·
|
actual
or anticipated variations in our reserve estimates and quarterly operating
results;
|
|
·
|
changes
in natural gas and oil prices;
|
|
·
|
sales
of our common stock by significant stockholders and future issuances of
our common stock;
|
|
·
|
increases
in our cost of capital;
|
|
·
|
changes
in applicable laws or regulations, court rulings and enforcement and legal
actions;
|
|
·
|
commencement
of or involvement in litigation;
|
|
·
|
changes
in market valuations of similar
companies;
|
|
·
|
additions
or departures of key management
personnel;
|
|
·
|
general
market conditions, including fluctuations in and the occurrence of events
or trends affecting the price of natural gas and oil;
and
|
|
·
|
domestic
and international economic, legal and regulatory factors unrelated to our
performance.
|
|
·
|
Deliver
to the customer, and obtain a written receipt for, a disclosure
document;
|
|
·
|
Disclose
certain price information about the
stock;
|
|
·
|
Disclose
the amount of compensation received by the broker-dealer or any associated
person of the broker-dealer;
|
|
·
|
Send
monthly statements to customers with market and price information about
the penny stock; and
|
|
·
|
In
some circumstances, approve the purchaser’s account under certain
standards and deliver written statements to the customer with information
specified in the rules.
|
Low
|
High
|
|||||||
Fiscal
2008
|
||||||||
Quarter
ended June 30, 2007
|
1.00 | 1.25 | ||||||
Quarter
ended September 30, 2007
|
0.75 | 1.35 | ||||||
Quarter
ended December 31, 2007
|
0.70 | 1.20 | ||||||
Quarter
ended March 31, 2008
|
0.81 | 1.20 | ||||||
Fiscal
2009
|
||||||||
Quarter
ended June 30, 2008
|
0.95 | 1.20 | ||||||
Quarter
ended September 30, 2008
|
4.20 | 5.00 | ||||||
Quarter
ended December 31, 2008
|
0.45 | 3.16 | ||||||
Quarter
ended March 31, 2009
|
0.25 | 1.88 |
Fiscal
Year Ended
March
31,
|
||||||||||||
2009
|
2008
|
Increase
/ (Decrease)
|
||||||||||
Amount
|
Amount
|
$
|
||||||||||
Oil
and natural gas revenues
|
$ | 6,436,805 | $ | 3,602,798 | $ | 2,834,007 |
Fiscal
Year Ended
March
31,
|
||||||||||||
2009
|
2008
|
Increase
/ (Decrease)
|
||||||||||
Amount
|
Amount
|
$
|
||||||||||
Expenses:
|
||||||||||||
Direct
operating costs
|
$ | 2,637,333 | $ | 1,795,188 | $ | 842,145 | ||||||
Depreciation,
depletion and
amortization
|
872,230 | 913,224 | (40,994 | ) | ||||||||
Total
production expenses
|
3,509,563 | 2,708,412 | 801,151 | |||||||||
Professional
fees
|
1,320,332 | 1,226,998 | 93,334 | |||||||||
Salaries
|
849,340 | 1,703,099 | (853,759 | ) | ||||||||
Depreciation
on other fixed assets
|
39,063 | 22,106 | 16,957 | |||||||||
Administrative
expenses
|
1,392,645 | 887,872 | 504,773 | |||||||||
Impairment
of oil & gas properties
|
4,777,723 | - | 4,777,723 | |||||||||
Total
expenses
|
11,888,666 | 6,548,487 | 5,340,179 |
Proved
Reserves Category
|
Gross
|
Net
|
PV10
(before tax)
(1)
|
|||||||||
Proved,
Developed Producing
|
||||||||||||
Oil
(stock-tank barrels)
|
722,590 | 429,420 | $ | 6,691,550 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - | |||||||||
Proved,
Developed Non-Producing
|
||||||||||||
Oil
(stock-tank barrels)
|
146,620 | 95,560 | $ | 1,459,280 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - | |||||||||
Proved,
Undeveloped
|
||||||||||||
Oil
(stock-tank barrels)
|
1,440,760 | 811,650 | $ | 2,478,510 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - | |||||||||
Total
Proved Reserves
|
||||||||||||
Oil
(stock-tank barrels)
|
2,309,970 | 1,136,630 | $ | 10,629,340 | ||||||||
Natural
Gas (mcf)
(2)
|
- | - | - |
|
(1)
|
The
following table shows our reconciliation of our PV10 to our standardized
measure of discounted future net cash flows (the most direct comparable
measure calculated and presented in accordance with GAAP). PV10 is our
estimate of the present value of future net revenues from estimated proved
natural gas reserves after deducting estimated production and ad valorem
taxes, future capital costs and operating expenses, but before deducting
any estimates of future income taxes. The estimated future net revenues
are discounted at an annual rate of 10% to determine their “present
value.” We believe PV10 to be an important measure for evaluating the
relative significance of our oil and natural gas properties and that the
presentation of the non-GAAP financial measure of PV10 provides useful
information to investors because it is widely used by professional
analysts and sophisticated investors in evaluating oil and gas companies.
Because there are many unique factors that can impact an individual
company when estimating the amount of future income taxes to be paid, we
believe the use of a pre-tax measure is valuable for evaluating our
company. We believe that most other companies in the oil and gas industry
calculate PV10 on the same basis. PV10 should not be considered as an
alternative to the standardized measure of discounted future net cash
flows as computed under GAAP.
|
As
of
March
31,
2009
|
||||
PV10
(before tax)
|
$ | 10,629,340 | ||
Future
income taxes, net of 10% discount
|
- | |||
Standardized
measure of discounted future net cash flows
|
$ | 10,629,340 |
|
(2)
|
There
were no natural gas reserves at March 31,
2009.
|
March
31,
2009
|
March
31,
2008
|
Increase
/ (Decrease)
$
|
||||||||||
Current
Assets
|
$ | 898,941 | $ | 1,511,595 | (612,654 | ) | ||||||
Current
Liabilities
|
$ | 2,827,015 | $ | 2,117,176 | 709,839 | |||||||
Working
Capital (deficit)
|
$ | (1,928,074 | ) | $ | (605,581 | ) | (1,322,493 | ) |
Name
|
Age
|
Position
|
Board Committee(s)
(1)
|
|||
C. Stephen
Cochennet
|
52
|
President, Chief Executive
Officer, and Chairman
|
None
|
|||
Dierdre P.
Jones
|
44
|
Chief Financial
Officer
|
None
|
|||
Robert G.
Wonish
|
55
|
Director
|
GCNC (Chairman)
and
Audit
|
|||
Daran G.
Dammeyer
|
48
|
Director
|
Audit (Chairman)
and
GCNC
|
|||
Darrel G.
Palmer
|
51
|
Director
|
GCNC
|
|||
Dr. James W.
Rector
|
|
48
|
|
Director
|
|
None
|
|
(1)
|
“GCNC”
means the Governance, Compensation and Nominating Committee of the Board
of Directors. “Audit” means the Audit Committee of the Board of
Directors.
|
Name and Principal Position
|
Fiscal
Year
|
Salary
($)
|
Bonus
($)
|
Option
Awards
($)
|
All Other
Compen-
sation
($)
|
Total
($)
|
||||||||||||||||
C.
Stephen Cochennet
|
2009
|
$ | 186,525 | $ | 50,000 | $ | - |
(2)
|
$ | - | $ | 236,525 | ||||||||||
President,
Chief Executive Officer
|
2008
|
$ | 156,000 | - | 859,622 |
(1)
|
- | $ | 1,015,622 | |||||||||||||
Dierdre
P. Jones
|
2009
|
$ | 128,808 | $ | 10,000 | - |
(2)
|
- | $ | 138,808 | ||||||||||||
Chief
Financial Officer
|
2008
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
- |
(3)
|
|
(1)
|
Amount represents the estimated
total fair value of stock options granted to Mr. Cochennet under SFAS
123(R).
|
|
(2)
|
In
August, 2008,
we granted
C. Stephen Cochennet, our chief executive officer, an option to purchase
75,000 shares of our common stock at $6.25 per share and we granted
Dierdre P. Jones, our chief financial officer, and option to purchase
40,000 shares of our common stock at $6.25 per share
under SFAS 123(R) as discussed in
Note 3 to our financial statements for the year ended March 31, 2009
included elsewhere in this report.
These options were rescinded in
November 2008 at the request of the board’s compensation committee and the
approval of each option holder.
|
|
(3)
|
Ms.
Jones was promoted to chief financial officer during fiscal 2009 and was
not a named executive officer in fiscal
2008.
|
Option Awards
|
|||||||||||||||||||
Fiscal
Year
|
Number of
Securities
Underlying
Unexercised
Options
Exercisable
(#)
|
Number of
Securities
Underlying
Unexercised
Options
Unexercisable
(#)
|
Number of
Securities
Underlying
Unexercised
Unearned
Options
(#)
|
Option
Exercise
Price
($)
|
Option
Expiration
Date
|
||||||||||||||
C.
Stephen Cochennet
|
2009
|
200,000 | - | - | $ | 6.25 |
05/03/2011
|
||||||||||||
Dierdre
P. Jones
|
2009
|
20,000 | - | - | $ | 6.30 |
07/31/2011
|
Name
|
Fees
Earned
or Paid in
Cash
$
|
Stock
Awards
$
|
Option
Awards
(2)
$
|
All Other
Compensation
$
|
Total
$
|
|||||||||||||||
Daran
G. Dammeyer
|
$ | 58,000 | $ | 12,000 |
(1)
|
$ | -0- | $ | -0- | $ | 70,000 | |||||||||
Darrel
G. Palmer
|
$ | 26,500 | $ | -0- | $ | -0- | $ | 20,000 |
(3)
|
$ | 46,500 | |||||||||
Robert
G. Wonish
|
$ | 49,000 | $ | -0- | $ | -0- | $ | -0- | $ | 49,000 | ||||||||||
Dr.
James W. Rector
|
$ | 22,500 | $ | -0- | $ | -0- | $ | -0- | $ | 22,500 |
(1)
|
Amount represents the estimated
total fair market
value of 2,182 shares of common stock issued to Mr. Dammeyer for services
as audit committee chairman under SFAS 123(R), as discussed in Note 3 to
our audited financial statements for the year ended March 31, 2009
included elsewhere in this
report.
|
(2)
|
In
July, 2008, 28,000 stock options
were granted to each of Messrs. Dammeyer, Palmer and Wonish and 38,000
stock options were granted to Dr. Rector under SFAS 123(R), as discussed
in Note 3 to our financial statements for the year ended March 31, 2009
inclu
d
ed elsewhere in this report. These
total 122,000 options granted to Messrs. Dammeyer, Palmer and Wonish and
to Dr. Rector were rescinded in November
2008.
|
(3)
|
Mr.
Palmer was paid $20,000 for assisting in the establishment and development
of the audit committee and for his involvement and assistance to the chief
executive officer in finalizing the hedging instrument with
BP.
|
Name and Address of Beneficial Owner, Officer
or
Director
(1)
|
Number
of Shares
|
Percent of
Outstanding
Shares of
Common Stock
(2)
|
||||||
C.
Stephen Cochennet, President & Chief Executive Officer
(3)
|
600,000 |
(4)
|
12.5 | % | ||||
Dierdre
P. Jones, Chief Financial Officer
|
20,000 | * | ||||||
Robert
(Bob) G. Wonish, Director
(3)
|
40,000 |
(5)
|
* | |||||
Darrel
G. Palmer, Director
(3)
|
40,000 |
(5)
|
* | |||||
Daran
G. Dammeyer, Director
(3)
|
44,102 |
(5)
|
* | |||||
Dr.
James W. Rector, Director
(3)
|
-0- | * | ||||||
Directors
and Officers as a Group
|
15.6 | % | ||||||
West
Coast Opportunity Fund LLC
(6)
West
Coast Asset Management, Inc.
Paul
Orfalea, Lance Helfert & R. Atticus Lowe
2151
Alessandro Drive, #100
Ventura,
CA 93001
|
1,000,000 | 22.5 | % | |||||
Enable
Growth Partners L.P.
(7)
Enable
Capital Management, LLC
Mitchell
S. Levine
One
Ferry Building, Suite 225
San
Francisco, CA 94111
|
353,800 | 8.7 | % |
|
*
|
Represents beneficial ownership of
less than 1%
|
|
(1)
|
As
used in this table, “beneficial ownership” means the sole or shared power
to vote, or to direct the voting of, a security, or the sole or shared
investment power with respect to a security (i.e., the
power to dispose
of, or to direct the disposition of, a
security).
|
|
(2)
|
Figures
are rounded to the nearest tenth of a
percent.
|
|
(3)
|
The
address of each person is care of EnerJex Resources: Corporate Woods 27,
Suite 350, 10975 Grandview Drive, Overland Park,
Kansas 66210.
|
|
(4)
|
Includes
200,000 options, exercisable at $6.25 per share through May 3,
2011.
|
|
(5)
|
Includes
40,000 options, exercisable at $6.25 per share through May 3,
2011.
|
|
(6)
|
Based
on a Schedule 13D filed with the SEC on February 13, 2009, the investment
manager of West Coast Opportunity Fund, LLC (“WCOF”) is West Coast Asset
Management (“WCAM”). WCAM has the authority to take any and all
actions on behalf of WCOF, including voting any shares held by
WCOF. Paul Orfalea, Lance Helfert and R. Atticus Lowe
constitute the Investment Committee of WCOF. Messrs. Orfalea,
Helfert and Lowe disclaim beneficial ownership of the
shares.
|
|
(7)
|
Based
on a Schedule 13G/A filed with the SEC on February 11, 2009, Enable
Capital Management, LLC, as general and investment manager of Enable
Growth Partners L.P. and other clients, may be deemed to have the power to
direct the voting or disposition of shares of common stock held by Enable
Growth Partners L.P. (353,800 shares of common stock) and other clients
(285,040 shares of common stock). Therefore, Energy Capital
Management, LLC, as Enable Growth Partners L.P.’s and those other
accounts’ general partner and investment manager, and Mitchell S. Levine,
as managing member and majority owner of Enable Capital Management, LLC,
may be deemed to beneficially own the shares of common stock owned by
Enable Growth Partners L.P. and such other
accounts.
|
Plan
Category
|
Number
of shares to be issued
upon exercise of
outstanding options,
warrants and rights
(a)
|
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
|
Number of shares
rem
aining available for
future issuance under
equity compensation
plans (excluding
shares
reflected in column (a)
(c)
|
|||||||||
Equity compensation plans
approved by
stockholders
|
4 38,500 | $ | 6.30 | 761,500 | ||||||||
Equity compensation plans not
approved by
stockholders
|
— | — | — | |||||||||
Total
|
438,500 | $ | 6.30 | 761,500 |
|
•
|
The amounts involved exceeds the
lesser of
$120,000 or
one
percent of the
average of our total assets at year end for the last two completed
fiscal
year
s ($
93,280
);
and
|
|
•
|
A director, executive officer,
holder of more than 5% of our common stock or any member of their
immediate family had or will have a direct or indirect material
interest.
|
For
the Fiscal Years
Ended
March
31,
|
||||||||
2009
|
2008
|
|||||||
Audit
Fees
(1)
|
$ | 56,000 | $ | 105,000 | ||||
Audit-Related
Fees
(2)
|
-0- | -0- | ||||||
Tax
Fees
(3)
|
10,000 | 13,000 | ||||||
All
Other Fees
(4
)
|
19,718 | -0- | ||||||
Total
fee
s
paid or accrued to our principal accountant
|
$ | 85,718 | $ | 118,000 |
|
(1)
|
Audit Fees include fees billed and
expected to be billed for services performed to comply with Generally
Accepted Auditing Standards (GAAS), including the recurring audit of the
Company
’
s consolidated financial
statements for such period included in this Annual Report on
Form 10-K and for the reviews of the consolidated quarterly financial
statements included in the Quarterly Reports on Form 10-QSB filed
with the Securities and Exchange
Commission. This category also
includes fees for audits provided in connection with statutory filings or
procedures related to audit of income tax provisions and related reserves,
consents and assistance with and review of documents filed with the
SEC.
|
|
(2)
|
Audit-Related Fees include fees
for services associated with assurance and reasonably related to the
performance of the audit or review of the Company
’
s financial statements. This
category includes fees related to assistance in financial due diligence
related to mergers
and acquisitions, consultations regarding Generally Accepted Accounting
Principles, reviews and evaluations of the impact of new regulatory
pronouncements, general assistance with implementation of Sarbanes-Oxley
Act of 2002 requirement
s
and audit services not required
by statute or regulation.
|
|
(3)
|
Tax fees consist of fees related
to the preparation and review of the Company
’
s federal and state income tax
returns.
|
|
(4)
|
Other fees include fees related to
the preparation and review of the F
orm S-1 Registration
Statement.
|
Page
|
|
Management
Responsibility for Financial Information
|
65
|
Management’s
Report on Internal Control Over Financial Reporting
|
66
|
Index
to Financial Statements
|
F-1
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
Consolidated
Balance Sheets
|
F-3
|
Consolidated
Statements of Operations
|
F-4
|
Consolidated
Statements of Stockholders Equity
|
F-5
|
Consolidated
Statements of Cash Flows
|
F-6
|
Exhibit No.
|
Description
|
|
2.1
|
Agreement
and Plan of Merger between Millennium Plastics Corporation and Midwest
Energy, Inc. effective August 15, 2006 (incorporated by reference to
Exhibit 2.3 to the Form 8-K filed on August 16, 2006)
|
|
3.1
|
Amended
and Restated Articles of Incorporation, as currently in effect
(incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August
14, 2008)
|
|
3.2
|
Amended
and Restated Bylaws, as currently in effect
(
incorporated by reference
to Exhibit 3.3 to the Form SB-2 filed on February 23,
2001)
|
|
4.1
|
Article
VI of Amended and Restated Articles of Incorporation of Millennium
Plastics Corporation (incorporated by reference to Exhibit 1.3 to the Form
8-K filed on December 6, 1999)
|
|
4.2
|
Article
II and Article VIII, Sections 3 & 6 of Amended and Restated Bylaws of
Millennium Plastics Corporation (incorporated by reference to Exhibit 4.1
to the Form SB-2 filed on February 23, 2001)
|
|
4.3
|
Specimen
common stock certificate (incorporated by reference to Exhibit 4.3 to the
Form S-1/A filed on May 27, 2008)
|
|
10.1
|
Credit Agreeme
nt with Texas Capital Bank, N.A.
dated
July
3
, 2008
(
incorporated by reference
to Exhibit 10.33 to the Form 10-K filed on July 10,
2008)
|
|
10.2
|
Promissory Note to Texas Capital
Bank, N.A. dated
July
3
, 2008
(
incorporated by reference
to Exhibit 10.34 to the Form 10-K filed on July 10,
2008)
|
|
10.3
|
Amended and Restated
Mortgage, Security Agreement,
Financing Statement and Assignment of Production and Revenues with Texas
Capital Bank, N.A. dated
July 3
, 2008
(
incorporated by reference
to Exhibit 10.35 to the Form 10-K filed on July 10,
2008)
|
|
10.4
|
Security Agreement with Texas
Capital Bank, N.A. dated
July 3
, 2008
(
incorporated by reference
to Exhibit 10.36 to the Form 10-K filed on July 10,
2008)
|
|
10.5
|
Letter Agreement with Debenture
Holders dated
July
3
, 2
008
(
incorporated by reference
to Exhibit 10.37 to the Form 10-K filed on July 10,
2008)
|
|
10.6†
|
C.
Stephen Cochennet Employment Agreement dated August 1, 2008 (incorporated
by reference to Exhibit 10.1 to the Form 8-K filed on August 1,
2008)
|
|
10.7
†
|
Dier
dre P. Jones Employment Agreement
dated August 1, 2008 (
incorporated by reference to Exhibit 10.2 to
the Form 8-K filed on August 1, 2008)
|
|
10.8
†
|
Amended and Restated EnerJex
Resources, Inc. Stock Incentive Plan (
incorporated by reference to
Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
|
|
10.9
|
Form of Officer and Director
Indemnification Agreement (
incorporated by reference to Exhibit
10.2 to the Form 8-K filed on October 16, 2008)
|
|
10.10
|
Euramerica Letter Agreement
Amendment dated September 15,
2008 (
incorporated by
reference to Exhibit 10.10 to the Form 8-K filed on September 18,
2008)
|
|
10.11
|
Euramerica Letter Agreement
Amendment dated October 15, 2008 (
incorporated by reference to
Exhibit 10.11 to the Form 8-K filed on October 21,
2008)
|
|
10.12(a)
†
|
C. Stephen Cochennet Rescission of
Option Grant Agreement dated November 17, 2008
(incorporated by reference to
Exhibit 10.38(a) to the Form 10-Q filed on February 23,
2009)
|
10.12(b)
†
|
Dierdre P. Jones Rescission of
Option Grant Agreement dated
November 17, 2008
(incorporated by reference to
Exhibit 10.38(b) to the Form 10-Q filed on February 23,
2009)
|
|
10.12(c)
|
Daran G. Dammeyer
Rescission of Option Grant
Agreement dated November 17, 2008
(incorporated by reference to
Exhibit 10.38(c) to the Fo
rm 10-Q filed on February 23,
2009)
|
|
10.12(d)
|
Darrel G. Palmer
Rescission of Option Grant
Agreement dated November 17, 2008
(incorporated by reference to
Exhibit 10.38(d) to the Form 10-Q filed on February 23,
2009)
|
|
10.12(e)
|
Dr. James W. Rector
Resciss
ion of Option Grant Agreement
dated November 17, 2008
(incorporated by reference to
Exhibit 10.38(e) to the Form 10-Q filed on February 23,
2009)
|
|
10.12(f)
|
Robert G. Wonish
Rescission of Option Grant
Agreement dated November 17, 2008
(incorporated by refe
rence to Exhibit 10.38(f) to the
Form 10-Q filed on February 23, 2009)
|
|
10.13
|
Letter
Agreement with Debenture Holders dated June 11, 2009 (incorporated by
reference to Exhibit 10.1 to the Form 8-K filed on June 16,
2009)
|
|
10.14
|
Joint
Operating Agreement with Pharyn Resources to explore and develop the
Brownrigg Lease Press Release dated June 1, 2009 (incorporated by
reference to Exhibit 99.1 to the Form 8-K filed on June 5,
2009)
|
|
10.15
|
Amendment 4 to Joint Exploration
Agreement effective as of Novembe
r 6, 2008 between MorMeg, LLC and
EnerJex Resources, Inc.
|
|
10.16
|
Waiver
from Texas Capital Bank, N.A. dated July 14,
2009
|
|
21.1
|
List
of Subsidiaries
|
|
23.1
|
Miller
& Lents, Ltd. Consent Of Independent Petroleum Engineers and
Geologists Letter dated June 24, 2009 and effective March 31,
2009
|
|
23.2
|
Consent
of Weaver & Martin, LLC
|
|
31.1
|
Certification of Chief Executive
Officer pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
|
|
31.2
|
Certification of Chief
Financial
Officer pursuant to
Section 302
of the
Sarbanes-Oxley Act of 2002
|
|
32.1
|
Certification of Chief Executive
Officer pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
32.2
|
Certification of Chief
Financial
Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of
2002
|
ENERJEX
RESOURCES, INC.
|
|
By:
|
/s/ C. Stephen Cochennet |
C.
Stephen Cochennet, Chief Executive Officer
|
|
Date:
July 14,
2009
|
ENERJEX
RESOURCES, INC.
|
|
By:
|
/s/
Dierdre P Jones
|
Dierdre
P Jones, Chief Financial Officer
|
|
Date:
July 14,
2009
|
Name
|
Title
|
Date
|
||
/s/ C. Stephen Cochennet |
President,
Chief Executive Officer,
|
July
14, 2009
|
||
C.
Stephen Cochennet
|
(Principal
Executive Officer),
|
|||
Secretary,
Chairman
|
||||
/s/ Dierdre P Jones |
Chief
Financial Officer
|
July
14, 2009
|
||
Dierdre
P. Jones
|
||||
/s/
Robert G. Wonish
|
Director
|
July
14, 2009
|
||
Robert
G. Wonish
|
||||
/s/
Daran G. Dammeyer
|
Director
|
July
14, 2009
|
||
Daran
G. Dammeyer
|
||||
/s/
Darrel G. Palmer
|
Director
|
July
14, 2009
|
||
Darrel
G. Palmer
|
||||
/s/
Dr. James W. Rector
|
Director
|
July
14, 2009
|
||
Dr.
James W. Rector
|
|
|
Page
|
|
Index
to Financial Statements
|
F-1
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
Consolidated
Balance Sheets at March 31, 2009 and 2008
|
F-3
|
Consolidated
Statements of Operations for the Fiscal Years Ended March 31, 2009 and
2008
|
F-4
|
Consolidated
Statement of Stockholders’ Equity(Deficit) for the Fiscal Years Ended
March 31, 2009 and 2008
|
F-5
|
Consolidated
Statement of Cash Flows for the Fiscal Years Ended March 31, 2009 and
2008
|
F-6
|
Notes
to Consolidated Financial Statements
|
F-7
|
March
31,
|
||||||||
2009
|
2008
|
|||||||
Assets
|
||||||||
Current
assets:
|
||||||||
Cash
|
$ | 127,585 | $ | 951,004 | ||||
Accounts
receivable
|
462,044 | 227,055 | ||||||
Prepaid
debt issue costs
|
45,929 | 157,191 | ||||||
Deposits
and prepaid expenses
|
263,383 | 176,345 | ||||||
Total
current assets
|
898,941 | 1,511,595 | ||||||
Fixed
assets
|
365,019 | 185,299 | ||||||
Less:
Accumulated depreciation
|
63,988 | 30,982 | ||||||
Total
fixed assets
|
301,031 | 154,317 | ||||||
Other
assets:
|
||||||||
Prepaid
debt issue costs
|
- | 157,191 | ||||||
Oil
and gas properties using full-cost accounting:
|
||||||||
Properties
not subject to amortization
|
31,183 | 62,216 | ||||||
Properties
subject to amortization
|
6,449,023 | 8,982,510 | ||||||
Total
other assets
|
6,480,206 | 9,201,917 | ||||||
Total
assets
|
$ | 7,680,178 | $ | 10,867,829 | ||||
Liabilities
and Stockholders’ Equity (Deficit)
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable
|
$ | 1,016,168 | $ | 416,834 | ||||
Accrued
liabilities
|
87,811 | 70,461 | ||||||
Notes
payable
|
- | 965,000 | ||||||
Deferred
payments from Euramerica development
|
- | 251,951 | ||||||
Long-term
debt, current
|
1,723,036 | 412,930 | ||||||
Total
current liabilities
|
2,827,015 | 2,117,176 | ||||||
Asset
retirement obligation
|
803,624 | 459,689 | ||||||
Convertible
note payable
|
25,000 | 25,000 | ||||||
Long-term
debt, net of discount of $596,108
|
7,818,163 | 6,831,972 | ||||||
Total
liabilities
|
11,473,802 | 9,433,837 | ||||||
Contingencies
and commitments
|
||||||||
Stockholders’
Equity (Deficit):
|
||||||||
Preferred
stock, $0.001 par value, 10,000,000 shares authorized, no shares issued
and outstanding
|
- | - | ||||||
Common
stock, $0.001 par value, 100,000,000 shares authorized; shares issued and
outstanding –4,443,512 at March 31, 2009 and 4,440,651 at March 31,
2008
|
4,444 | 4,441 | ||||||
Paid
in capital
|
8,932,906 | 8,853,457 | ||||||
Retained
(deficit)
|
(12,730,974 | ) | (7,423,906 | ) | ||||
Total
stockholders’ equity (deficit)
|
(3,793,624 | ) | 1,433,992 | |||||
Total
liabilities and stockholders’ equity (deficit)
|
$ | 7,680,178 | $ | 10,867,829 |
For the Fiscal Years Ended
|
||||||||
March 31,
|
||||||||
2009
|
2008
|
|||||||
Oil
and natural gas revenues
|
$ | 6,436,805 | $ | 3,602,798 | ||||
Expenses:
|
||||||||
Direct
operating costs
|
2,637,333 | 1,795,188 | ||||||
Depreciation,
depletion and amortization
|
911,293 | 935,330 | ||||||
Impairment
of oil and gas properties
|
4,777,723 | - | ||||||
Professional
fees
|
1,320,332 | 1,226,998 | ||||||
Salaries
|
849,340 | 1,703,099 | ||||||
Administrative
expense
|
1,392,645 | 887,872 | ||||||
Total
expenses
|
11,888,666 | 6,548,487 | ||||||
Loss
from operations
|
(5,451,861 | ) | (2,945,689 | ) | ||||
Other
income (expense):
|
||||||||
Interest
expense
|
(882,426 | ) | (792,448 | ) | ||||
Loan
interest accretion
|
(2,814,095 | ) | (1,089,798 | ) | ||||
Gain
on liquidation of hedging instrument
|
3,879,050 | - | ||||||
Other
Gain/(Loss)
|
(37,736 | ) | - | |||||
Total
other income (expense)
|
144,793 | (1,882,246 | ) | |||||
Net
income - (loss)
|
$ | (5,307,068 | ) | $ | (4,827,935 | ) | ||
Weighted
average shares outstanding - basic
|
4,443,249 | 4,284,144 | ||||||
Net
income (loss) per share - basic
|
$ | (1.19 | ) | $ | (1.13 | ) |
Common Stock
|
||||||||||||||||||||||||
Shares
|
Par Value
|
Owed but not
issued
|
Paid in
Capital
|
Retained Deficit
|
Total
Stockholders’
Equity (Deficit)
|
|||||||||||||||||||
Balance,
April 1, 2007
|
2,635,731 | $ | 2,636 | $ | 3 | $ | 2,548,742 | $ | ( 2,595,971 | ) | $ | (44,590 | ) | |||||||||||
Stock
sold
|
1,800,000 | 1,800 | - | 4,311,956 | - | 4,313,756 | ||||||||||||||||||
Stock
issued for services
|
1,920 | 2 | - | 14,998 | - | 15,000 | ||||||||||||||||||
Previously
authorized but unissued stock
|
3,000 | 3 | (3 | ) | - | - | - | |||||||||||||||||
Stock
options issued for services
|
- | - | - | 1,977,761 | - | 1,977,761 | ||||||||||||||||||
Net
(loss) for the year
|
- | - | - | - | (4,827,935 | ) | (4,827,935 | ) | ||||||||||||||||
Balance,
March 31, 2008
|
4,440,651 | 4,441 | - | 8,853,457 | (7,423,906 | ) | 1,433,992 | |||||||||||||||||
Stock
options issued for services
|
- | - | - | 67,452 | - | 67,452 | ||||||||||||||||||
Stock
issued for services
|
2,182 | 2 | - | 11,998 | - | 12,000 | ||||||||||||||||||
Stock
issued in reverse stock split
|
679 | 1 | - | (1 | ) | - | - | |||||||||||||||||
Net
loss for the year
|
- | - | - | - | $ | (5,307,068 | ) | (5,307,068 | ) | |||||||||||||||
Balance,
March 31, 2009
|
4,443,512 | $ | 4,444 | $ | - | $ | 8,932,906 | $ | ( 12,730,974 | ) | $ | (3,793,624 | ) |
For the Fiscal Years Ended
|
||||||||
March 31,
|
||||||||
2009
|
2008
|
|||||||
Cash
flows from operating activities
|
||||||||
Net
(loss)
|
$ | (5,307,068 | ) | $ | (4,827,935 | ) | ||
Depreciation
and depletion
|
950,357 | 935,330 | ||||||
Debt
issue cost amortization
|
157,191 | 152,453 | ||||||
Stock
and options issued for services
|
79,452 | 1,992,761 | ||||||
Accretion
of interest on long-term debt discount
|
2,814,095 | 1,089,798 | ||||||
Accretion
of asset retirement obligation
|
60,864 | 30,331 | ||||||
Impairment
of oil & gas properties
|
4,777,723 | - | ||||||
Adjustments
to reconcile net (loss) to cash used in operating
activities:
|
||||||||
Accounts
receivable
|
(234,989 | ) | (222,917 | ) | ||||
Notes
and interest receivable
|
- | 10,300 | ||||||
Deposits
and prepaid expenses
|
24,224 | (169,672 | ) | |||||
Accounts
payable
|
599,334 | 374,535 | ||||||
Accrued
liabilities
|
17,350 | (25,429 | ) | |||||
Deferred
payment from Euramerica for development
|
(251,951 | ) | 251,951 | |||||
Cash
used in operating activities
|
3,686,582 | (408,494 | ) | |||||
Cash
flows from investing activities
|
||||||||
Purchase
of fixed assets
|
(204,200 | ) | (149,799 | ) | ||||
Additions
to oil & gas properties
|
(3,123,003 | ) | (9,530,321 | ) | ||||
Sale
of oil & gas properties
|
300,000 | 300,000 | ||||||
Note
and interest receivable from officer
|
- | 23,100 | ||||||
Proceeds
from sale of vehicle
|
- | |||||||
Cash
used in investing activities
|
(3,027,203 | ) | (9,357,020 | ) | ||||
Cash
flows from financing activities
|
||||||||
Proceeds
from (repayment of) note payable, net
|
(965,000 | ) | 615,000 | |||||
Proceeds
from sales of common stock
|
- | 4,313,756 | ||||||
Debt
issue costs
|
(466,835 | ) | ||||||
Borrowings
on long-term debt
|
11,274,843 | 6,344,816 | ||||||
Payments
on long-term debt
|
(11,792,641 | ) | (189,712 | ) | ||||
Cash
provided from financing activities
|
(1,482,798 | ) | 10,617,025 | |||||
Increase
(decrease) in cash and cash equivalents
|
(823,419 | ) | 851,511 | |||||
Cash
and cash equivalents, beginning
|
951,004 | 99,493 | ||||||
Cash
and cash equivalents, end
|
$ | 127,585 | $ | 951,004 | ||||
Supplemental
disclosures:
|
||||||||
Interest
paid
|
$ | 768,053 | $ | 733,972 | ||||
Income
taxes paid
|
$ | - | $ | - | ||||
Non-cash
transactions:
|
||||||||
Share-based
payments issued for services
|
$ | - | $ | 280,591 |
Weighted
average expected volatility
|
101 | % | ||
Weighted
average expected term (in years)
|
3.95 | |||
Weighted
average expected dividends
|
0 | % | ||
Weighted
average risk free rate
|
4.42 | % |
Options
|
Weighted
Ave. Exercise
Price
|
Warrants
|
Weighted
Ave. Exercise
Price
|
|||||||||||||
Outstanding
April 1, 2007
|
60,000 | $ | 6.25 | - | ||||||||||||
Granted
|
458,500 | 6.30 | 75,000 | $ | 3.00 | |||||||||||
Cancelled
|
(60,000 | ) | (6.25 | ) | - | - | ||||||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
March 31, 2008
|
458,500 | $ | 6.30 | 75,000 | $ | 3.00 | ||||||||||
Granted
|
- | - | - | - | ||||||||||||
Cancelled
|
(20,000 | ) | (6.25 | ) | - | - | ||||||||||
Exercised
|
- | - | - | - | ||||||||||||
Outstanding
March 31, 2009
|
438,500 | $ | 6.30 | 75,000 | $ | 3.00 |
Asset
retirement obligation at April 1, 2007
|
$ | 23,908 | ||
Liabilities
incurred during the period
|
405,450 | |||
Liabilities
settled during the period
|
- | |||
Accretion
|
30,331 | |||
Asset
retirement obligations, March 31, 2008
|
459,689 | |||
Liabilities
incurred during the period
|
283,071 | |||
Liabilities
settled during the period
|
- | |||
Accretion
|
60,864 | |||
Asset
retirement obligations, March 31, 2009
|
$ | 803,624 |
Credit
Facility
|
$ | 7,328,000 | ||
Debentures
|
2,700,000 | |||
Unaccreted
discount
|
(596,108 | ) | ||
Debentures,
net of unaccreted discount
|
2,103,892 | |||
Vehicle
notes payable
|
109,307 | |||
Total
long-term debt
|
9,541,199 | |||
Less
current portion
|
( 1,723,036 | ) | ||
Long-term
debt
|
$ | 7,818,163 |
March
31,
200
9
|
March
31,
200
8
|
|||||||
Non-current
deferred tax asset:
|
||||||||
Impaired
oil & gas costs and long-lived assets
|
$ | 1,864,700 | $ | 312,800 | ||||
Net
operating loss carry-forward
|
2,754,600 | 2,429,900 | ||||||
Valuation
allowance
|
(4 , 619 , 300 | ) | (2,742,700 | ) | ||||
Total
deferred tax net
|
$ | - | $ | - |
March
31,
2009
|
March
31,
2008
|
|||||||
Statutory
tax rate
|
34 | % | 34 | % | ||||
Equity
based compensation
|
(1 | )% | (15 | )% | ||||
Oil
& gas costs and long-lived assets
|
(29 | )% | 1 | % | ||||
Change
in valuation allowance
|
(4 | ) % | (20 | )% | ||||
Effective
tax rate
|
0 | % | 0 | % |
March
31,
2009
|
March
31,
2008
|
|||||||
Production
revenues
|
$ | 6,436,805 | $ | 3,602,798 | ||||
Production
costs
|
(2,637,333 | ) | (1,795,188 | ) | ||||
Depletion
and depreciation
|
( 892,871 | ) | (913,224 | ) | ||||
Results
of operations for producing activities
|
$ | 2,906,601 | $ | 894,386 |
March
31,
2009
|
March
31,
2008
|
|||||||
Proved
|
$ | 8,566,979 | $ | 10,207,596 | ||||
Unevaluated
and unproved
|
31,183 | 62,216 | ||||||
Accumulated
depreciation and depletion
|
(1,817,956 | ) | (925,086 | ) | ||||
Sale
of properties
|
(300,000 | ) | (300,000 | ) | ||||
Net
capitalized costs
|
$ | 6, 480,206 | $ | 9, 044,726 |
March
31,
2009
|
March
31,
2008
|
|||||||
Acquisition
of proved and unproved properties
|
$ | 123,040 | $ | 4,352,040 | ||||
Development
costs
|
2,999,963 | 5,178,281 | ||||||
Exploration
costs
|
- | - | ||||||
Total
|
$ | 3, 12 3, 003 | $ | 9,530,321 |
March 31, 2009
|
March 31, 2008
|
|||||||||||||||
Gas-mcf
|
Oil-stb
|
Gas-mcf
|
Oil-stb
|
|||||||||||||
Proved
reserves:
|
||||||||||||||||
Revisions
of previous estimates
|
(394,732 | ) | (14,575 | ) | - | - | ||||||||||
Purchase
of minerals in place
|
- | 53,280 | 418,959 | 347,228 | ||||||||||||
Extensions
and discoveries
|
- | - | 1,068,683 | |||||||||||||
Production
|
(6,465 | ) | (74,289 | ) | (17,762 | ) | (43,697 | ) | ||||||||
Total
|
- | 1,336,630 | 401,197 | 1,372,214 |
Gas- mcf
|
Oil – stb
|
|||
March 31, 2009
|
March 31, 2009
|
|||
-
|
524,980 |
Gas- mcf
|
Oil stb
|
|||
March 31, 2008
|
March 31, 2008
|
|||
401,197
|
861,240 |
March
31,
2009
|
March
31,
2008
|
|||||||
Future
production revenue
|
$ | 57,007,970 | $ | 132,457,459 | ||||
Future
production costs
|
(24,732,440 | ) | (39,629,625 | ) | ||||
Future
development costs
|
(9,584,500 | ) | (18,827,013 | ) | ||||
Future
cash flows before income taxes
|
22,691,030 | 74,000,821 | ||||||
Future
income taxes
|
- | (19,241,95 4 | ) | |||||
Future
net cash flows
|
22,691,030 | 54,758,867 | ||||||
10%
annual discount for estimating of future
cash
flows
|
( 12,061,690 | ) | (26,558,364 | ) | ||||
Standardized
measure of discounted net
cash
flows
|
$ | 10,629,340 | $ | 28,200,503 |
March
31,
2009
|
March
31,
2008
|
|||||||
Balance
beginning of year
|
$ | 28,200,503 | $ | - | ||||
Sales,
net of production costs
|
(5,697,410 | ) | (1,777,278 | ) | ||||
Net
change in pricing and production costs
|
(31,927,063 | ) | - | |||||
Net
change in future estimated
development
costs
|
9,220,510 | - | ||||||
Purchase
of minerals in place
|
136,190 | 8,124,394 | ||||||
Extensions
and discoveries
|
518,297 | 21,853,387 | ||||||
Revisions
|
(1,089,039 | ) | - | |||||
Accretion
of discount
|
(143,477 | ) | - | |||||
Change
in income tax
|
11,410,829 | - | ||||||
Balance
end of year
|
$ | 10,629,340 | $ | 28,200,503 |
|
1.
|
Section
D5 of the JEA is hereby amended and restated in its entirety as
follows:
|
|
A.
|
The
project revenues from whatever source will be used to repay all debt
associated with the project, including without limitation any loan or debt
incurred by EnerJex to obtain funding for the Black Oaks
Project.
|
|
B.
|
When
the project debt is paid, the working interest of the individual leases
within the Black Oaks block will be assigned to EnerJex in the undivided
interest that the total EnerJex investment bears to the total of that
investment plus the pre-project commencement value stated in paragraph 2
of the Recitals, with the remaining undivided interest (which shall not be
a carried interest) being assigned to MorMeg. The parties agree to
reassign working interest if necessary to redistribute the working
interest according to the above
formula.
|
|
2.
|
Section
D.6 of the JEA is hereby amended and restated in its entirety as
follows:
|
|
3.
|
Any
provision of the JEA, or its amendments expressly granting EnerJex an
option to participate in the Nickel Town prospect is hereby deleted, and
any reference to any option regarding the Nickel Town leases is of no
force or effect by mutual agreement of the
parties.
|
|
4.
|
In
the event of a conflict between this Fourth Amendment and the JEA and any
amendments thereto, this Fourth Amendment shall prevail to the extent of
such conflict.
|
|
5.
|
This
Fourth Amendment shall be of no force and effect upon a material default
by EnerJex under the Credit
Facility.
|
|
6.
|
Other
than as specifically provided in this Fourth Amendment, all other
provisions of the JEA shall remain in full force and
effect. This Fourth Amendment constituting the sole and entire
agreement between the parties as to the matters contained herein, and
supersedes any and all conversations, letters and other communications
which may have been disseminated by the parties relating to the subject
matter hereof, all of which are void and of no
effect.
|
|
7.
|
Any
capitalized terms not defined herein have the meaning set forth in the
JEA.
|
|
8.
|
This
Fourth Amendment may be executed in any number of counterparts, all of
which taken together shall constitute one and the same instrument, and the
parties hereto may execute this Fourth Amendment by signing any such
counterpart.
|
|
9.
|
The
parties hereby agree to take or cause to be taken such action, and to do
and perform all such other acts and things as are necessary, advisable or
appropriate to carry out the intent and terms of this Fourth
Amendment
|
MORMEG,
LLC, a Kansas limited liability company
|
|
By:
|
/s/ Mark Haas
|
Name:
Mark Haas
|
|
Title:
Managing Member
|
/s/ C. Steve Cochennet | |
Name:
Steve Cochennet
|
|
RE:
|
Waiver
Letter (“
Waiver
Letter
”)
regarding Credit Agreement dated July 3, 2008 (as amended, “
Credit
Agreement
”) between Texas Capital Bank, N.A., as a Bank, L/C Issuer
and Administrative Agent (in such latter capacity and together with its
successors and permitted assigns in such capacity, the “
Administrative
Agent
”), the financial institutions from time to time parties
thereto, and EnerJex Resources, Inc., EnerJex Kansas, Inc. and DD Energy,
Inc. (collectively, “
Borrowers
”)
(collectively, the “
Parties
”)
|
Sincerely,
|
||
TEXAS
CAPITAL BANK, N.A.
|
||
By:
|
/s/
Jonathan Gregory
|
|
Jonathan
Gregory
|
||
Executive
Vice President
|
EnerJex
Resources, Inc.
|
EnerJex
Kansas, Inc.
|
By:
|
/s/ C. Steve Cochennet |
By:
|
/s/ C. Steve Cochennet | |
Steve
Cochennet,
|
Steve
Cochennet,
|
|||
Chief
Executive Officer
|
Chief
Executive Officer
|
|||
DD
Energy, Inc.
|
||||
By:
|
/s/ C. Steve Cochennet | |||
Steve
Cochennet,
|
||||
Chief
Executive Officer
|
Name of Subsidiary
|
State of Incorporation
|
Percentage
Ownership
|
||||
DD
Energy, Inc.
|
Nevada
|
100 | % | |||
EnerJex
Kansas, Inc.
|
Nevada
|
100 | % |
MILLER
AND LENTS, LTD.
|
|
By
|
/s/
R. W. Frazier
|
R.
W. Frazier
|
|
Senior
Vice President
|
Weaver
& Martin, LLC
|
1.
|
I have reviewed this Annual
Report on Form 10-K of EnerJex Resources,
Inc.;
|
2.
|
Based on my knowledge, this
report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading
with respect to the period covered by this
report;
|
3.
|
Based on my knowledge, the
financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly
report;
|
4.
|
The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and have:
|
a.
|
Designed such disclosure controls
and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the
period in which this report is being
prepared;
|
b.
|
Designed such internal control
over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance
with generally accepted accounting
principles;
|
c.
|
Evaluated the effectiveness of
the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based
on such evaluation; and
|
d.
|
Disclosed in this report any
change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting;
and
|
5.
|
The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors
and the audit committee of the registrant’s board of directors (or persons
performing the equivalent
functions):
|
a.
|
All significant deficiencies and
material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial
information; and
|
b.
|
Any fraud, whether or not
material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial
reporting.
|
/s/ C. Stephen Cochennet
|
C.
Stephen Cochennet,
|
Chief
Executive Officer
|
(Principal
Executive
Officer)
|
1.
|
I have reviewed this Annual
Report on Form 10-K of EnerJex Resources,
Inc.;
|
2.
|
Based on my knowledge, this
report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of
the circumstances under which such statements were made, not misleading
with respect to the period covered by this
report;
|
3.
|
Based on my knowledge, the
financial statements, and other financial information included in this
report, fairly present in all material respects the financial condition,
results of operations and cash flows of the registrant as of, and for, the
periods presented in this quarterly
report;
|
4.
|
The registrant’s other certifying
officer and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant
and have:
|
a.
|
Designed such disclosure controls
and procedures, or caused such disclosure controls and procedures to be
designed under our supervision, to ensure that material information
relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the
period in which this report is being
prepared;
|
b.
|
Designed such internal control
over financial reporting, or caused such internal control over financial
reporting to be designed under our supervision, to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance
with generally accepted accounting
principles;
|
c.
|
Evaluated the effectiveness of
the registrant’s disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based
on such evaluation; and
|
d.
|
Disclosed in this report any
change in the registrant’s internal control over financial reporting that
occurred during the registrant’s most recent fiscal quarter that has
materially affected, or is reasonably likely to materially affect, the
registrant’s internal control over financial reporting;
and
|
5.
|
The registrant’s other certifying
officer and I have disclosed, based on our most recent evaluation of
internal control over financial reporting, to the registrant’s auditors
and the audit committee of the registrant’s board of directors (or persons
performing the equivalent
functions):
|
a.
|
All significant deficiencies and
material weaknesses in the design or operation of internal control over
financial reporting which are reasonably likely to adversely affect the
registrant’s ability to record, process, summarize and report financial
information; and
|
b.
|
Any fraud, whether or not
material, that involves management or other employees who have a
significant role in the registrant’s internal control over financial
reporting.
|
/s/ Dierdre P. Jones
|
Dierdre
P. Jones,
|
Chief
Financial Officer
|
(Principal
Financial and Accounting
Officer)
|
1.
|
The
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934;
and
|
2.
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
/s/ C. Stephen Cochennet
|
C.
Stephen Cochennet,
|
Chief
Executive Officer
|
(Principal
Executive Officer)
|
1.
|
The
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934;
and
|
2.
|
The
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
/s/ Dierdre P. Jones
|
Dierdre
P. Jones
|
Chief
Financial Officer
|
(Principal
Financial and Accounting
Officer)
|