UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2006
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OR
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number 1-8032
San Juan Basin Royalty
Trust
(Exact name of registrant as
specified in the Amended and Restated San Juan Basin
Royalty Trust Indenture)
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Texas
(State or other
jurisdiction of
incorporation or organization)
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75-6279898
(I.R.S. Employer
Identification No.)
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Compass Bank
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas
(Address of principal
executive offices)
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76116
(Zip Code)
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(866) 809-4553
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Units of Beneficial Interest
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes
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No
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Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes
o
No
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Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes
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No
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Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K.
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Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Act:
Large Accelerated
filer
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Accelerated
filer
o
Non-accelerated
filer
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes
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No
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State the aggregate market value of the Units of Beneficial
Interest held by non-affiliates of the registrant as of
June 30, 2006: $1,814,849,777.
At February 26, 2007, there were 46,608,796 Units of
Beneficial Interest of the Trust outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
“Units of Beneficial Interest” at page 2;
“Description of the Properties” at page 5;
“Trustee’s Discussion and Analysis” at
pages 5 through 11; and “Statements of Assets,
Liabilities and Trust Corpus,” “Statements of
Distributable Income,” “Statements of Changes in Trust
Corpus,” “Notes to Financial Statements,” and
“Report of Independent Registered Public Accounting
Firm” at page 13 et seq., in registrant’s Annual
Report to Unit Holders for the year ended December 31,
2006, are incorporated herein by reference for Item 5
(Market for Registrant’s Units, Related Security Holder
Matters and Issuer Purchases of Units), Item 7
(Trustee’s Discussion and Analysis of Financial Condition
and Results of Operation) and Item 8 (Financial Statements
and Supplementary Data) of Part II of this Report.
TABLE OF CONTENTS
PART I
Certain information included in this Annual Report on
Form 10-K
contains, and other materials filed or to be filed by the
San Juan Basin Royalty Trust (the “Trust”) with
the Securities and Exchange Commission (as well as information
included in oral statements or other written statements made or
to be made by the Trust) may contain or include, forward-looking
statements within the meaning of Section 21E of the
Securities Exchange Act of 1934 and Section 27A of the
Securities Act of 1933. Such forward-looking statements may be
or may concern, among other things, capital expenditures,
drilling activity, development activities, production efforts
and volumes, hydrocarbon prices, estimated future net revenues,
estimates of reserves, the results of the Trust’s
activities, and regulatory matters. Such forward-looking
statements generally are accompanied by words such as
“may,” “will,” “estimate,”
“expect,” “predict,” “project,”
“anticipate,” “goal,” “should,”
“assume,” “believe,” “plan,”
“intend,” or other words that convey the uncertainty
of future events or outcomes. Such statements reflect Burlington
Resources Oil & Gas Company LP’s
(“BROG”), the working interest owner’s, current
view with respect to future events; are based on an assessment
of, and are subject to, a variety of factors deemed relevant by
Compass Bank, the Trustee of the Trust, and BROG and involve
risks and uncertainties. These risks and uncertainties include
volatility of oil and gas prices, product supply and demand,
competition, regulation or government action, litigation and
uncertainties about estimates of reserves. Should one or more of
these risks or uncertainties occur, actual results may vary
materially and adversely from those anticipated.
The Trust is an express trust created under the laws of the
state of Texas by the San Juan Basin Royalty Trust
Indenture (the “Original Indenture”) entered into on
November 3, 1980, between Southland Royalty Company
(“Southland Royalty”) and The Fort Worth National
Bank. Effective as of September 30, 2002, the Original
Indenture was amended and restated (the Original Indenture, as
amended and restated, the “Indenture”). The Trustee of
the Trust is Compass Bank (as a result of the merger discussed
below). The principal office of the Trust is located at 2525
Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116,
Attention: Trust Department (telephone number
(866) 809-4553).
The Trust maintains a website at
www.sjbrt.com.
The Trust
makes available (free of charge) its annual, quarterly and
current reports (and any amendments thereto) filed with the
Securities and Exchange Commission (the “SEC”) through
its website as soon as reasonably practicable after
electronically filing or furnishing such material with or to the
SEC.
On October 23, 1980, the stockholders of Southland Royalty
approved and authorized that company’s conveyance of a 75%
net overriding royalty interest (equivalent to a net profits
interest) to the Trust for the benefit of the stockholders of
Southland Royalty of record at the close of business on the date
of the conveyance (the “Royalty”) carved out of that
company’s oil and gas leasehold and royalty interests (the
“Underlying Properties”) in properties located in the
San Juan Basin of northwestern New Mexico. Pursuant to the
Net Overriding Royalty Conveyance (the “Conveyance”)
the Royalty was transferred to the Trust on November 3,
1980, effective as to production from and after November 1,
1980 at 7:00 a.m.
On March 24, 2006 Compass Bancshares Inc., the parent
company of Compass Bank, completed its acquisition of TexasBanc
Holding Co., the parent company of TexasBank, the prior trustee
of the Trust. On that same date, TexasBank merged with Compass
Bank, and as a result, Compass Bank succeeded TexasBank as
Trustee under the terms of the Indenture.
On February 16, 2007, Compass Bancshares, Inc. announced
the signing of a definitive agreement to be acquired by Banco
Bilbao Vizcaya Argentaria, S.A (“BBVA”). Under the
terms of that agreement, Compass Bancshares, Inc. would
become a wholly-owned subsidiary of BBVA. The transaction is
expected to close in the second half of 2007 and is subject to
the approval of shareholders of BBVA and Compass Bancshares,
Inc. as well as to regulatory approval and customary closing
conditions.
The Royalty was carved out of and now burdens the Underlying
Properties as more particularly described under
“Item 2. Properties” herein.
The Royalty constitutes the principal asset of the Trust. The
beneficial interests in the Royalty are divided into that number
of Units of Beneficial Interest (the “Units”) of the
Trust equal to the number of shares of the common
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stock of Southland Royalty outstanding as of the close of
business on November 3, 1980. Each stockholder of Southland
Royalty of record at the close of business on November 3,
1980 received one freely tradeable Unit for each share of the
common stock of Southland Royalty then held. Holders of Units
are referred to herein as “Unit Holders.” Subsequent
to the Conveyance of the Royalty, through a series of
assignments and mergers, Southland Royalty’s successor
became BROG. On March 31, 2006, a subsidiary of
ConocoPhillips completed its acquisition of Burlington
Resources, Inc., BROG’s parent. As a result, ConocoPhillips
became the parent of Burlington Resources, Inc., which in turn,
is the parent of BROG.
The function of the Trustee is to collect the net proceeds
attributable to the Royalty (“Royalty Income”), to pay
all expenses and charges of the Trust, and then distribute the
remaining available income to the Unit Holders. The Trust is not
empowered to carry on any business activity and has no
employees. All administrative functions are performed by the
Trustee.
The Trust received approximately $136.3 million,
$153.9 million and $111.0 million in Royalty Income
from BROG in each of the fiscal years ended December 31,
2006, 2005 and 2004, respectively. After deducting
administrative expenses and accounting for interest income and
any change in cash reserves, the Trust distributed approximately
$135.9 million, $151.6 million and $109.4 million
to Unit Holders in each of the fiscal years ended
December 31, 2006, 2005 and 2004, respectively. The
Trust’s corpus was approximately $21.8 million,
$23.9 million and $26.7 million as of
December 31, 2006, 2005 and 2004, respectively.
The term “net proceeds,” as used in the Conveyance,
means the excess of “gross proceeds” received by BROG
during a particular period over “production costs” for
such period. “Gross proceeds” means the amount
received by BROG (or any subsequent owner of the Underlying
Properties) from the sale of the production attributable to the
Underlying Properties subject to certain adjustments.
“Production costs” generally means costs incurred on
an accrual basis by BROG in operating the Underlying Properties,
including both capital and non-capital costs. For example, these
costs include development drilling, production and processing
costs, applicable taxes and operating charges. If production
costs exceed gross proceeds in any month, the excess is
recovered out of future gross proceeds prior to the making of
further payment to the Trust, but the Trust is not otherwise
liable for any production costs or other costs or liabilities
attributable to the Underlying Properties or the minerals
produced therefrom. If at any time the Trust receives more than
the amount due under the Royalty, it shall not be obligated to
return such overpayment, but the amounts payable to it for any
subsequent period shall be reduced by such amount, plus
interest, at a rate specified in the Conveyance.
Compliance with state and federal environmental protection laws
could reduce the Royalty Income received by the Trust. Costs of
complying with such laws and regulations affect the production
costs incurred by BROG in operating the Underlying Properties
and may also affect capital expenditures by BROG. The Trust has
no information regarding any estimated capital expenditures by
BROG specifically allocable to environmental control facilities
in the current or succeeding fiscal years.
Certain of the Underlying Properties are operated by BROG with
the obligation to conduct its operations in accordance with
reasonable and prudent business judgment and good oil and gas
field practices. As operator, BROG has the right to abandon any
well when, in its opinion, such well ceases to produce or is not
capable of producing oil and gas in paying quantities. BROG also
is responsible, subject to the terms of an agreement with the
Trust, for marketing the production from such properties, either
under existing sales contracts or under future arrangements at
the best prices and on the best terms it shall deem reasonably
obtainable in the circumstances. BROG also has the obligation to
maintain books and records sufficient to determine the amounts
payable to the Trustee.
Proceeds from production in the first month are generally
received by BROG in the second month, the net proceeds
attributable to the Royalty are paid by BROG to the Trustee in
the third month, and distribution by the Trustee to the Unit
Holders is made in the fourth month. Unit Holders of record as
of the last business day of each month (the “monthly record
date”) will be entitled to receive the calculated monthly
distribution amount for such month on or before ten business
days after the monthly record date. The amount of each monthly
distribution will generally be determined and announced ten days
before the monthly record date. The aggregate monthly
distribution amount is the excess of (i) the net proceeds
attributable to the Royalty paid to the Trustee, plus any
decrease in cash reserves previously established for contingent
liabilities and any other cash receipts of the
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Trust, over (ii) the expenses and payments of liabilities
of the Trust, plus any net increase in cash reserves for
contingent liabilities.
Cash being held by the Trustee as a reserve for liabilities or
contingencies (which reserves may be established by the Trustee
in its discretion) or pending distribution is placed, in the
Trustee’s discretion, in obligations issued by (or
unconditionally guaranteed by) the United States or any agency
thereof, repurchase agreements secured by obligations issued by
the United States or any agency thereof, certificates of deposit
of banks having capital, surplus and undivided profits in excess
of $50,000,000, or money market funds that have been rated AAAmg
or AAAm by Standard & Poor’s and AA by
Moody’s, subject, in each case, to certain other qualifying
conditions.
The Underlying Properties are primarily gas producing
properties. Normally there is a greater demand for gas in the
winter months than during the rest of the year. Otherwise, the
Royalty Income is not subject to seasonal factors nor in any
manner related to or dependent upon patents, licenses,
franchises or concessions. The Trust conducts no research
activities.
The exploration for and the production of gas and oil is a
speculative business. The Trust has no means of ensuring
continued income from the Royalty at the present level or
otherwise. In addition, fluctuations in prices and supplies of
gas and oil and the effect these fluctuations might have on
royalty income to the Trust and on reserves net to the Trust
cannot be accurately projected. The Trustee has no information
with which to make any projections beyond information on
economic conditions that is generally available to the public
and thus is unwilling to make any such projections.
BROG has the right to sell its interest in the Underlying
Properties and has recommended to the Trust that certain
Underlying Properties BROG believes are marginal be sold to
third parties. BROG has asked the Trust to join in the proposed
sale by conveying the Royalty burdening those properties. The
properties BROG proposed to sell constitute less than 2% of the
value of the Royalty. The Trustee is currently evaluating
whether its joinder in such a sale would be in the best interest
of the Unit Holders. Any such sale would require Unit Holder
approval of an amendment to the Indenture that would allow the
Trustee to sell up to a specified percentage of the value of the
Royalty each year without obtaining the consent of Unit Holders.
Although risk factors are described elsewhere in this Annual
Report on
Form 10-K,
the following is a summary of the principal risks associated
with an investment in Units of the Trust.
Oil
and gas prices fluctuate due to a number of factors, and lower
prices will reduce net proceeds to the Trust and distributions
to Unit Holders.
The Trust’s monthly distributions are highly dependent upon
the prices realized from the sale of gas and, to a lesser
extent, oil. Oil and 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 BROG. Factors that contribute to price
fluctuation include, among others:
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political conditions worldwide, in particular political
disruption, war or other armed conflicts in oil producing
regions;
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worldwide economic conditions;
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weather conditions;
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the supply and price of foreign oil and gas;
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the level of consumer demand;
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the price and availability of alternative fuels;
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the proximity to, and capacity of, transportation
facilities; and
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the effect of worldwide energy conservation measures.
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Moreover, government regulations, such as regulation of natural
gas transportation and price controls, can affect product prices
in the long term.
Lower oil and gas prices may reduce the amount of oil and gas
that is economic to produce and reduce net profits to the Trust.
The volatility of energy prices reduces the predictability of
future cash distributions to Unit Holders.
Increased
costs of production and development will result in decreased
Trust distributions.
Production and development costs attributable to the Underlying
Properties are deducted in the calculation of net proceeds.
Accordingly, higher or lower production and development costs,
without concurrent increases in revenues, directly decrease or
increase the share of net proceeds paid to the Trust as Royalty
Income.
If development and production costs of the Underlying Properties
exceed the proceeds of production from the Underlying
Properties, such excess costs are carried forward and the Trust
will not receive a share of net proceeds for the Underlying
Properties until future net proceeds from production from such
properties exceed the total of the excess costs. Development
activities may not generate sufficient additional revenue to
repay the costs; however, the Trust is not obligated to repay
the excess costs except through future production.
Trust
reserve estimates depend on many assumptions that may prove to
be inaccurate, which could cause both estimated reserves and
estimated future revenues to be too high.
The value of the Units of the Trust depends upon, among other
things, the amount of reserves attributable to the Royalty and
the estimated future value of the reserves. Estimating reserves
is inherently uncertain. Ultimately, actual production, revenues
and expenditures for the Underlying Properties will vary from
estimates and those variations could be material. Petroleum
engineers consider many factors and make assumptions in
estimating reserves. Those factors and assumptions include:
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historical production from the area compared with production
rates from similar producing areas;
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the assumed effect of governmental regulation; and
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assumptions about future commodity prices, production and
development costs, severance and excise taxes, and capital
expenditures.
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Changes in these assumptions can materially change reserve
estimates. The reserve data included herein are estimates only
and are subject to many uncertainties. Actual quantities of oil
and natural gas may differ considerably from the amounts set
forth herein. In addition, different reserve engineers may make
different estimates of reserve quantities and cash flows based
upon the same available data.
The
operators of the Underlying Properties are subject to extensive
governmental regulation.
Oil and gas operations have been, and in the future will be,
affected by federal, state and local laws and regulations and
other political developments, such as price or gathering rate
controls and environmental protection regulations.
Operating
risks for BROG and other operators of the Underlying Properties
can adversely affect Trust distributions.
Royalty Income payable to the Trust is derived from the
production and sale of oil and gas, which operations are subject
to risk inherent in such activities, such as blowouts,
cratering, explosions, uncontrollable flows of oil, gas or well
fluids, fires, pollution and other environmental risks and
litigation concerning routine and extraordinary business
activities and events. These risks could result in substantial
losses which are deducted in calculating the net proceeds paid
to the Trust due to injury and loss of life, severe damage to
and destruction of property and equipment, pollution and other
environmental damage and suspension of operations.
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None
of the Trustee, the Trust nor the Unit Holders control the
operation or development of the Underlying
Properties.
Neither the Trustee nor the Unit Holders can influence or
control the operation or future development of the Underlying
Properties. The Underlying Properties are owned by BROG and BROG
operates the majority of such properties and handles the
calculation of the net proceeds attributable to the Royalty and
the payment of Royalty Income to the Trust.
The
Royalty can be sold and the Trust can be terminated in certain
circumstances.
The Trust will be terminated and the Trustee must sell the
Royalty if holders of at least 75% of the Units approve the sale
or vote to terminate the Trust, or if the Trust’s gross
revenue for each of two successive years is less than
$1,000,000 per year. Following any such termination and
liquidation, the net proceeds of any sale will be distributed to
the Unit Holders and Unit Holders will receive no further
distributions from the Trust. We cannot assure you that any such
sale will be on terms acceptable to all Unit Holders.
Mineral
properties, such as the Underlying Properties, are depleting
assets and, if BROG or other operators of the Underlying
Properties do not perform additional development projects, the
assets may deplete faster than expected.
The Royalty Income payable to the Trust is derived from the sale
of depleting assets. Accordingly, the portion of the
distributions to Unit Holders (to the extent of depletion taken)
may be considered a return of capital. The reduction in proved
reserve quantities is a common measure of depletion. Future
maintenance and development projects on the Underlying
Properties will affect the quantity of proved reserves. The
timing and size of these projects will depend on the market
prices of natural gas. If BROG does not implement additional
maintenance and development projects, the future rate of
production decline of proved reserves may be higher than the
rate currently expected by the Trust.
Unit
Holders have limited voting rights.
Voting rights as a Unit Holder are more limited than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of Unit Holders or for an
annual or other periodic re-election of the Trustee. Unlike
corporations, which are generally governed by boards of
directors elected by their equity holders, the Trust is
administered by a corporate Trustee in accordance with the
Indenture and other organizational documents. The Trustee has
extremely limited discretion in its administration of the Trust.
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ITEM 1B.
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UNRESOLVED
STAFF COMMENTS
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The Trust has not received any written comments from the SEC
staff regarding its periodic or current reports under the
Securities Exchange Act of 1934 that remain unresolved.
The Royalty conveyed to the Trust was carved out of Southland
Royalty’s (now BROG’s) working interests and royalty
interests in certain properties situated in the San Juan
Basin in northwestern New Mexico. See “Item 1.
Business” for information on the conveyance of the Royalty
to the Trust. References below to “gross” wells and
acres are to the interests of all persons owning interests
therein, while references to “net” are to the
interests of BROG (from which the Royalty was carved) in such
wells and acres.
Unless otherwise indicated, the following information in this
Item 2 is based upon data and information furnished to the
Trustee by BROG.
Producing
Acreage, Wells and Drilling
The Underlying Properties consist of working interests, royalty
interests, overriding royalty interests and other contractual
rights in 151,900 gross (119,000 net) producing acres
in San Juan, Rio Arriba and Sandoval Counties of
northwestern New Mexico and 4,616 gross (1,286 net)
economic wells, including dual completions. Production
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from conventional gas wells is primarily from the Pictured
Cliffs, Mesaverde and Dakota formations. During 1988, Southland
Royalty began development of coal seam reserves in the Fruitland
Coal formation.
The Royalty conveyed to the Trust is limited to the base of the
Dakota formation, which is currently the deepest significant
producing formation under acreage affected by the Royalty.
Rights to production, if any, from deeper formations are
retained by BROG.
During 2006, in calculating Royalty Income, BROG deducted
$39.2 million of capital expenditures for projects,
including drilling and completion of 115 gross
(24.14 net) conventional wells, two gross (0.003 net)
payadds, two gross (1.74 net) recompletions, three gross
(2.50 net) restimulations, 44 gross (14.63 net)
coal seam wells, seven gross (0.28 net) coal seam payadds,
two gross (0.048 net) coal seam recompletions, and two
gross (0.08 net) coal seam miscellaneous capital projects.
A payadd is the completion of an additional productive interval
in an existing completed zone in a well.
The aggregate capital expenditures deducted by BROG in
calculating Royalty Income for 2006 include approximately
$12.2 million attributable to the capital budgets for prior
years. This occurs because projects within a given year’s
budget may extend into subsequent years, with capital
expenditures attributable to those projects used in calculating
distributable income to the Trust in those subsequent years.
Further, BROG’s accounting period for capital expenditures
runs through November 30 of each calendar year, such that
capital expenditures incurred in December of each year are
actually accounted for as part of the following year’s
capital expenditures. In addition, with respect to wells not
operated by BROG, BROG’s share of capital expenditures may
not actually be paid by it until the year or years after those
expenses were incurred by the operator. Capital expenditures of
approximately $24.8 million for 2006 budgeted projects were
deducted in calculating net proceeds payable to the Trust in
calendar year 2006, and approximately $7.1 million in
capital expenditures from the 2006 budget were deducted in
calculating net proceeds payable to the Trust for January and
February 2007. Therefore, an additional approximately
$5.7 million in capital expenditures for budgeted 2006
projects remains to be spent.
During 2005, in calculating Royalty Income, BROG deducted
approximately $19.1 million of capital expenditures for
projects, including drilling and completion of 38 gross
(2.72 net) conventional wells, five gross (0.011 net)
payadds, one gross (0.57 net) conventional restimulation,
25 gross (2.89 net) coal seam wells, one gross
(0.99 net) coal seam recavitation, two gross (0.61 net)
coal seam recompletions, and five gross (0.20 net)
miscellaneous coal seam capital projects. There were
110 gross (19.08 net) conventional wells, eight gross
(1.73 net) payadds, six gross (3.30 net) conventional
recompletions, seven gross (5.04 net) conventional
restimulations, 59 gross (10.06 net) coal seam wells,
five gross (2.32 net) coal seam recompletions, and one
gross (0.04 net) miscellaneous coal seam capital project in
progress as of December 31, 2005.
BROG has informed the Trust that its budget for capital
expenditures for the Underlying Properties in 2007 is estimated
at $28.0 million. Approximately $24.0 million of that
budget is allocable to 112 new wells, including 33 wells
scheduled to be dually completed in the Mesaverde and Dakota
formations and ten wells scheduled to be dually completed in the
Fruitland Coal and Pictured Cliffs formations. BROG indicates
that a total of 34 of the new wells, at an aggregate cost of
approximately $11.4 million, are projected to be drilled to
formations producing coal seam gas. BROG reports that based on
its actual capital requirements, the pace of regulatory
approvals, and the mix of projects and swings in the price of
natural gas, the actual capital expenditures for 2007 could
range from $20.0 million to $50.0 million. BROG
anticipates 416 projects, including the drilling of 67 new wells
to be operated by BROG and 45 wells to be operated by third
parties. Of the new BROG operated wells, 48 are projected to be
conventional wells completed or dually completed to the Pictured
Cliffs, Mesaverde,
and/or
Dakota formations, seven are scheduled to be dually completed to
both conventional and coal seam formations, and the remaining 12
are projected to be completed in the Fruitland Coal formation. A
total of 30 of the wells operated by third parties are projected
to be conventional wells, and the remaining 15 are to be coal
seam wells, with five of the 15 projected coal seam wells to be
dually completed in the Fruitland Coal and Pictured Cliffs
formations. The budget for 2007 reflects the continuation of a
shift toward increased development of conventional gas and a
reduction of its program for infill drilling in the Fruitland
Coal formation.
In February 2002, BROG informed the Trust that the New Mexico
Oil Conservation Division (the “OCD”) had approved
plans for
80-acre
infill drilling of the Dakota formation in the San Juan
Basin. In July 2003, the OCD
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approved
160-acre
density in the Fruitland Coal formation.
Eighty-acre
density has been permitted in the Mesaverde formation since 1997.
Oil and
Gas Production
The Trust recognizes production during the month in which the
related net proceeds attributable to the Royalty are paid to the
Trust. Royalty Income for a calendar year is based on the actual
gas and oil production during the period beginning with November
of the preceding calendar year through October of the current
calendar year. Production of oil and gas and related average
sales prices attributable to the Royalty for the three years
ended December 31, 2006, were as follows:
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|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
|
|
Production
|
|
|
22,475,405
|
|
|
|
40,702
|
|
|
|
26,600,644
|
|
|
|
43,142
|
|
|
|
25,324,435
|
|
|
|
44,832
|
|
|
Average Price
|
|
$
|
6.55
|
|
|
$
|
61.30
|
|
|
$
|
6.27
|
|
|
$
|
49.62
|
|
|
$
|
4.68
|
|
|
$
|
34.81
|
|
Pricing
Information
Gas produced in the San Juan Basin is sold in both
interstate and intrastate commerce. Reference is made to the
discussion contained herein under “Regulation” for
information as to federal regulation of prices of oil and
natural gas. Gas production from the Underlying Properties
totaled 40,900,570 Mcf during 2006.
On September 4, 1996, the Trustee announced a settlement of
litigation filed by the Trustee against BROG (the “1996
Settlement”). In the 1996 Settlement, agreement was
reached, among other things, regarding marketing arrangements
for the sale of those gas, oil and natural gas liquids products
from the Underlying Properties going forward as follows:
(i) BROG agreed that all subsequent contracts for the sale
of gas from the Underlying Properties would require the written
approval of an independent gas marketing consultant acceptable
to the Trust;
(ii) BROG will continue to market the oil and natural gas
liquids from the Underlying Properties but will make payments to
the Trust based on actual proceeds from such sales, and BROG
will no longer use posted prices as the basis for calculating
proceeds to the Trust nor make a deduction for marketing fees
associated with sales of oil or natural gas liquids
products; and
(iii) The independent marketer of the gas from the
Underlying Properties is entitled to use of BROG’s current
gas transportation, gathering, processing and treating
agreements with third parties, at least through the remainder of
their primary terms.
BROG previously entered into two contracts for the sale of all
volumes of gas produced from the Underlying Properties. These
contracts provided for (i) the sale of such gas to Duke
Energy and Marketing, L.L.C. and PNM Gas Services
(“PNM”), respectively, (ii) the delivery of such
gas at various delivery points through March 31, 2005, and
from
year-to-year
thereafter until terminated by either party on twelve
months’ notice, and (iii) the sale of such gas at
prices which fluctuate in accordance with published indices for
gas sold in the San Juan Basin of New Mexico. Effective
January 1, 2004, the rights and obligations of Duke Energy
and Marketing, L.L.C. were assumed by ConocoPhillips Company
(“ConocoPhillips”) pursuant to an Assignment and
Novation Agreement. By correspondence dated March 25, 2004,
BROG notified ConocoPhillips of BROG’s election to
terminate such contract as of March 31, 2005. BROG then
prepared a form of request for proposal and circulated it to a
number of potential purchasers, including ConocoPhillips,
inviting them to bid for the purchase of the gas currently sold
under the contract expiring March 31, 2005. Effective as of
April 1, 2005, BROG entered into two new contracts for the
sale of all volumes of gas produced from the Underlying
Properties and formerly sold to ConocoPhillips. These
new contracts provide for (i) the sale of such gas to
ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc.
(“ChevronTexaco”), and Coral Energy Resources, L.P.
(“Coral”), respectively, (ii) the delivery of
such gas at various delivery points through March 31, 2007,
and from
year-to-year
thereafter until terminated by either party on twelve
months’ notice, and (iii) the sale of such gas at
prices which fluctuate in accordance with the published indices
for gas sold in the San Juan Basin of New Mexico. With
respect to BROG’s contract with PNM, BROG and
8
PNM entered into a letter agreement dated January 31, 2005,
pursuant to which the parties waived the right to terminate the
underlying contract as of March 31, 2006, so that the term
of that contract will continue until at least March 31,
2007, and from
year-to-year
thereafter until terminated by either party upon twelve
months’ notice to the other. Neither BROG nor any of
ChevronTexaco, Coral nor PNM gave notice to terminate the three
contracts described above for the sale of all volumes of gas
produced from the Underlying Properties and, accordingly, the
terms of those contracts have been extended through
March 31, 2008.
Confidentiality agreements with purchasers of gas produced from
the Underlying Properties prohibit public disclosure of certain
terms and conditions of gas sales contracts with those entities,
including specific pricing terms, gas receipt points. Such
disclosure could compromise the ability to compete effectively
in the marketplace for the sale of gas produced from the
Underlying Properties.
Oil and
Gas Reserves
The following are definitions adopted by the SEC and the
Financial Accounting Standards Board which are applicable to
terms used within this Annual Report on
Form 10-K:
“Estimated future net revenues” are computed by
applying current prices of oil and gas (with consideration of
price changes only to the extent provided by contractual
arrangements and allowed by federal regulation) to estimated
future production of proved oil and gas reserves as of the date
of the latest balance sheet presented, less estimated future
expenditures (based on current costs) to be incurred in
developing and producing the proved reserves, and assuming
continuation of existing economic conditions. “Estimated
future net revenues” are sometimes referred to in this
Annual Report on
Form 10-K
as “estimated future net cash flows.”
“Present value of estimated future net revenues” is
computed using the estimated future net revenues (as defined
above) and a discount rate of 10%.
“Proved reserves” are those estimated quantities of
crude oil, 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
oil and gas reservoirs under existing economic and operating
conditions.
“Proved developed reserves” are those proved reserves
which can be expected to be recovered through existing wells
with existing equipment and operating methods.
“Proved undeveloped reserves” are those proved
reserves which are expected to be recovered from new wells on
undrilled acreage, or from existing wells where a relatively
major expenditure is required.
9
The independent petroleum engineers’ reports as to the
proved oil and gas reserves as of December 31, 2004, 2005
and 2006, were prepared by Cawley, Gillespie &
Associates, Inc. The following table presents a reconciliation
of proved reserve quantities attributable to the Royalty from
December 31, 2003, to December 31, 2006, (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
|
|
|
Natural
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
|
|
Reserves as of December 31,
2003
|
|
|
382
|
|
|
|
240,609
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
102
|
|
|
|
26,415
|
|
|
Extensions, discoveries and other
additions
|
|
|
20
|
|
|
|
15,236
|
|
|
Production
|
|
|
(45
|
)
|
|
|
(25,324
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Reserves as of December 31,
2004
|
|
|
459
|
|
|
|
256,936
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
15
|
|
|
|
14,401
|
|
|
Extensions, discoveries and other
additions
|
|
|
23
|
|
|
|
17,023
|
|
|
Production
|
|
|
(43
|
)
|
|
|
(26,601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Reserves as of December 31,
2005
|
|
|
454
|
|
|
|
261,759
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
(33
|
)
|
|
|
(27,467
|
)
|
|
Extensions, discoveries and other
additions
|
|
|
20
|
|
|
|
8,644
|
|
|
Production
|
|
|
(41
|
)
|
|
|
(22,475
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Reserves as of December 31,
2006
|
|
|
400
|
|
|
|
220,461
|
|
|
|
|
|
|
|
|
|
|
|
Estimated quantities of proved developed reserves of crude oil
and natural gas as of December 31, 2006, 2005 and 2004 were
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Crude Oil (Bbls)
|
|
|
357
|
|
|
|
395
|
|
|
|
419
|
|
|
Natural Gas (Mcf)
|
|
|
197,466
|
|
|
|
231,235
|
|
|
|
235,272
|
|
Generally, the calculation of oil and gas reserves takes into
account a comparison of the value of the oil or gas to the cost
of producing those minerals, in an attempt to cause minerals in
the ground to be included in reserve estimates only to the
extent that the anticipated costs of production will be exceeded
by the anticipated sales revenue. Accordingly, an increase in
sales price
and/or
a
decrease in production cost can itself result in an increase in
estimated reserves and declining prices
and/or
increasing costs can result in reserves reported at less than
the physical volumes actually thought to exist. The Financial
Accounting Standards Board requires supplemental disclosures for
oil and gas producers based on a standardized measure of
discounted future net cash flows relating to proved oil and gas
reserve quantities. Under this disclosure, future cash inflows
are estimated by applying year-end prices of oil and gas
relating to the enterprise’s proved reserves to the
year-end quantities of those reserves, less estimated future
expenditures (based on current costs) of developing and
producing the proved reserves, and assuming continuation of
existing economic conditions. Future price changes are only
considered to the
extent provided by contractual arrangements in existence at
year-end. The standardized measure of discounted future net cash
flows is achieved by using a discount rate of 10% a year to
reflect the timing of future net cash flows relating to proved
oil and gas reserves.
Estimates of proved oil and gas reserves are by their nature
imprecise. Estimates of future net revenue attributable to
proved reserves are sensitive to the unpredictable prices of oil
and gas and other variables. Accordingly, under the allocation
method used to derive the Trust’s quantity of proved
reserves, changes in prices will result in changes in quantities
of proved oil and gas reserves and estimated future net revenues.
10
The 2006, 2005 and 2004 changes in the standardized measure of
discounted future net cash flows related to future royalty
income from proved reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Balance, January 1
|
|
$
|
1,090,324
|
|
|
$
|
756,017
|
|
|
$
|
497,701
|
|
|
Revisions of prior-year estimates,
change in prices and other
|
|
|
(345,237
|
)
|
|
|
339,865
|
|
|
|
272,251
|
|
|
Extensions, discoveries and other
additions
|
|
|
28,520
|
|
|
|
72,698
|
|
|
|
47,338
|
|
|
Accretion of discount
|
|
|
109,032
|
|
|
|
75,602
|
|
|
|
49,770
|
|
|
Royalty Income
|
|
|
(136,312
|
)
|
|
|
(153,858
|
)
|
|
|
(111,043
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
746,327
|
|
|
$
|
1,090,324
|
|
|
$
|
756,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve quantities and revenues shown in the tables above for
the Royalty were estimated from projections of reserves and
revenues attributable to the combined BROG and Trust interests.
Reserve quantities attributable to the Royalty were derived from
estimates by allocating to the Royalty a portion of the total
net reserve quantities of the interests, based upon gross
revenue less production taxes. Because the reserve quantities
attributable to the Royalty are estimated using an allocation of
the reserves, any changes in prices or costs will result in
changes in the estimated reserve quantities allocated to the
Royalty. Therefore, the reserve quantities estimated will vary
if different future price and cost assumptions occur. The future
net cash flows were determined without regard to future federal
income tax credits available to production from coal seam wells.
December average prices of $7.09 per Mcf of conventional
gas, $5.48 per Mcf of coal seam gas and $58.65 per Bbl
of oil were used at December 31, 2006, in determining
future net revenue. The downward revision in reserve quantities
for 2006 is due primarily to lower gas prices in December 2006
as compared to December 2005.
December average prices of $9.04 per Mcf of conventional
gas, $7.05 per Mcf of coal seam gas and $54.17 per Bbl
of oil were used at December 31, 2005, in determining
future net revenue. The upward revision in reserve quantities
for 2005 as compared to 2004 is due in part to higher oil and
gas prices in December 2005 as compared to December 2004.
December average prices of $6.33 per Mcf of conventional
gas, $4.82 per Mcf of coal seam gas and $38.79 per Bbl
of oil were used at December 31, 2004, in determining
future net revenue.
The following presents estimated future net revenues and present
value of estimated future net revenues attributable to the
Royalty for each of the years ended December 31, 2006, 2005
and 2004 (in thousands, except amounts per Unit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Estimated
|
|
|
Present
|
|
|
Estimated
|
|
|
Present
|
|
|
Estimated
|
|
|
Present
|
|
|
|
|
Future
|
|
|
Value
|
|
|
Future
|
|
|
Value
|
|
|
Future
|
|
|
Value
|
|
|
|
|
Net
|
|
|
at
|
|
|
Net
|
|
|
at
|
|
|
Net
|
|
|
at
|
|
|
|
|
Revenue
|
|
|
10%
|
|
|
Revenue
|
|
|
10%
|
|
|
Revenue
|
|
|
10%
|
|
|
|
|
Total Proved
|
|
$
|
1,337,575
|
|
|
$
|
746,327
|
|
|
$
|
2,018,722
|
|
|
$
|
1,090,324
|
|
|
$
|
1,382,108
|
|
|
$
|
756,017
|
|
|
Proved Developed
|
|
$
|
1,198,784
|
|
|
$
|
677,276
|
|
|
$
|
1,785,597
|
|
|
$
|
965,615
|
|
|
$
|
1,264,556
|
|
|
$
|
696,430
|
|
|
Total Proved Per Unit
|
|
$
|
28.70
|
|
|
$
|
16.01
|
|
|
$
|
43.31
|
|
|
$
|
23.39
|
|
|
$
|
29.65
|
|
|
$
|
16.22
|
|
Proved reserve quantities are estimates based on information
available at the time of preparation and such estimates are
subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of
those reserves may be substantially different from the above
estimates. Moreover, the present values shown above should not
be considered the market values of such oil and gas reserves or
the costs that would be incurred to acquire equivalent reserves.
A market value determination would require the analysis of
additional parameters.
11
Regulation
Many aspects of the production, pricing and marketing of crude
oil and natural gas are regulated by federal and state agencies.
Legislation affecting the oil and gas industry is under constant
review for amendment or expansion, frequently increasing the
regulatory burden on affected members of the industry.
Exploration and production operations are subject to various
types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate
wells, and regulating the location of wells, the method of
drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled and the plugging and
abandonment of wells. Natural gas and oil operations are also
subject to various conservation laws and regulations that
regulate the size of drilling and spacing units or proration
units and the density of wells which may be drilled and
unitization or pooling of oil and gas properties. In addition,
state conservation laws establish maximum allowable production
from natural gas and oil wells, generally prohibit the venting
or flaring of natural gas and impose certain requirements
regarding the ratability of production. The effect of these
regulations is to limit the amounts of natural gas and oil that
BROG can produce and to limit the number of wells or the
locations at which BROG can drill.
Federal
Natural Gas Regulation
The transportation and sale for resale of natural gas in
interstate commerce, historically, have been regulated pursuant
to several laws enacted by Congress and the regulations
promulgated under these laws by the Federal Energy Regulatory
Commission (“FERC”) and its predecessor. In the past,
the federal government has regulated the prices at which gas
could be sold. Congress removed all non-price controls affecting
wellhead sales of natural gas effective January 1, 1993.
Congress could, however, reenact price controls in the future.
Sales of natural gas are affected by the availability, terms and
cost of transportation. The price and terms for access to
pipeline transportation remain subject to extensive federal and
state regulation. Several major regulatory changes have been
implemented by Congress and FERC from 1985 to the present that
affect the economics of natural gas production, transportation
and sales. In addition, FERC continues to promulgate revisions
to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate
natural gas transmission companies, that remain subject to
FERC’s jurisdiction. These initiatives may also affect the
intrastate transportation of gas under certain circumstances.
The stated purpose of many of these regulatory changes is to
promote competition among the various sectors of the natural gas
industry and these initiatives generally reflect more
light-handed regulation of the natural gas industry.
Additional proposals and proceedings that might affect the
natural gas industry are considered from time to time by
Congress, FERC, state regulatory bodies and the courts. The
Trust cannot predict when or if any such proposals might become
effective, or their effect, if any, on the Trust. The natural
gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent
regulatory approach pursued over the last decade by FERC and
Congress will continue.
Sales of crude oil, condensate and gas liquids are not currently
regulated and are made at market prices. The ability to
transport and sell petroleum products are dependent on pipelines
whose rates, terms and conditions of service are subject to FERC
jurisdiction under the Interstate Commerce Act. Certain
regulations implemented by FERC in recent years could result in
an increase in the cost of transportation service on certain
petroleum products pipelines.
Section 45
Tax Credit
Sales of gas production from certain coal seam wells drilled
prior to January 1, 1993, qualified for federal income tax
credits under Section 29 (now Section 45K) of the
Internal Revenue Code of 1986, as amended (the
“Code”), through 2002 but not thereafter. Accordingly,
under present law, the Trust’s production and sale of gas
from coal seam wells does not qualify for tax credit under
Section 45K of the Code (the “Section 45K Tax
Credit”). Congress has at various times since 2002
considered energy legislation, including provisions to reinstate
the Section 45K Tax Credit in various ways and to various
extents, but no legislation that would qualify the Trust’s
current production for such credit has been enacted. For
example, on August 8, 2005, new energy tax legislation was
12
enacted which, among other things, modified the Section 45K
Tax Credit in several respects, but did not extend the credit
for production from coal seam wells. No prediction can be made
as to what future tax legislation affecting Section 45K of
the Code may be proposed or enacted or, if enacted, its impact,
if any, on the Trust and the Unit Holders.
Passive
Loss Rules
The classification of the Trust’s income for purposes of
the passive loss rules may be important to a Unit Holder.
As a result of the Tax Reform Act of 1986, royalty income such
as that derived through the Trust will generally be treated as
portfolio income and will not reduce passive losses.
Other
Regulation
The oil and natural gas industry is also subject to compliance
with various other federal, state and local regulations and
laws, including, but not limited to, environmental protection,
occupational safety, resource conservation and equal employment
opportunity.
|
|
|
|
ITEM 3.
|
LEGAL
PROCEEDINGS
|
As discussed herein under Part II, Item 9A (Controls
and Procedures), due to the pass-through nature of the Trust,
BROG provides much of the information disclosed in this Annual
Report on
Form 10-K
and the other periodic reports filed by the Trust with the SEC.
Although the Trustee receives periodic updates from BROG
regarding activities which may relate to the Trust, the
Trust’s ability to timely report certain information
required to be disclosed in the Trust’s periodic reports is
dependent on BROG’s timely delivery of the information to
the Trust.
On November 11, 2005, an Arbitration Award was issued in
favor of the Trust in the aggregate amount of $7,683,699 in
arbitration styled
San Juan Basin Royalty Trust vs.
Burlington Resources Oil & Gas Company
LP.
The purpose of the arbitration was to resolve
certain joint interest audit issues as between the parties to
the arbitration. On November 21, 2005, BROG filed its
Original Petition to Vacate or to Modify or Correct Arbitration
Award in the case styled
Burlington Resources Oil &
Gas Company LP vs. San Juan Basin Royalty Trust
,
No. 2005-74370,
in the District Court of Harris County, Texas,
281
st
Judicial
District. In this litigation, BROG alleged that the award in
favor of the Trust should be vacated or modified because one of
the issues decided was beyond the scope of the matters agreed to
be arbitrated, the award was issued in manifest disregard of
applicable law, and a portion of the award is barred by
limitations. BROG also sought to recover its attorneys’
fees. The Trust filed an answer and counterclaim in the
litigation filed by BROG denying those allegations and asking
that the arbitrator’s award be confirmed. On April 20,
2006, the Court entered an Order denying BROG’s motion to
vacate and granting the Trust’s application to confirm the
Arbitration Award and on June 6, 2006, rendered a final
judgment in favor of the Trust. However, on May 22, 2006,
BROG filed a Notice of Appeal indicating its desire to appeal
the Order and any final judgment confirming the Arbitration
Award and on July 5, 2006, filed a Motion for New Trial in
the District Court of Harris County, Texas, urging substantially
similar arguments made at the hearing. The Trust responded to
the Motion for New Trial and served BROG with post-judgment
discovery requests. BROG’s Motion for New Trial was
overruled on August 4, 2006. BROG’s distribution to
the Trust for July 2006 included $1,534,182 representing a
portion of the Arbitration Award, plus accrued interest. Of this
amount, $1,325,826 (the equivalent of $994,270 grossed up
to account for the Trust’s 75% net overriding royalty
interest) was included in calculating the net proceeds paid to
the Trust, and the accrued interest thereon was $539,812. The
balance of the Arbitration Award is pending BROG’s appeal,
which has been assigned
No. 01-06-00485-CV
in the First Court of Appeals in Houston, Texas. On
August 24, 2006, BROG filed its Supersedeas Bond to secure
payment of the balance of the Arbitration Award, plus interest,
if the appeal is dismissed or BROG does not perform the adverse
judgment which becomes final on appeal. BROG filed its Brief of
Appellant in the First Court of Appeals on November 29,
2006. The Trust filed its Brief of Appellee on January 29,
2007. BROG was entitled to file its reply brief on or before
February 20, 2007, but on February 16, 2007, BROG
filed a motion requesting an extension through March 22,
2007. Once all briefs are filed, the parties will await either a
ruling on their respective requests to present oral arguments or
a ruling on the merits based solely on the briefs. No reliable
estimate can be given as to when the First Court of Appeals will
act and it should be noted that the ruling of that Court on the
merits of the appeal will itself be subject to possible
discretionary review by the Texas Supreme Court.
13
In addition to the legal proceedings described above, BROG is
involved in various legal proceedings, the outcome of which may
impact the Trust. Should certain legal proceedings to which BROG
is a party be decided in a manner adverse to BROG, the amount of
Royalty Income received by the Trust could materially decrease.
The Trust has not received from BROG any estimate of the amount
of any potential loss in such proceedings, or the portion of any
such potential loss that might be allocated to the Royalty.
|
|
|
|
ITEM 4.
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
No matters were submitted to a vote of Unit Holders, through the
solicitation of proxies or otherwise, during the fourth quarter
ended December 31, 2006.
PART II
|
|
|
|
ITEM 5.
|
MARKET
FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND
ISSUER PURCHASES OF UNITS
|
The information under “Units of Beneficial Interest”
at page 2 of the Trust’s Annual Report to Unit Holders
for the year ended December 31, 2006, is herein
incorporated by reference. The Trust has no directors, executive
officers or employees. Accordingly, the Trust does not maintain
any equity compensation plans and there are no Units reserved
for issuance under any such plans.
|
|
|
|
ITEM 6.
|
SELECTED
FINANCIAL DATA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
|
Royalty Income
|
|
$
|
136,311,892
|
|
|
$
|
153,858,264
|
|
|
$
|
111,042,767
|
|
|
$
|
91,997,262
|
|
|
$
|
38,053,281
|
|
|
Distributable income
|
|
|
135,867,325
|
|
|
|
151,560,081
|
|
|
|
109,390,735
|
|
|
|
90,357,837
|
|
|
|
36,417,967
|
|
|
Distributable income per Unit
|
|
|
2.915055
|
|
|
|
3.251747
|
|
|
|
2.346998
|
|
|
|
1.938644
|
|
|
|
0.781354
|
|
|
Distributions per Unit
|
|
|
2.915055
|
|
|
|
3.251747
|
|
|
|
2.346998
|
|
|
|
1.938644
|
|
|
|
0.781354
|
|
|
Total assets, December 31
|
|
|
26,481,276
|
|
|
|
43,054,656
|
|
|
|
36,814,866
|
|
|
|
36,905,104
|
|
|
|
37,972,696
|
|
|
|
|
|
ITEM 7.
|
TRUSTEE’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
|
The “Description of the Properties” and
“Trustee’s Discussion and Analysis” at
pages 5 through 11 of the Trust’s Annual Report to
Unit Holders for the year ended December 31, 2006, are
herein incorporated by reference.
|
|
|
|
ITEM 7A.
|
QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
The Trust invests in no derivative financial instruments, and
has no foreign operations or long-term debt instruments. The
Trust is a passive entity and is prohibited from engaging in any
business or commercial activity of any kind whatsoever,
including borrowing transactions, other than the Trust’s
ability to borrow money periodically as necessary to pay
expenses, liabilities and obligations of the Trust that cannot
be paid out of cash held by the Trust. The amount of any such
borrowings is unlikely to be material to the Trust. The Trust
periodically holds short-term investments acquired with funds
held by the Trust pending distribution to Unit Holders and funds
held in reserve for the payment of Trust expenses and
liabilities. Because of the short-term nature of these
borrowings and investments and certain limitations upon the
types of such investments which may be held by the Trust, the
Trustee believes that the Trust is not subject to any material
interest rate risk. The Trust does not engage in transactions in
foreign currencies which could expose the Trust or Unit Holders
to any foreign currency related market risk. The Trust does not
market the gas, oil
and/or
natural gas liquids from the Underlying Properties. BROG is
responsible for such marketing.
|
|
|
|
ITEM 8.
|
FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA
|
The Financial Statements of the Trust and the notes thereto at
page 13 et seq., of the Trust’s Annual Report to Unit
Holders for the year ended December 31, 2006, are herein
incorporated by reference.
14
|
|
|
|
ITEM 9.
|
CHANGES
IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
|
Within the two most recent fiscal years, there have been no
changes in and disagreements with the Trust’s independent
accountants.
|
|
|
|
ITEM 9A.
|
CONTROLS
AND PROCEDURES
|
The Trust maintains a system of disclosure controls and
procedures that is designed to ensure that information required
to be disclosed in the Trust’s filings under the Securities
Exchange Act of 1934 (the “Exchange Act”) is recorded,
processed, summarized and reported, within the time periods
specified in the SEC’s rules and forms. Disclosure controls
and procedures include controls and procedures designed to
ensure that information required to be disclosed by the Trust is
accumulated and communicated by BROG to the Trustee and its
employees who participate in the preparation of the Trust’s
periodic reports to allow timely decisions regarding disclosure.
Due to the pass-through nature of the Trust, BROG provides much
of the information disclosed in this Annual Report on
Form 10-K
and the other periodic reports filed by the Trust with the SEC.
The Indenture does not require BROG to update or provide
information to the Trust. Under the Conveyance transferring the
Royalty to the Trust, BROG is obligated to provide the Trust
with certain information concerning calculations of net proceeds
owed to the Trust, among other information. Pursuant to the 1996
Settlement, BROG agreed to new, more formal financial reporting
and audit procedures as compared to those provided in the
Conveyance.
The Trustee receives periodic updates from BROG regarding
activities related to the Trust. Accordingly, the Trust’s
ability to timely report certain information required to be
disclosed in the Trust’s periodic reports is dependent on
BROG’s timely delivery of such information to the Trust. In
order to help ensure the accuracy and completeness of the
information required to be disclosed in the Trust’s
periodic reports, the Trust employs independent public
accountants, joint interest auditors, marketing consultants,
attorneys and petroleum engineers. These outside professionals
advise the Trustee in its review and compilation of this
information for inclusion in this
Form 10-K
and the other periodic reports provided by the Trust to the SEC.
The Trustee has evaluated the Trust’s disclosure controls
and procedures as of December 31, 2006, and has concluded
that such disclosure controls and procedures are effective at
the “reasonable assurance” level (as such term is used
in
Rule 13a-15(f)
of the Exchange Act) to ensure that material information related
to the Trust is gathered on a timely basis to be included in the
Trust’s periodic reports. In reaching its conclusion, the
Trustee considered the Trust’s dependence on BROG to
deliver timely and accurate information to the Trust. The
Trustee has not reviewed the Trust’s disclosure controls
and procedures in concert with management, a board of directors
or an independent audit committee. The Trust does not have, nor
does the Indenture provide for, officers, a board of directors
or an independent audit committee.
During the quarter ended December 31, 2005, there were no
changes in the Trust’s internal control over financial
reporting (as defined in
Rule 13a-15(f)
of the Exchange Act) that materially affected, or are reasonably
likely to materially affect, the Trust’s internal control
over financial reporting. The Trustee has not evaluated the
Trust’s internal control over financial reporting in
concert with management, a board of directors or an independent
audit committee. The Trust does not have, nor does the Indenture
provide for, officers, a board of directors or an independent
audit committee.
15
Trustee’s
Report on Internal Control Over Financial Reporting
Compass Bank, in its capacity as trustee (the
“Trustee”) of San Juan Basin Royalty Trust (the
“Trust”) is responsible for establishing and
maintaining adequate internal control over financial reporting.
The Trust’s internal control over financial reporting is a
process designed under the supervision of the Trustee to provide
reasonable assurance regarding the reliability of financial
reporting and the preparation of the Trust’s financial
statements for external purposes in accordance with a modified
cash basis of accounting, which is a comprehensive basis of
accounting other than U.S. generally accepted accounting
principles.
As of December 31, 2006, the Trustee assessed the
effectiveness of the Trust’s internal control over
financial reporting based on the criteria for effective internal
control over financial reporting established in “Internal
Control — Integrated Framework”, issued by the
Committee of Sponsoring Organizations of the Treadway
Commission. Based on the assessment, the Trustee determined that
the Trust maintained effective internal control over financial
reporting as of December 31, 2006, based on those criteria.
Weaver and Tidwell, L.L.P., the independent registered public
accounting firm that audited the financial statements of the
Trust included in this Annual Report on
Form 10-K,
has issued an attestation report on the Trustee’s
assessment of the effectiveness of the Trust’s internal
control over financial reporting as of December 31, 2006.
The report, which expresses unqualified opinions on the
Trustee’s assessment and on the effectiveness of the
Trust’s internal control over financial reporting as of
December 31, 2006, is included in this Item under the
heading “Report of Independent Registered Public Accounting
Firm on Internal Control Over Financial Reporting”.
Report of
Independent Registered Public
Accounting Firm on Internal Control Over Financial
Reporting
We have audited the assessment of Compass Bank (the
“Trustee”), included in the accompanying
Trustee’s Report on Internal Control Over Financial
Reporting, that San Juan Basin Royalty Trust (the
“Trust”) maintained effective internal control over
financial reporting as of December 31, 2006, based on
criteria established in
Internal Control —
Integrated Framework
issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the “COSO
criteria”). The Trustee is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express an opinion
on the Trustee’s assessment and an opinion on the
effectiveness of the Trust’s internal control over
financial reporting 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 effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, evaluating the
Trustee’s assessment, testing and evaluating the design and
operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A trust’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
the Trust’s modified cash basis of accounting, which is a
comprehensive basis of accounting other than U.S. generally
accepted accounting principles. A trust’s internal control
over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the trust;
(2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial
statements in accordance with its modified cash basis of
accounting, and that receipts and expenditures of the trust are
being made only in accordance with authorizations of the
trustee; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use,
or disposition of the trust’s assets that could have a
material effect on the financial statements.
16
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, the Trustee’s assessment that the Trust
maintained effective internal control over financial reporting
as of December 31, 2006, is fairly stated, in all material
respects, based on the COSO criteria. Also, in our opinion, the
Trust maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2006,
based on the COSO criteria.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
statements of assets, liabilities and trust corpus as of
December 31, 2006 and 2005 and the related statements of
distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2006 of the
Trust and our report dated February 28, 2007 expressed an
unqualified opinion thereon.
/s/ Weaver
and Tidwell, L.L.P.
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
February 28, 2007
|
|
|
|
ITEM 9A(T).
|
CONTROLS
AND PROCEDURES
|
Not applicable.
|
|
|
|
ITEM 9B.
|
OTHER
INFORMATION
|
All information required to be disclosed by the Trust in a
Current Report on
Form 8-K
during the fourth quarter of the year ended December 31,
2006, has previously been reported on a
Form 8-K.
PART III
|
|
|
|
ITEM 10.
|
DIRECTORS
AND EXECUTIVE OFFICERS OF THE REGISTRANT
|
The Trust has no directors, executive officers or employees; the
Trust is managed by a corporate trustee. Accordingly, the Trust
does not have an audit committee, audit committee financial
expert or a code of ethics applicable to executive officers. The
Trustee, however, has adopted a policy regarding standards of
conduct and conflicts of interest applicable to all directors,
officers and employees of the Trustee. The Trustee is a
corporate trustee which may be removed, with or without cause,
at a meeting of the Unit Holders, by the affirmative vote of the
holders of a majority of all the Units then outstanding.
Section 16(a)
Beneficial Ownership Reporting Compliance
The Trust has no directors or officers. Accordingly, only
holders of more than 10% of the Trust’s Units are required
to file with the SEC initial reports of ownership of Units and
reports of changes in such ownership. Based solely on a review
of these reports, the Trust believes that the applicable
reporting requirements of Section 16(a) of the Securities
Exchange Act of 1934 were complied with for all transactions
which occurred in 2006.
|
|
|
|
ITEM 11.
|
EXECUTIVE
COMPENSATION
|
The Trust has no directors, executive officers or employees.
Accordingly, the Trust does not have a compensation committee or
maintain any equity compensation plans, and there are no Units
reserved for issuance under any such plans.
17
During the past three years the Trustee received total
remuneration as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name of Individual
|
|
|
|
|
Capacities in
|
|
|
Cash
|
|
|
or Entity
|
|
Year
|
|
|
Which Served
|
|
|
Compensation(1)
|
|
|
|
|
Compass Bank(2)
|
|
|
2006
|
|
|
|
Trustee
|
|
|
$
|
249,924
|
|
|
TexasBank
|
|
|
2005
|
|
|
|
Trustee
|
|
|
$
|
310,461
|
|
|
TexasBank
|
|
|
2004
|
|
|
|
Trustee
|
|
|
$
|
259,472
|
|
|
|
|
|
|
(1)
|
|
Under the Indenture, the Trustee is entitled to an
administrative fee for its administrative services and the
preparation of quarterly and annual statements of: (i) 1/20
of 1% of the first $100 million of the annual gross revenue
of the Trust, and 1/30 of 1% of the annual gross revenue of the
Trust in excess of $100 million and (ii) the
Trustee’s standard hourly rates for time in excess of
300 hours annually. As of January 1, 2003, the
administrative fee due under items (i) and (ii) above
will not be less than $36,000 per year (as adjusted
annually to reflect the increase (if any) in the Producers Price
Index as published by the U.S. Department of Labor, Bureau
of Labor Statistics).
|
|
|
|
(2)
|
|
On March 24, 2006 Compass Bancshares Inc., the parent
company of Compass Bank, completed its acquisition of TexasBanc
Holding Co., the parent company of TexasBank, the prior trustee
of the Trust. On that same date, TexasBank merged with Compass
Bank, and as a result, Compass Bank succeeded TexasBank as
Trustee under the terms of the Indenture. On February 16,
2007, Compass Bancshares, Inc. announced the signing of a
definitive agreement to be acquired by Banco Bilbao Vizcaya
Argentaria, S.A (“BBVA”). Under the terms of that
agreement, Compass Bancshares, Inc. would become a wholly-owned
subsidiary of BBVA. The transaction is expected to close in the
second half of 2007 and is subject to the approval of
shareholders of BBVA and Compass Bancshares, Inc. as well as to
regulatory approval and customary closing conditions.
|
|
|
|
|
ITEM 12.
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED SECURITY HOLDER MATTERS
|
The Trust has no directors, executive officers or employees.
Accordingly, the Trust does not maintain any equity compensation
plans and there are no Units reserved for issuance under any
such plans.
(a)
Security Ownership of Certain Beneficial
Owners.
As of February 26, 2007, no person
was known to beneficially own more than 5% of the outstanding
Units of the Trust.
(b)
Security Ownership of Trustee.
As of
February 26, 2007, Compass Bank beneficially owned
14,450 Units, or less than one percent of the Units.
Compass Bank has sole voting power over all of these Units and
has the sole power to dispose of 1,500 of these Units.
|
|
|
|
ITEM 13.
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS
|
The Trust has no directors or executive officers and is not
empowered to carry on any business activity. Accordingly, there
are no relationships or related transactions to which the Trust
was a party that are required to be disclosed. See Item 11
for the remuneration received by the Trustee during the year
ended December 31, 2006 and Item 12 for information
concerning Units owned by the Trustee.
|
|
|
|
ITEM 14.
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
The following table presents fees for professional audit
services rendered by Weaver and Tidwell, L.L.P., the
Trust’s principal accountants, for the audit of the
Trust’s annual financial statements for the fiscal years
ended
18
December 31, 2006 and 2005 and fees billed for other
services rendered to the Trust by Weaver and Tidwell, L.L.P.
during those periods.
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
Audit Fees
|
|
$
|
71,125
|
|
|
$
|
76,065
|
|
|
Audit-Related Fees
|
|
|
-0-
|
|
|
|
-0-
|
|
|
Tax Fees
|
|
|
5,475
|
|
|
|
8,085
|
|
|
All Other Fees
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
76,600
|
|
|
$
|
84,150
|
|
|
|
|
|
|
|
|
|
|
|
Audit Fees consist of fees billed for professional services
rendered for the audit of the Trust’s annual financial
statements and internal control over financial reporting, review
of the interim financial statements included in the Trust’s
quarterly reports and services that are normally provided by
Weaver and Tidwell, L.L.P. in connection with statutory and
regulatory filings or engagements.
Audit-Related Fees consist of fees billed for assurance and
related services that are reasonably related to the performance
of the audit or review of the Trust’s financial statements.
This category includes fees related to audit and attest services
not required by statute or regulations and consultations
concerning financial accounting and reporting standards.
Tax Fees consist of fees for professional services billed for
tax compliance, tax advice and tax planning. These services
include assistance regarding federal and state tax compliance,
return preparation, preparation of the
B-schedules
and tax booklet.
All Other Fees consist of fees billed for products and services
other than the services reported above.
The Trust has no directors or executive officers. Accordingly,
the Trust does not have an audit committee and there are no
audit committee pre-approval policies or procedures relating to
services provided by the Trust’s independent accountants.
Pursuant to the terms of the Indenture, the Trustee engages and
approves all services rendered by the Trust’s independent
accountants.
PART IV
|
|
|
|
ITEM 15.
|
EXHIBITS AND
FINANCIAL STATEMENT SCHEDULES
|
The following documents are filed as a part of this Annual
Report on
Form 10-K:
Financial
Statements
Included in Part II of this Annual Report on
Form 10-K
by reference to the Trust’s Annual Report to Unit Holders
for the year ended December 31, 2006:
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements
19
Financial
Statement Schedules
Financial statement schedules are omitted because of the absence
of conditions under which they are required or because the
required information is given in the financial statements or
notes thereto.
Exhibits
|
|
|
|
|
|
Exhibit
|
|
|
|
Number
|
|
Description
|
|
|
|
|
4(a)
|
|
|
Amended and Restated Royalty Trust
Indenture, dated September 30, 2002 (the original Royalty
Trust Indenture, dated November 1, 1980 having been entered
into between Southland Royalty Company and The Fort Worth
National Bank, as Trustee), heretofore filed as
Exhibit 99.2 of the Trust’s Current Report on
Form 8-K
filed with the SEC on October 1, 2002, is incorporated
herein by reference.*
|
|
|
4(b)
|
|
|
Net Overriding Royalty Conveyance
from Southland Royalty Company to the Fort Worth National
Bank, as Trustee, dated November 3, 1980 (without
Schedules).**
|
|
|
4(c)
|
|
|
Assignment of Net Overriding
Interest (San Juan Basin Royalty Trust), dated
September 30, 2002, between Bank One, N.A. and TexasBank,
heretofore filed as Exhibit 4(c) to the Trust’s
Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended September 30,
2002, is incorporated herein by reference.*
|
|
|
10
|
|
|
Indemnification Agreement, dated
May 13, 2003, with effectiveness as of July 30, 2002,
by and between Lee Ann Anderson and San Juan Basin Royalty
Trust, heretofore filed as Exhibit 10(a) to the
Trust’s Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended March 31, 2003, is
incorporated herein by reference.
|
|
|
13
|
|
|
Registrant’s Annual Report to
Unit Holders for the fiscal year ended December 31, 2006.**
|
|
|
23
|
|
|
Consent of Cawley,
Gillespie & Associates, Inc., reservoir engineer.**
|
|
|
31
|
|
|
Certification required by
Rule 13a-14(a),
dated March 1, 2007, by Lee Ann Anderson, Vice President
and Senior Trust Officer of Compass Bank, the Trustee of
the Trust.**
|
|
|
32
|
|
|
Certification required by
Rule 13a-14(b),
dated March 1, 2007, by Lee Ann Anderson, Vice President
and Senior Trust Officer of Compass Bank on behalf of
Compass Bank, the Trustee of the Trust.***
|
|
|
|
|
|
*
|
|
A copy of this Exhibit is available to any Unit Holder (free of
charge) upon written request to the Trustee, Compass Bank, 2525
Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
|
|
|
|
**
|
|
Filed herewith.
|
|
|
|
***
|
|
Furnished herewith.
|
20
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
SAN JUAN BASIN ROYALTY TRUST
|
|
|
|
|
|
By:
|
COMPASS
BANK, AS TRUSTEE OF THE
|
SAN JUAN BASIN ROYALTY TRUST
Lee Ann Anderson
Vice President and Senior Trust Officer
Date: March 1, 2007
(The Trust has no directors or executive officers)
21
EXHIBIT INDEX
|
|
|
|
|
|
Exhibit
|
|
|
|
Number
|
|
Description
|
|
|
|
|
4(a)
|
|
|
Amended and Restated Royalty Trust
Indenture, dated September 30, 2002 (the original Royalty
Trust Indenture, dated November 1, 1980 having been entered
into between Southland Royalty Company and The Fort Worth
National Bank, as Trustee), heretofore filed as
Exhibit 99.2 of the Trust’s Current Report on
Form 8-K
filed with the SEC on October 1, 2002, is incorporated
herein by reference.*
|
|
|
4(b)
|
|
|
Net Overriding Royalty Conveyance
from Southland Royalty Company to the Fort Worth National
Bank, as Trustee, dated November 3, 1980 (without
Schedules).**
|
|
|
4(c)
|
|
|
Assignment of Net Overriding
Interest (San Juan Basin Royalty Trust), dated
September 30, 2002, between Bank One, N.A. and TexasBank,
heretofore filed as Exhibit 4(c) to the Trust’s
Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended September 30,
2002, is incorporated herein by reference.*
|
|
|
10
|
|
|
Indemnification Agreement, dated
May 13, 2003, with effectiveness as of July 30, 2002,
by and between Lee Ann Anderson and San Juan Basin Royalty
Trust, heretofore filed as Exhibit 10(a) to the
Trust’s Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended March 31, 2003, is
incorporated herein by reference.
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13
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Registrant’s Annual Report to
Unit Holders for the fiscal year ended December 31, 2006.**
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23
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Consent of Cawley,
Gillespie & Associates, Inc., reservoir engineer.**
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31
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Certification required by
Rule 13a-14(a),
dated March 1, 2007, by Lee Ann Anderson, Vice President
and Senior Trust Officer of Compass Bank, the Trustee of
the Trust.**
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32
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Certification required by
Rule 13a-14(b),
dated March 1, 2007, by Lee Ann Anderson, Vice President
and Senior Trust Officer of Compass Bank, on behalf of
Compass Bank, the Trustee of the Trust.***
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*
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A copy of this Exhibit is available to any Unit Holder (free of
charge) upon written request to the Trustee, Compass Bank, 2525
Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
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**
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Filed herewith.
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***
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Furnished herewith.
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22
Exhibit 4(b)
NET OVERRIDING ROYALTY CONVEYANCE
(San Juan Basin Royalty Trust)
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THE STATE OF NEW MEXICO
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§
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§
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KNOW ALL MEN BY THESE PRESENTS:
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COUNTIES OF SAN JUAN,
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§
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RIO ARRIBA AND SANDOVAL
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§
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THAT, SOUTHLAND ROYALTY COMPANY, a Delaware corporation (“Assignor”), for and in consideration
of the sum of Ten Dollars ($10.00) and other good and valuable consideration to it paid by The Fort
Worth National Bank, a bank organized under the laws of the United States, acting not in its
individual corporate capacity but solely as trustee under that certain San Juan Basin Royalty Trust
Indenture dated as of November 1, 1980 (“Assignee”), the receipt and sufficiency of which are
hereby acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set over and
delivered, and by these presents does hereby bargain, sell, grant, convey, transfer, assign, set
over and deliver unto Assignee a net overriding royalty interest (“the Royalty Interest”) in and to
the Minerals in and under, and if, as and when produced, saved and sold from, the Subject Lands
during the term of the Subject Interests equal to Seventy-Five percent (75%) of the Net Proceeds
attributable to the Subject Interests, as each of the above capitalized words are defined in
Article I and all as more fully provided herein.
TO HAVE AND TO HOLD the Royalty Interest, together with all and singular the rights and
appurtenances thereto in anywise belonging, unto Assignee, its successors and assigns, subject,
however, to the terms and provisions of this Conveyance; and Assignor does by these presents bind
and obligate itself, its successors and assigns, to WARRANT and FOREVER defend all and singular the
Royalty Interest unto the said Assignee, its successors and assigns, against every person
whomsoever lawfully claiming or to claim the same or any part thereof by, through or under
Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
As herein used the following words, terms or phrases have the following meanings:
SECTION 1.01. “Affiliate” means, as to the party specified, any Person controlling, controlled
by or under common control with such party, with the concept of control in such context meaning the
possession, directly or indirectly, of the power to direct or cause the direction of the management
and policies of another, whether through the ownership of voting securities, by contract or
otherwise.
SECTION 1.02. “Assignor” means the Assignor named herein while it owns all or any part of or
interest in the Subject Interests and any other Person or Persons who acquire all or any part of or
interest in the Subject Interests.
SECTION 1.03. “Assignee” means the Assignee named herein while it owns all or any part of or
interest in the Royalty Interest and any other Person or Persons who acquire legal title to all or
any part of or interest in the Royalty Interest.
SECTION 1.04. “Conveyance” means this Net Overriding Royalty Conveyance.
SECTION 1.05. “Effective Date” means 7:00 o’clock A.M., local time in effect at the location
of each Subject Interest, on November 1, 1980.
SECTION 1.06. “Excess Production Costs” at any point in time means an amount equal to the
excess of Production Costs over Gross Proceeds for the period ending with such point and beginning
with the end of the most recent month in which there were Net Proceeds.
SECTION 1.07. “Gross Proceeds” means the amounts received from and after the Effective Date by
Assignor from the Sale of Subject Minerals sold after the Effective Date, in the aggregate, subject
to the following:
(a) There shall be excluded from Gross Proceeds all general property (ad valorem),
production, severance, sales, gathering and windfall profits taxes and other taxes (whether
state, federal or otherwise) assessed or levied on or in connection with the Subject
Interests, the Royalty Interest or the production therefrom, or against Assignor as owner of
the Subject Interests or Assignee as owner of the Royalty Interest, and which taxes are
deducted or excluded from proceeds of Sale received by Assignor.
(b) There shall be excluded any amount for Subject Minerals attributable to nonconsent
operations conducted with respect to the Subject Interests (or any portion thereof) as to
which Assignor shall be a nonconsenting party and which is dedicated to the recoupment or
reimbursement of costs and expenses of the consenting party or parties by the terms of the
relevant operating agreement, unit agreement, contract for development or other instrument
providing for such nonconsent operations, provided Assignor’s election not to participate in
such operations is made in conformity with the provisions of Section 6.01 of this
Conveyance.
(c) There shall be excluded any amount which Assignor shall receive as any of the
following: consideration for transfer or sale of any of the Subject Interests (subject to
the Royalty Interest) or equipment or other personal property or fixtures on the Subject
Lands; delay rental; shut-in gas well royalty or payment; minimum royalty (to the extent not
attributable to actual production of the Subject Minerals); payments for gas not taken, when
such payments are made (but to the extent such payments are allocated to gas taken in the
future such payments shall be included without interest in Gross Proceeds when such gas is
taken); damages arising from any cause other than drainage or reservoir injury; rental for
reservoir use; payments made to Assignor in connection with the drilling of any well on any
of the Subject Lands or lands in the vicinity (such exclusion including dry and bottom hole
payments, provided that if such well is drilled on the Subject Lands and Assignor incurs
Production Costs in connection therewith such payments shall reduce Production Costs) or in
connection with any adjustment of any well and leasehold equipment upon unitization of any
of the Subject Interests; provided
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there shall be included in Gross Proceeds advance or prepaid payments for future
production received by Assignor to the extent not subject to repayment in the event of
insufficient subsequent production (and to the extent so subject to repayment shall be
included without interest in Gross Proceeds when the Minerals on which such payment was so
advanced or prepaid are actually produced) and payments made to Assignor in connection with
the deferring of drilling of any well on any of the Subject Lands (including payments from
an operator in the vicinity for refraining from drilling an offset well).
(d) There shall be excluded any amount for Subject Minerals lost in the production or
marketing thereof or used by Assignor in conformity with ordinary or prudent practices for
drilling, production and plant operations (including gas injection, secondary recovery,
pressure maintenance, repressuring, cycling operations, plant fuel or shrinkage) conducted
for the purpose of drilling for, producing or processing Subject Minerals or for operations
on any unit or plant to which the Subject Interests are committed, but only so long as such
Subject Minerals are so used.
(e) Amounts received as a loan by Assignor from a purchaser of Subject Minerals,
whether with or without interest, shall not be considered to be derived from the sale of
Subject Minerals, provided that the related Sales Contract meets the requirements of Section
4.01 hereof.
(f) So long as and to the extent that the same may be required by applicable laws and
regulations, in the case of any Subject Interest derived under a lease from the United
States of America from which the average production of oil per well per day averaged on the
monthly basis is 15 barrels or less, the obligation to pay and the right of Assignee to
receive the proceeds of oil produced from such lease shall be suspended until said average
production of oil per well per day exceeds said minimum amount, and such suspension shall
apply separately to any zone or portion of such lease segregated for computing government
royalties.
(g) If a controversy or possible controversy exists (whether by reason of any statute,
order, decree, rule, regulation, contract or otherwise) between Assignor and any purchaser
as to the correct sales price of any Subject Mineral or, for any other reason, as to
Assignor’s right to receive or collect the proceeds of sale of any Subject Minerals, then
(i) amounts withheld by the purchaser or deposited by it with an escrow agent
shall not be considered to be received by Assignor until actually collected by
Assignor, but the amounts received by Assignor shall include any interest, penalty
or other amount paid to Assignor in respect thereof;
(ii) amounts received by Assignor and promptly deposited by it with an escrow
agent shall not be considered to have been received by Assignor, but all amounts
thereafter paid to Assignor by such escrow agent shall be considered to be amounts
received from the sale of Subject Minerals; and
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(iii) amounts received by Assignor and not deposited with an escrow agent shall
be considered to be received for purposes of this Section 1.07.
(h) Assignor shall have the right to contest the amount of the windfall profits tax
alleged to be due on proceeds included in Gross Proceeds and to seek refunds thereof. In
the event any amounts are required to be paid because of any deficiency in prior payment of
windfall profits tax for periods after the Effective Date, the amounts so paid shall be
included in Production Costs as paid.
SECTION 1.08. “Minerals” means oil, gas and all other minerals produced in association with
oil or gas, but excluding all other minerals, whether similar or dissimilar.
SECTION 1.09. “Monthly Record Date” for each month means the close of business on the last day
of such month which is not a Saturday, Sunday or other day on which national banking institutions
in the City of Fort Worth, Texas, are closed as authorized or required by law, unless Assignee
determines that a later date is required to comply with applicable law or the rules of an exchange
pursuant to the terms of the San Juan Basin Royalty Trust Indenture referred to above.
SECTION 1.10. “Net Proceeds” for any period means the excess of Gross Proceeds realized during
such period over the sum of (a) Production Costs incurred during such period and (b) Excess
Production Costs as of the end of the immediately preceding period.
SECTION 1.11. “Non-Affiliate” means, as to the party specified, any Person who is not an
Affiliate of such party.
SECTION 1.12. “Person” means any individual, corporation, partnership, trust, estate or other
entity, organization or association.
SECTION 1.13. “Prime Interest Rate” means the interest rate per annum charged by Morgan
Guaranty Bank of New York on ninety day loans to its most substantial and responsible commercial
borrowers.
SECTION 1.14. “Processing Costs” means the costs to Assignor of manufacturing, refining or
processing (all herein referred to as “processing”) gas and casinghead gas included in the Subject
Minerals before the Sale thereof, which costs for purposes hereof shall consist of
(a) the sum of (i) any such processing charges paid to Non-Affiliates and (ii) the
expenses (including depreciation but otherwise not including capital costs) incurred by
Assignor or its Affiliate in processing such Subject Minerals plus an amount equal to a
return of 15% on the depreciated book value of the fixed assets used in such processing (for
which purpose of computing depreciation and the return on depreciated book value the value
of fixed assets owned by Assignor will be their book value as of the date first used in
processing Subject Minerals), or
(b) if greater, the amount allowed as processing charges by any Federal or State agency
having jurisdiction over the sale of such Subject Minerals.
-4-
If Assignor or an Affiliate receives a share of the production of others or of plant products
therefrom (or proceeds of sale thereof) for processing such production of others, such share shall
not be included in Subject Minerals (or Gross Proceeds). If Assignor or an Affiliate does not bear
any processing costs but the owners or operators of a plant receive a share of the Subject Minerals
(or proceeds of sale thereof) for processing them, such share (or proceeds) shall be excluded from
the Subject Minerals (and Gross Proceeds).
SECTION 1.15. “Production Costs” means, on an accrual accounting method and accruing with
respect to the following from and after the Effective Date, and whether capital or non-capital in
nature,
(a) the sum of
(i) all amounts borne by Assignor as any of the following: royalty; overriding
royalty or other presently existing burden against production or the proceeds of
sale of production attributable to the Subject Interests; delay rental; shut-in gas
well royalty or payment; minimum royalty; payments to lessors or others in the area
in connection with the drilling or deferring of drilling of any well on any of the
Subject Lands or lands in the vicinity (including dry and bottom hole payments and
payments made to others for refraining from drilling an offset well) or in
connection with any adjustment of any well and leasehold equipment upon unitization
of any of the Subject Interests; and rent and other consideration paid for use of or
damage to the surface;
(ii) all general property (ad valorem), production, severance, sales, gathering
and windfall profits taxes and other taxes (whether state, federal or otherwise),
except income taxes, assessed or levied on or in connection with the Subject
Interests, the Royalty Interest or the production therefrom or equipment on the
Subject Lands, or against Assignor as owner of the Subject Interests or Assignee as
owner of the Royalty Interest, and which taxes are paid by Assignor, and any income
tax on the Royalty Interest paid by Assignor;
(iii) the aggregate costs incurred by Assignor under any joint operating
agreement applicable to the Subject Interests to which Assignor and one or more
Non-Affiliates are parties;
(iv) The aggregate costs incurred by Assignor under Schedule B attached hereto
with respect to any Subject Interest not subject to a joint operating agreement
between Assignor and a Non-Affiliate.
(v) all other costs, expenses and liabilities of investigating, exploring,
prospecting, drilling and mining for, operating and producing Subject Minerals and
sale and marketing thereof, including without implied limitation: costs of
equipping, plugging back, reworking, completing, recompleting and plugging and
abandoning of any well on the Subject Lands and of making the Subject Minerals ready
or available for market; the cost of construction of gathering lines, tanks,
transmission lines, meters and other production and delivery facilities and of
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transporting, compressing, dehydrating, separating, treating, storing and
marketing the Subject Minerals; the cost of secondary recovery, pressure
maintenance, repressuring, cycling and other operations conducted for the purpose of
enhancing production; and the cost of litigation concerning title to or operation of
the Subject Interests and any other acts or omissions of Assignor consistent
herewith or brought by Assignor to protect the Subject Interests;
(vi) Processing Costs;
(vii) interest accrued during any month in which there were Excess Production
Costs computed at the Prime Interest Rate in effect at the end of such period on the
amount of Excess Production costs at the end of such period;
(viii) the costs of the audits furnished pursuant to Section 2.06 hereof;
(ix) any amounts paid by Assignor, whether as refund, interest or penalty, to a
purchaser because the amount initially received by Assignor as sales price was more
or allegedly more than permitted by the terms of any applicable contract, statute,
regulation, order, decree or other obligation;
(x) any other amounts paid by Assignor with respect to the Subject Interests or
operation thereof or sale of production therefrom, whether as refund, fine, interest
or penalty, pursuant to litigation or settlement of threatened litigation or order
of governmental agency, provided that Assignor has not breached Section 6.01 hereof;
and
(xi) all consideration hereafter paid and costs and expenses hereafter incurred
by Assignor for any renewals or extensions of leases or other rights hereafter
acquired which are included in the definition herein of Subject Interests;
(b) but excluding
(i) costs which would otherwise be treated as Production Costs but which shall
not be so treated for purposes hereof (until the following amounts have been fully
credited against such costs) equal to amounts reimbursed or credited to Assignor by
insurance from damage to property, by sales of property or transfers of property off
the leases included in the Subject Interests or by proceeds from unitization or
other disposition of property;
(ii) the costs incurred in drilling a well to a lower depth than that to which
the Subject Interests are by the definition below limited unless the well is
ultimately completed as a producer within the depths included in the Subject
Interests and is not completed as a producer below such depths and, even in such
event, the cost of drilling below such depths (as allocated by Assignor) shall be
excluded; and
(iii) any amounts which would otherwise be Production Costs but which are
attributable to periods before the Effective Date.
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SECTION 1.16. “Sale” includes exchanges and other dispositions for value.
SECTION 1.17. “Sales Contracts” means all contracts and agreements for the offer or sale of,
or commitment to offer or sell, or right of first refusal to purchase, Subject Minerals.
SECTION 1.18. “Subject Interests” means each kind and character of right, title, claim or
interest which Assignor has on the Effective Date in the oil, gas or mineral leases, mineral
interests, royalty interests and overriding royalty interests and the unitization and pooling
agreements and the units created thereby which are described in Schedule A, and all the right,
title, claim or interest which Assignor has on the Effective Date in and to the Subject Lands,
whether such right, title, claim or interest be under and by virtue of a lease, a mineral deed or
reservation, a royalty deed or reservation, an overriding royalty assignment or reservation, a
unitization or pooling agreement, a unitization or pooling order, an operating agreement, a
division order, a transfer order or any other type of contract, conveyance or instrument or under
any other type of claim or title, legal or equitable, recorded or unrecorded, even though
Assignor’s interests be incorrectly or incompletely described in, or a description thereof be
omitted from, Schedule A, all as the same shall be enlarged by the discharge of any payments out of
production or by the removal of any charges or encumbrances to which any of the same are subject
and any and all renewals and extensions of any of the same, but subject to all burdens to which
Assignor’s such right, title, claim or interest is subject (while same remains so subject),
limited, however, as follows: (i) limited to the depths to which the definition below of “Subject
Lands” is limited, (ii) limited, as to duration, with respect to each Subject Interest which is a
mineral interest subject on the Effective Date to an oil and gas lease (or oil, gas and mineral
lease), whether or not owned in whole or in part by Assignor, or which is a royalty interest as to
which the underlying mineral estate is subject to such a lease, to the life of that lease or any
renewal or extension thereof (so that if a lease in force on the Effective Date should terminate in
whole or in part for any reason and not be renewed or extended then such Subject Interest, to the
extent same, or the underlying mineral estate in same, is no longer subject to such lease, shall no
longer be subject to this Conveyance and the rights, titles and interests therein hereby conveyed
shall revert to Assignor without necessity of written proof so evidencing) and (iii) limited, if
Assignor’s interest in any Subject Interest should terminate sooner than the reversion provided in
the foregoing (ii), to the period to which Assignor’s interest in such Subject Interest is limited.
There shall be excluded from the term “Subject Interests” any interest hereafter acquired by
Assignor in and to any of the Subject Lands, except any interest acquired pursuant to existing
agreements for no new consideration and renewals or extensions of leases. For purposes of this
Conveyance “renewals or extensions” of any lease shall be limited to renewals or extensions of an
existing lease obtained by the present owner thereof (or such owner’s successors in interest) while
such lease is in force or within six months after such lease terminates. Assignor shall be under
no duty to seek renewals or extensions of any lease.
SECTION 1.19. “Subject Lands” means the lands which are described in or which are subject to
the oil, gas and mineral leases, mineral deeds, royalty deeds, assignments and other instruments
described in Schedule A attached hereto from the surface of such lands to the base of the
“Basin-Dakota Gas Pool” as defined in Rule 25 of Order No. R-1670-C (as amended to the date hereof)
issued by the New Mexico Oil Conservation Commission, provided that if Assignor’s ownership rights
in any such lands are presently limited to depths shallower than such depth the “Subject Lands”
shall likewise be subject to such limitation and provided further that
-7-
where the description in Schedule A excepts land or refers to an instrument insofar only as it
covers certain land, no interest in such excepted land or in land other that to which such
reference is limited shall be included in the terms “Subject Lands” or “Subject Interests”.
SECTION 1.20. “Subject Minerals” means all Minerals in and under, and which may be produced,
saved and sold from, and which shall accrue and be attributable to, the Subject Interests,
including plant products attributable thereto from processing gas or casinghead gas included in the
Subject Minerals before sale thereof (but not including products derived from processing oil).
ARTICLE II
RECORDS AND REPORTS
SECTION 2.01.
Books and Records
. Assignor shall at all times maintain true and
correct books and records sufficient to determine the amounts payable to Assignee hereunder,
including, but not limited to, a Net Proceeds account to which Gross Proceeds and Production Costs
are credited and charged.
SECTION 2.02.
Inspections
. The books and records referred to in Section 2.01 shall be
open for inspection at the office of Assignor during normal business hours.
SECTION 2.03.
Quarterly Statements
. Within thirty (30) days next following the close
of each calendar quarter, Assignor shall deliver to Assignee a statement showing the computation of
Net Proceeds attributable to such quarter.
SECTION 2.04.
Assignee’s Exceptions to Quarterly Statements
. If Assignee shall take
exception to any item or items included in the quarterly statements rendered by Assignor, Assignee
shall notify Assignor in writing within 180 days after the receipt of the report and annual audit
furnished pursuant to Section 2.06 hereof, setting forth in such notice the specific charges
complained of and to which exception is taken or the specific credits which should have been made
and allowed; and, with respect to such complaints and exceptions as are justified, adjustment shall
be made. If Assignee shall fail to give Assignor notice of such complaints and exceptions prior to
the expiration of such 180 days period, then the statements for such calendar year as originally
rendered by Assignor shall be deemed to be correct as rendered.
SECTION 2.05.
Geological Data
. Upon request Assignor shall, subject to the
limitations of confidentiality undertakings with co-owners or other third parties, furnish to
Assignee access to all geological, well and production data which Assignor has on hand relating to
operations on the Subject Interests. Assignor shall also furnish to Assignee quarterly reports
showing the status of development, producing and other operations conducted by Assignor on the
Subject Interests. All information furnished to Assignee pursuant to this section is confidential
and for the sole benefit of Assignee and shall not be shown by Assignee to any other Person.
SECTION 2.06.
Annual Audits and Reports
. Within 90 days after the end of the calendar
year, Assignor shall deliver to Assignee a statement which has been audited by a
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nationally recognized firm of independent public accountants selected by Assignor, which shall
show the information provided for in Section 2.03 on an annual basis.
ARTICLE III
PAYMENT
SECTION 3.01.
Payment
. On or before the Monthly Record Date, Assignor shall pay to
Assignee as a royalty and overriding royalty hereunder an amount equal to Seventy-Five percent
(75%) of the Net Proceeds for the preceding month. On December 31, 1980, Assignor shall pay to
Assignee as an advance royalty the sum of $1,000,000. Such amount shall be subtracted from the
amounts otherwise payable under this Section with respect to future periods.
SECTION 3.02.
Interest on Past Due Payments
. Any amount not paid by Assignor to
Assignee when due shall bear, and Assignor will pay, interest at the rate of four percentage points
over the Prime Interest Rate, determined at the end of each month, from such due date until such
amount is paid, but not in excess of the maximum amount allowed by law.
SECTION 3.03.
Overpayment
. If at any time Assignor inadvertently pays Assignee more
than the amount due, Assignee shall not be obligated to return any such overpayment, but the amount
or amounts otherwise payable to Assignee for any subsequent period or periods shall be reduced by
such overpayment, plus an amount equal to interest computed at 120% of the weighted average Prime
Interest Rate in effect during the period of such overpayment.
ARTICLE IV
MARKETING OF SUBJECT MINERALS
SECTION 4.01.
Sales Contracts
. Assignor, to the extent it has the right to do so,
shall market or cause to be marketed the Subject Minerals. For such purpose, sales of Subject
Minerals may continue to be made pursuant to existing Sales Contracts. Assignor may amend such
existing Sales Contracts and may enter into one or more Sales Contracts in the future at the best
prices and on the best terms Assignor shall deem reasonably obtainable in the circumstances. Gross
Proceeds of Subject Minerals subject to Sales Contracts shall be determined on the basis of amounts
actually received by Assignor from sales under the Sales Contracts regardless of whether at the
time of production or sale market value should be different from proceeds of sale.
SECTION 4.02.
Performance of Sales Contracts
. Assignor will duly perform all
obligations binding on it under all Sales Contracts in accordance with the terms thereof and will
take all appropriate and reasonable measures to enforce the performance under each of the Sales
Contracts of the obligations of the purchaser thereunder. All Subject Minerals sold by Assignor,
whether pursuant to Sales Contracts or otherwise, shall be delivered by Assignor to the purchasers
thereof, into the pipelines to which the wells producing such Subject Minerals may be connected or
to such other point of purchase as is reasonably required in the marketing of such Subject
Minerals.
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SECTION 4.03.
Reliance by Third Party
. As to any party, the acts of Assignor shall be
binding on Assignee. It shall not be necessary for Assignee to join with Assignor in any division
or transfer order or any Sales Contract, and proceeds of sale of the Subject Minerals shall be paid
by the purchasers thereof (or others disbursing proceeds) directly to Assignor without necessity of
joinder by or consent of Assignee.
ARTICLE V
NON-LIABILITY OF ASSIGNEE
In no event shall Assignee be liable or responsible in any way for any Production Costs or
other costs or liabilities incurred by Assignor or others attributable to the Subject Interests or
to the Minerals produced therefrom.
ARTICLE VI
OPERATION OF SUBJECT INTERESTS
SECTION 6.01.
Prudent Operator Standard
. Assignor agrees, to the extent it has the
legal right to do so under the terms of any lease, operating agreement, unit operating agreement,
contract for development or similar instrument affecting or pertaining to the Subject Interests (or
any portion thereof), that it will conduct and carry on the maintenance and operation of the
Subject Interests with reasonable and prudent business judgment and in accordance with good oil an
gas field practices, and that it will drill such wells as a reasonably prudent operator would drill
from time to time in order to protect them from drainage. However, nothing contained in this
Section 6.01 shall be deemed to prevent or restrict Assignor from electing not to participate in
any operation which is to be conducted under the terms of any operating agreement, unit operating
agreement, contract for development or similar instrument affecting or pertaining to the Subject
Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations
thereon, if such election is made by Assignor in good faith. Notwithstanding anything elsewhere
herein to the contrary, Assignor shall never be liable to Assignee for the manner in which Assignor
performs its duties hereunder as long as Assignor has acted in good faith.
SECTION 6.02.
Abandonment of Properties
. Nothing herein contained shall obligate
Assignor to continue to operate any well or to operate or maintain in force or attempt to maintain
in force any of the Subject Interests when, in Assignor’s opinion, such well or Subject Interest
ceases to produce or is not capable of producing oil or gas in paying quantities. The expiration
of a Subject Interest in accordance with the terms and conditions applicable thereto shall not be
considered to be a voluntary surrender or abandonment thereof.
SECTION 6.03.
Insurance
. Although Assignor is permitted to carry policies of
insurance covering the property upon the Subject Interests and risks incident to the operation
thereof and to charge premiums therefor to the Net Proceeds account, Assignor shall not be required
to carry insurance on such property or covering any of such risks unless it elects so to do. In no
event shall Assignor be liable to Assignee on account of any losses sustained which are not covered
by insurance.
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ARTICLE VII
UNITIZATION
SECTION 7.01.
Pooled Subject Interests
. Certain of the Subject Interests may have
been heretofore pooled and unitized for the production of Minerals. Such Subject Interests are and
shall be subject to the terms and provisions of such pooling and unitization agreements, and the
Royalty Interest in each such Subject Interest shall apply to and affect only the production from
such units which accrues to such Subject Interest under and by virtue of the applicable pooling and
unitization agreements.
SECTION 7.02.
Right to Pool and Process
. Assignor shall have the right and power,
exercisable only during the period provided in Section 7.03 hereof, (a) to pool and unitize any of
the Subject Interests and to alter, change or amend or terminate any pooling or unitization
agreements heretofore or hereafter entered into, as to all or any part of the land covered hereby,
as to any one or more of the formations or horizons hereunder, and as to any one or more Minerals,
upon such terms and provisions as Assignor shall in its sole discretion determine, and (b) to
commit any of the Subject Interests (including the Royalty Interest attributable thereto) to an
agreement for processing same (pursuant to which, by way of example and not by way of limitation,
the plant owner or operator receives a portion of the Subject Minerals or plant products therefrom
or proceeds of the sale thereof as a fee for processing). If and whenever through the exercise of
such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of
any governmental body or official hereafter promulgated, any of the Subject Interests are pooled or
unitized in any manner, the Royalty Interest insofar as it affects such Subject Interest shall also
be pooled and unitized, and in any such event such Royalty Interest in such Subject Interest shall
apply to and affect only the production which accrues to such Subject Interest under and by virtue
of the pooling and unitization.
SECTION 7.03.
Applicable Period
. Assignor’s power and rights in Section 7.02 shall be
exercisable only during the period of the life of the last survivor of the descendants of the
signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one
(21) years after the death of such last survivor, or the term of this Conveyance, whichever period
shall first expire.
ARTICLE VIII
GOVERNMENT REGULATION
All obligations of Assignor hereunder shall be subject to all applicable provisions of the
Emergency Petroleum Allocation Act of 1973, the Department of Energy Organization Act, the Natural
Gas Act, the Natural Gas Policy Act of 1978 and each other statute purporting to provide regulation
of the sale of Minerals or establishing maximum prices at which the same may be sold and all
applicable laws, orders, rules and regulations thereunder of the Federal Energy Regulatory
Commission, the Department of Energy and each other legislative or governmental body, agency, board
or commission having jurisdiction. Rates permitted under the Natural Gas Act, the Natural Gas
Policy Act of 1978, the Emergency Petroleum Allocation Act of 1973 and each such other statute and
the rules and regulations thereunder to be paid for the Subject
-11-
Minerals shall be controlling if lower than prices established in Sales Contracts. Assignor
shall be entitled to use its reasonable discretion in making filings, for itself and on behalf of
Assignee, with the Federal Energy Regulatory Commission, the Department of Energy or any other
governmental body, agency, board or commission having jurisdiction, affecting the price or prices
at which Subject Minerals may be sold, and with purchasers of production, operators or others with
respect to the windfall profits tax.
ARTICLE IX
ASSIGNMENTS
SECTION 9.01.
Assignment by Assignor
. Assignor shall have the right to assign, sell,
transfer, convey, mortgage or pledge the Subject Interests, or any part thereof, subject to the
Royalty Interest and the terms and provisions of this Conveyance. From and after the effective
date of any such assignment, sale, transfer or conveyance by Assignor, the assignee thereunder
shall succeed to all the requirements upon and responsibilities of Assignor hereunder, as to the
interests so acquired by such assignee, and, from and after the said effective date, Assignor shall
be relieved of such requirements and responsibilities, excepting only those accrued or due for
performance prior to such effective date.
SECTION 9.02.
Partial Assignment
. If Assignor assigns its interest under the Subject
Interests as to some of such Subject Interests or as to some part thereof, then, effective as of
the date of such assignment, in determining the Royalty Interest payable with respect to production
from such assigned Subject Interests or parts thereof, the Gross Proceeds, Production Costs and Net
Proceeds attributable to such assigned interests will be computed and determined by the assignee of
such assigned interests in the aggregate as to the assigned interests owned by such assignee, but
separate from and not aggregated with the computation and determination made by Assignor as to
unassigned interests.
SECTION 9.03.
Assignment by Assignee
. Assignee has the right to assign the Royalty
Interest in whole or in part, but (with respect to the assignee named herein) only as authorized by
the San Juan Basin Royalty Trust Indenture referred to above. However, no such assignment will
affect the method of computing Net Proceeds, and if more than one Person becomes entitled to
participate in the Royalty Interest, Assignor may withhold from such other Person payments to which
such Person would otherwise be entitled hereunder and the furnishing of any data or information
which Assignor is required by the terms hereof to furnish Assignee until Assignor is furnished a
recordable instrument executed by or binding upon all Persons interested in the Royalty Interest
designating one Person who is to receive such payments, data and information. In making
conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder),
Assignee need not vest in its grantee or assignee all of the rights of Assignee hereunder with
respect to the interest in the Subject Interests so conveyed or assigned.
SECTION 9.04.
Change in Ownership
. No change of ownership or right to receive payment
of the Royalty Interest, or of any part thereof, however accomplished, shall be binding upon
Assignor until notice thereof shall have been furnished by the Person claiming the benefit thereof,
and then only with respect to payments thereafter made. Notice of Sale or assignment shall consist
of a certified copy of the recorded instrument accomplishing the same; notice of
-12-
change of ownership or right to receive payment accomplished in any other manner (for example
by reason of incapacity, death or dissolution) shall consist of certified copies of recorded
documents and complete proceedings legally binding and conclusive of the rights of all parties.
Until such notice shall have been furnished Assignor as above provided, the payment or tender of
all sums payable on the Royalty Interest may be made in the manner provided herein precisely as if
no such change in interest or ownership or right to receive payment had occurred. The kind of
notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall
be binding on Assignor.
SECTION 9.05.
Rights of Mortgagee or Trustee
. If Assignee shall at any time execute a
mortgage or deed of trust covering all or part of the Royalty Interest, the mortgagee(s) or
trustee(s) therein named or the holder of any obligation secured thereby shall be entitled, to the
extent such mortgage or deed of trust so provides, to exercise all the rights, remedies, powers and
privileges conferred upon Assignee by the terms of this Conveyance and to give or withhold all
consents required to be obtained hereunder by Assignee, but the provisions of this Section 9.05
shall in no way be deemed or construed to impose upon Assignor any obligation or liability
undertaken by Assignee under such mortgage or deed of trust or under the obligation secured
thereby.
ARTICLE X
MISCELLANEOUS
SECTION 10.01.
Proportionate Reduction
. In the event of failure or deficiency in
title to any of the Subject Interests, the portion of the production from such Subject Interest out
of which the Royalty Interest attributable to such Subject Interest shall be payable shall be
reduced in the same proportion that such Subject Interest is reduced.
SECTION 10.02.
Term
. Subject to the limitations stated in Section 1.18 hereof, this
Conveyance shall remain in force so long as any of the Subject Interests are in effect.
SECTION 10.03.
Further Assurances
. Should any additional instruments of assignment
and conveyance be required to describe more specifically any interests subject hereto, Assignor
agrees to execute and deliver the same. Also, if any other or additional instruments are required
in connection with the transfer of State, Federal or Indian lease interests in order to comply with
applicable laws, regulations or agreements, Assignor will execute and deliver the same.
SECTION 10.04.
Notices
. All notices, statements, payments and communications between
the parties hereto shall be deemed to have been sufficiently given and delivered if enclosed in a
post paid wrapper and deposited in the United States Mails directed, or if personally delivered, to
the party to whom the same is directed or to be furnished or made at the respective addresses, as
follows:
-13-
Southland Royalty Company
1000 Fort Worth Club Tower
Fort Worth, Texas 76102
Attention: Treasurer
The Fort Worth National Bank
Post Office Box 2050
Fort Worth, Texas 76101
Attention: Trust Department
Either party or the successors or assignees of the interest or rights or obligations of either
party hereunder may change its address or designate a new or different address or addresses for the
purposes hereof by a similar notice given or directed to all parties interested hereunder at the
time.
SECTION 10.05.
Binding Effect
. This Conveyance shall bind and inure to the benefit of
the successors and assigns of Assignor and Assignee.
SECTION 10.06.
Governing Law
. The validity, effect and construction of this
Conveyance shall be governed by the laws of the State of New Mexico.
SECTION 10.07.
Headings
. Article and Section headings used in this Conveyance are for
convenience only and shall not affect the construction of this Conveyance.
SECTION 10.08.
Substitution of Warranty
. This instrument is made with full
substitution and subrogation of Assignee in and to all covenants of warranty by others heretofore
given or made with respect to the Subject Interests or any part thereof or interest therein.
SECTION 10.09.
Counterpart Execution
. This Conveyance may be executed in multiple
counterparts, each of which shall be an original. Certain counterparts may have descriptions
relating to different recording jurisdictions omitted from Schedule A. A counterpart with all such
descriptions is being filed for record in San Juan County, New Mexico.
-14-
IN WITNESS WHEREOF, each of the parties hereto has caused this agreement to be executed in its
name and behalf and its corporate seal to be affixed hereto and attested by its proper signatory
officers thereunto duly authorized, as of November 1, 1980.
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ATTEST:
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SOUTHLAND ROYALTY COMPANY
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/s/ Lucy H. Lowry
Lucy H. Lowry, Secretary
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By
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: /s/ Alton C. Goodrich
Alton
C. Goodrich
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Executive Vice President
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ATTEST:
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The Fort Worth National Bank
acting not in its individual capacity
but solely as the Trustee of the
San Juan Basin Royalty Trust
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/s/ Palmer S. Haffner, Jr.
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By:
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/s/ Bruce Petty
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Bruce
Petty
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Trust Officer
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Executive Vice President and
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Trust Officer
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-15-
THE STATE OF TEXAS §
COUNTY OF TARRANT §
The foregoing instrument was acknowledged before me this third day of November, 1980 by ALTON
C. GOODRICH, Executive Vice President of Southland Royalty Company, a corporation, on behalf of
said corporation.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this the third day of November, 1980.
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/s/ Diana Marsh
Notary
Public in and for Tarrant
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County,Texas
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My Commission Expires:
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THE STATE OF TEXAS §
COUNTY OF TARRANT §
The foregoing instrument was acknowledged before me this third day of November, 1980 by BRUCE
PETTY, Executive Vice President and Trust Officer of The Forth Worth National Bank, a banking
association organized under the laws of the United States, on behalf of said corporation.
GIVEN UNDER MY HAND AND SEAL OF OFFICE, this the third day of November, 1980.
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/s/ Diana Marsh
Notary
Public in and for Tarrant
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County, Texas
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My Commission Expires:
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-16-
Exhibit 13
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San Juan Basin Royalty Trust
2006 ANNUAL REPORT
& and Form 10 — K &
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The Trust
THE PRINCIPAL ASSET of the San Juan Basin Royalty Trust (the “Trust”) consists of a 75% net
overriding royalty interest (the “Royalty”) carved out of certain oil and gas leasehold and
royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of
northwestern New Mexico.
Units
of Beneficial interest
The units of beneficial interest of the Trust (the “Units”) are traded on the New York
Stock Exchange under the symbol “SJT.” At February 26, 2007, the closing price of a Unit was
$31.98. From January 1, 2005, to December 31, 2006, the quarterly high and low sales prices and
the aggregate amount of monthly distributions per Unit paid each quarter were as follows:
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DISTRIBUTIONS
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HIGH
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LOW
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PAID
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2006
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First Quarter
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$
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45.9900
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$
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36.0000
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$
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1.083276
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Second Quarter
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43.7500
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33.0000
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.599299
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Third Quarter
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41.2500
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32.8200
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.666989
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Fourth Quarter
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39.0000
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32.6200
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.565491
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TOTAL FOR 2006
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$
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2.915055
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2005
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First Quarter
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$
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37.4000
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$
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27.7000
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$
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.831092
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Second Quarter
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44.2000
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34.1000
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.740612
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Third Quarter
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51.4300
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39.0000
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.692829
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Fourth Quarter
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49.2500
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38.3000
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.987214
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TOTAL FOR
2005
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$
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3.251747
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At February 16, 2007, there were 46,608,796 Units outstanding held by 1,709 Unit holders of record.
The following table presents information relating to the distribution of record ownership of Units:
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NUMBER OF
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type of unit holders
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UNIT HOLDERS
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UNITS HELD
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Individuals, Joint Holders and Minors
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1,504
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1,888,965
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Fiduciaries
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162
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495,464
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Government Bodies
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1
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30
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Clubs, Associations or Societies
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7
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13,120
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Depositary (for all beneficial holders)
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1
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43,864,558
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Corporations
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34
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346,659
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TOTAL
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1,709
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46,608,796
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N
o
2
To Unit Holders
WE
ARE PLEASED TO PRESENT THE 2006 ANNUAL REPORT
of the San Juan Basin Royalty Trust.
The report includes a copy of the Trust’s Annual Report on Form
10-K filed with the Securities and
Exchange Commission (the “Commission”) for the year ended December 31, 2006, without exhibits. The
Form 10-K contains important information concerning the Underlying Properties, as defined below,
including the oil and gas reserves attributable to the 75% net overriding royalty interest owned by
the Trust. Production figures provided in this letter and in the Trustee’s Discussion and Analysis
are based on information provided by Burlington Resources Oil & Gas Company LP (“BROG”), the
current owner of the Underlying Properties and the successor, through a series of assignments and
mergers, to Southland Royalty Company (“Southland”). On March 31, 2006, a subsidiary of
ConocoPhillips completed its acquisition of Burlington Resources, Inc., BROG’s parent. As a result,
ConocoPhillips became the parent of Burlington Resources, Inc., which in turn, is the parent of
BROG. The Trust was established in November 1980 by Southland. Pursuant to the Indenture that
governs the operations of the Trust, Southland conveyed to the Trust a 75% net overriding royalty
interest (equivalent to a net profits interest) (the “Royalty”), carved out of Southland Royalty’s
oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties in the San
Juan Basin of northwestern New Mexico.
The Royalty constitutes the principal asset of the Trust. Under the Indenture governing the Trust,
the function of Compass Bank, as Trustee, is to collect the net proceeds attributable to the
Royalty (“Royalty Income”), to pay all expenses and charges of the Trust, and then distribute the
remaining available income to the Unit holders. Income distributed to Unit holders in 2006 was
$135,867,325 or $2.915055 per Unit. Distributable Income (as hereinafter defined) for 2006
consisted of Royalty Income of $136,311,892 plus interest income of $1,207,360, less administrative
expenses of $1,651,927. Information about the Trust’s estimated proved reserves of gas, including
coal seam gas, and of oil as well as the present value of net revenues discounted at 10% can be
found in Item 2 of the accompanying Form 10-K. Independent petroleum engineers retained by the
Trust have estimated the Underlying Properties could remain productive well beyond the stated
production index of approximately 9.8 years and BROG has published information observing that the
San Juan Basin will remain a major gas resource for decades to come. In support of this
observation, BROG cites the November 2002 U.S. Geological Survey study doubling its estimates of
the gas reserves in the San Juan Basin to over 50 trillion cubic feet. Certain royalty income is
generally considered portfolio income under the passive loss rules of the Internal Revenue Code.
Therefore, Unit holders should generally not consider the taxable income from the Trust to be
passive income in determining net passive income or loss. Unit holders should consult their tax
advisors for further information. Unit holders of record will continue to receive an individualized
tax information letter for each of the quarters ending March 31, June 30 and September 30, 2007,
and for the year ending December 31, 2007. Unit holders owning Units in nominee name may obtain
monthly tax information from the Trust’s Web site or from the Trustee upon request. For the
reader’s convenience, a glossary of definitions used in this report can be found on the inside back
cover. Please visit our Web site at www.sjbrt.com to access news releases, reports, Commission
filings and tax information.
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Compass Bank, Trustee
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By:
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Lee
Ann Anderson
Vice President and Senior Trust Officer
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N
o
3
Description of the Properties
The
principal asset
of the Trust is a 75% net overriding royalty interest (the
“Royalty”) carved out of certain working, royalty and other leasehold interests (the “Underlying
Properties”) owned by BROG in oil and gas properties located in the San Juan Basin, and more
particularly in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. The
Underlying Properties consist of working interests, royalty interests, overriding royalty interests
and other contractual rights in 151,900 gross (119,000 net) producing acres and 4,616 gross (1,286
net) producing wells, including dual completions.
The Underlying Properties have historically produced gas primarily from conventional wells drilled
to three major formations: the Pictured Cliffs, the Mesaverde and the Dakota, ranging in depth from
1,500 to 8,000 feet. The characteristics of these reservoirs result in the wells having very long
productive lives. A production index for oil and gas properties is derived by dividing remaining
reserves by current production. Based upon the reserve report prepared by the Trust’s independent
petroleum engineers as of December 31, 2006, the production index for the Underlying Properties is
estimated to be approximately 9.8 years. The production index is subject to change from
year-to-year based on reserve revisions and production levels and is not presented as an estimate
of the life expectancy of the Trust. Among the factors considered by engineers in estimating
remaining reserves of natural gas is the current sales price for gas. As the sales price increases,
the producer can justify expending higher lifting costs and therefore reasonably expect to recover
more of the known reserves. Accordingly, as gas prices rise, the production index increases and
vice versa.
In addition to gas from conventional wells, the Underlying Properties also produce gas from coal
seam wells completed to the Fruitland Coal formation. The process of removing coal seam gas is
often referred to as degasification or desorption. Millions of years ago, natural gas was generated
in the process of coal formation and absorbed into the coal. Water later filled the natural
fracture system. When the water is removed from the natural fracture system, reservoir pressure is
lowered and the gas desorbs from the coal. The desorbed gas then flows through the fracture system
and is produced at the well bore. The volume of formation water production typically declines with
time and the gas production may increase for a period of time before starting to decline. In order
to dispose of the formation water, surface facilities including pumping units are required, which
results in the cost of a completed well being as much as $550,000. The price of coal seam gas is
typically lower than the price of conventional gas. This is because the heating value of coal seam
gas is much lower than that of conventional gas due to (a) ever increasing percentages of carbon
dioxide in coal seam gas (carbon dioxide has no heating value), and (b) the absence of heavier
hydrocarbons such as ethanes, propanes, and butanes which are present in conventional gas.
Furthermore, the processing fees for coal seam gas are typically higher than the processing fees
for conventional gas due to the cost of extracting the carbon dioxide.
In February 2002, BROG informed the Trust that the
New Mexico Oil Conservation Division (the
“OCD”) had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan
Basin. In July 2003, the OCD approved 160-acre spacing in the Fruitland Coal formation.
Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.
The Federal Energy Regulatory Commission is primarily responsible for federal regulation of
natural gas. For a further discussion of gas pricing, gas purchasers, gas production and
regulatory matters affecting gas production see Item 2,
“Properties,” in the accompanying
Form 10-K.
Trustee’s
Discussion
and
Analysis
Gas
and Oil Production
Total gas and oil production from the Underlying Properties for the five years ended December
31, 2006, were as follows:
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2006
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2005
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2004
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2003
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2002
|
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Gas — Mcf
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40,900,570
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42,867,162
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44,015,816
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45,202,576
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46,206,297
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Mcf per Day
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112,056
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117,444
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120,262
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123,843
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126,593
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Oil — Bbls
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74,438
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69,558
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77,341
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74,727
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93,659
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Bbls per Day
|
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204
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191
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211
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205
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257
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N
o
5
Trustee’s
Discussion and Analysis
Gas
and Oil Production cont.
Royalty Income for a calendar year is based on the actual gas and oil production during the
period beginning with November of the preceding calendar year through October of the current
calendar year. Gas and oil sales attributable to the Royalty for the past five years are
summarized in the following table:
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2006
|
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2005
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2004
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2003
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2002
|
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Gas — Mcf
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22,475,405
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26,600,644
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25,324,435
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25,922,650
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19,584,056
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Average Price (per Mcf)
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$
|
6.55
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$
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6.27
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$
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4.68
|
|
|
$
|
3.93
|
|
|
$
|
2.32
|
|
|
Oil — Bbls
|
|
|
40,702
|
|
|
|
43,142
|
|
|
|
44,832
|
|
|
|
43,123
|
|
|
|
40,215
|
|
|
Average Price (per Bbl)
|
|
$
|
61.30
|
|
|
$
|
49.62
|
|
|
$
|
34.81
|
|
|
$
|
26.11
|
|
|
$
|
20.90
|
|
Sales volumes attributable to the Royalty are determined by dividing the net profits
received by the Trust and attributable to oil and gas, respectively, by the prices received for
sales volumes from the Underlying Properties, taking into consideration production taxes
attributable to the Underlying Properties. Since the oil and gas sales attributable to the Royalty
are based on an allocation formula dependent on such factors as price and cost, including capital
expenditures, the aggregate sales amounts from the Underlying Properties may not provide a
meaningful comparison to sales attributable to the Royalty.
The fluctuations in annual gas production that have occurred during these five years generally
resulted from changes in the demand for gas during that time, marketing conditions, and increased
capital spending to generate production from new and existing wells. Production from the
Underlying Properties is influenced by the line pressure of the gas gathering systems in the San
Juan Basin. As noted above, oil and gas sales attributable to the Royalty are based on an
allocation formula dependent on many factors, including oil and gas prices and capital
expenditures.
BROG previously entered into two contracts for the sale of all volumes of gas produced from the
Underlying Properties. These contracts provided for (i) the sale of such gas to Duke Energy and
Marketing L.L.C. and PNM Gas Services (“PNM”), respectively, (ii) the delivery of such gas at
various delivery points through March 31, 2005, and from year-to-year thereafter until terminated
by either party on 12 months’ notice, and (iii) the sale of such gas at prices which fluctuate in
accordance with published indices for gas sold in the San Juan Basin of New Mexico. Effective
January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by
ConocoPhillips Company (“ConocoPhillips”) pursuant to an Assignment and Novation Agreement. By
correspondence dated March 25, 2004, BROG notified ConocoPhillips of BROG’s election to terminate
such contract as of March 31, 2005. BROG then prepared a form of request for proposal and
circulated it to a number of potential purchasers, including ConocoPhillips, inviting them to bid
for the purchase of the gas currently sold under the contract expiring March 31, 2005. Effective as
of April 1, 2005, BROG entered into two new contracts for the sale of all volumes of gas produced
from the Underlying Properties and formerly sold to ConocoPhillips. These new contracts provide for
(i) the sale of such gas to ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc.
(“ChevronTexaco”), and Coral Energy Resources, L.P. (“Coral”), respectively, (ii) the delivery of
such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until
terminated by either party on 12 months’ notice, and (iii) the sale of such gas at prices which
fluctuate in accordance with the published indices for gas sold in the San Juan Basin of New
Mexico. With respect to BROG’s contract with PNM, BROG and PNM entered into a letter agreement
dated January 31, 2005, pursuant to which the parties waived the right to terminate the underlying
contract as of March 31, 2006, so that the term of that contract will continue until at least March
31, 2007, and from year-to-year thereafter until terminated by either party upon 12 months’ notice
to the other. Neither BROG nor any of ChevronTexaco, Coral nor PNM gave notice to terminate the
three contracts described above for the sale of all volumes of gas produced from the Underlying
Properties and, accordingly, the terms of those contracts have been extended through March 31,
2008.
Confidentiality agreements with purchasers of gas produced from the Underlying Properties prohibit
public disclosure of certain terms and conditions of gas sales contracts with those entities,
including specific pricing terms and gas receipt points. Such disclosure could compromise the
ability to compete effectively in the marketplace for the sale of gas produced from the Underlying
Properties.
N
o
6
Trustee’s
Discussion
and
Analysis
Royalty
Income
Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income
for the five years ended December 31, 2006, was determined as shown in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2002
|
|
|
|
|
Gross Proceeds
from the Underlying
Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
264,428,021
|
|
|
$
|
267,895,460
|
|
|
$
|
204,682,365
|
|
|
$
|
175,653,183
|
|
|
$
|
103,349,299
|
|
|
Oil
|
|
|
4,561,342
|
|
|
|
3,451,115
|
|
|
|
2,670,763
|
|
|
|
1,938,972
|
|
|
|
1,863,827
|
|
|
Other
|
|
|
1,384,848
|
1
|
|
|
2,405,486
|
2
|
|
|
3,314,808
|
3
|
|
|
(1,202,368
|
)
4
|
|
|
(5,110,589
|
)
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
270,374,211
|
|
|
$
|
273,752,061
|
|
|
$
|
210,667,936
|
|
|
$
|
176,389,787
|
|
|
$
|
100,102,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less
Production Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures
|
|
$
|
39,195,168
|
|
|
$
|
19,127,698
|
|
|
$
|
22,338,684
|
|
|
$
|
20,590,704
|
|
|
$
|
21,470,777
|
|
|
Severance Tax — Gas
|
|
|
25,652,907
|
|
|
|
26,717,315
|
|
|
|
19,766,231
|
|
|
|
17,281,986
|
|
|
|
9,752,508
|
|
|
Severance Tax — Oil
|
|
|
460,702
|
|
|
|
362,023
|
|
|
|
253,022
|
|
|
|
174,750
|
|
|
|
151,594
|
|
|
Other
|
|
|
42,968
|
|
|
|
273,766
|
|
|
|
42,763
|
|
|
|
41,850
|
|
|
|
18,037
|
|
|
Lease Operating
Expenses and Property Taxes
|
|
|
23,273,276
|
|
|
|
22,126,907
|
|
|
|
20,210,213
|
|
|
|
15,637,481
|
|
|
|
15,701,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
88,625,021
|
|
|
$
|
68,607,709
|
|
|
$
|
62,610,913
|
|
|
$
|
53,726,771
|
|
|
$
|
47,094,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess Production Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on Excess
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
(2,259,628
|
)
6
|
|
Production Costs
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
(10,545
|
)
6
|
|
Net Profits
|
|
$
|
181,749,190
|
|
|
$
|
205,144,352
|
|
|
$
|
148,057,023
|
|
|
$
|
122,663,016
|
|
|
$
|
50,737,708
|
|
|
Net Overriding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty
Interest
|
|
|
75
|
%
|
|
|
75
|
%
|
|
|
75
|
%
|
|
|
75
|
%
|
|
|
75
|
%
|
|
Royalty Income
|
|
$
|
136,311,892
|
|
|
$
|
153,858,264
|
|
|
$
|
111,042,767
|
|
|
$
|
91,997,262
|
|
|
$
|
38,053,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Represents funds allocated to the Trust as part of the ongoing negotiation of
joint interest audit exceptions, and a portion of the arbitration
award issued November 11, 2005 in favor of the Trust.
|
|
|
|
|
|
(2)
|
|
Represents funds allocated to the Trust as part of the ongoing negotiation of
joint interest audit exceptions.
|
|
|
|
(3)
|
|
Represents funds allocated to the Trust as part
of the ongoing negotiation of joint interest audit exceptions, interest received for resolved audit
exceptions, and insurance proceeds for a bus ness interruption claim.
|
|
|
|
(4)
|
|
Represents a settlement between BROG and the Mineral Management Service of the
United States Department of the Interior (the “MMS”).
|
|
|
|
(5)
|
|
Represents deductions by BROG from the net proceeds otherwise payable to
the Trust in connection with the portion of various settlement agreements with the MMS.
|
|
|
|
(6)
|
|
RePresents excess production costs incurred in December 2001 and recovered
by BROG in 2002, plus interest.
|
Distributable
Income
“Distributable Income” (as that term is used herein) consists of Royalty Income plus
interest, less the general and administrative expenses of the Trust and any changes in cash
reserves established by the Trustee.
For the year ended December 31, 2006, Distributable Income was $135,867,325, representing a 10%
decrease from 2005. For the year ended December 31, 2005, Distributable Income was $151,560,081,
representing a 38% increase from 2004. Distributable Income in 2004 was $109,390,735.
The Trust received Royalty Income of $136,311,892 and interest income of $1,207,360 in 2006. After
deducting
administrative expenses of $1,651,927, Distributable Income for 2006 was $135,867,325 ($2.915055
per Unit). In 2005, Royalty Income was $153,858,264, interest income was $167,367, and
administrative expenses were $2,465,550, resulting in Distributable Income of $151,560,081
($3.251747 per Unit). Although the average gas price increased from $6.25 per Mcf for 2005 to $6.47
per Mcf for 2006, the 10% decrease in Distributable Income from 2005 to 2006 was primarily
attributable to an approximately $20 million increase in capital expenditures in 2006 as compared
to 2005. Interest earnings in 2006 were higher, as compared to 2005, primarily due to additional
interest received in July as partial payment of the Arbitration Award described in
N
o
7
Trustee’s
Discussion and Analysis
Note 7 to the financial statements included herewith. Administrative expenses were lower in
2006, as compared to 2005. Higher expenses were incurred in 2005 primarily as a result of
compliance with the new internal control, financial reporting and other requirements of the
Sarbanes-Oxley Act of 2002, costs incurred in resolving certain outstanding audit issues and
obtaining the Arbitration Award.
In 2004, the Trust received Royalty Income of $111,042,767 and interest income of $58,885. After
deducting administrative expenses of $1,710,917, Distributable Income for 2004 was $109,390,735
($2.346998 per Unit). The 38% increase in Distributable Income from 2004 to 2005 was primarily
attributable to higher gas and oil prices which resulted in increased Royalty Income. In addition,
interest earnings in 2005 were higher, as compared to 2004, primarily due to an increase in funds
available for investment as well as an increase in interest rates. Administrative expenses were
higher in 2005, as compared to 2004, primarily as a result of compliance with the new internal
control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002, costs
incurred in resolving certain outstanding audit issues and obtaining the Arbitration Award.
BROG has informed the Trustee that the New Mexico Oil and Gas Proceeds Withholding Tax Act (the
“Withholding Tax Act”) requires remitters who pay certain oil and gas proceeds from production on
New Mexico properties on or after October 1, 2003, to withhold income taxes from such proceeds in
the case of certain nonresident recipients. The Trustee, on advice of New Mexico counsel, has
observed that “net profits interests,” such as the Royalty, and other types of interests, the
extent of which cannot be determined with respect to a specific share of the oil and gas
production, are excluded from the withholding requirements of the Withholding Tax Act. Unit holders
are reminded to consult with their tax advisors regarding the applicability of New Mexico income
tax to distributions received from the Trust by a Unit holder.
Operating
Expenses
Monthly operating expenses of the Underlying Properties, exclusive of property taxes, in 2006
averaged approximately $1,871,974, which is higher than the $1,769,538 average in 2005 and higher
than the $1,639,670 average in 2004. Operating expenses have increased primarily because increased
activity strained the capacity of service vendors and resulted in increasing costs.
Settlements
As part of the September 4, 1996, settlement of the litigation filed by the Trustee on June 4,
1992 against BROG and Southland, the Trust was entitled to certain adjustments (the “Val Verde
Credit”) that represented cost reductions favorable to the Trust in the charges for coal seam gas
gathered and treated on BROG’s Val Verde system. Effective July 1, 2002, BROG sold the Val Verde
facility. Accordingly, effective July 1, 2002, the calculation of net proceeds for gas gathered and
treated at the Val Verde facility no longer includes the Val Verde Credit. The total amount of the
Val Verde Credit for the 12 months’ ended June 30, 2002, was estimated by the Trust’s joint
interest auditors as approximately $1,880,000. The loss of the Val Verde Credit resulted in
increased costs allocated to the Trust for coal seam gas gathered and treated on the Val Verde
system and accordingly, decreased the Royalty Income received by the Trust.
As a part of that same litigation settlement, the Trustee and BROG established a formal protocol
pursuant to which joint interest auditors retained by the Trustee gained improved access to BROG’s
books and records as applicable to the Underlying Properties. The audit process was initiated in
1996 and, since inception, has resulted in audit exceptions being granted by and payments or
credits received from BROG totaling approximately $21,600,000.
Capital
Expenditures
During 2006, in calculating Royalty Income, BROG deducted $39.2 million of capital
expenditures for projects, including drilling and completion of 115 gross (24.14 net) conventional
wells, two gross (0.003 net) payadds, two gross (1.74 net) recompletions, three gross (2.50 net)
restimulations, 44 gross (14.63 net) coal seam wells, seven gross (0.28 net) coal seam payadds, two
gross (0.48 net) coal seam recompletions, and two gross (0.08 net) coal seam miscellaneous capital
projects.
There were 100 gross (26.27 net) conventional wells, 14 gross (0.39 net) payadds, seven gross (3.49
net) recompletions, six gross (4.02 net) restimulations, four gross (0.02 net) miscellaneous
capital projects, 28 gross (11.79 net) coal seam wells, one gross (0.04 net) coal seam payadd, five
gross (3.57 net) coal seam recompletions, and two gross (0.004 net) coal seam restimulations in
progress as of December 31, 2006.
The aggregate capital expenditures reported by BROG in calculating Royalty Income for 2006 include
approximately
N
o
8
Trustee’s
Discussion and Analysis
$12.2 million attributable to the capital budgets for prior years. This occurs because
projects within a given year’s budget may extend into subsequent years, with capital expenditures
attributable to those projects used in calculating Distributable Income to the Trust in those
subsequent years. Further, BROG’s accounting period for capital expenditures runs through November
30 of each calendar year, such that capital expenditures incurred in December of each year are
actually accounted for as part of the following year’s capital expenditures. In addition, with
respect to wells not operated by BROG, BROG’s share of capital expenditures may not actually be
paid by it until the year or years after those expenses were incurred by the operator.
Capital expenditures of approximately $24.8 million for 2006 budgeted projects were used in
calculating net proceeds payable to the Trust in calendar year 2006, and approximately $7.1
million in capital expenditures from the 2006 budget were used in calculating net proceeds payable
to the Trust for January and February 2007. Therefore, an additional approximately $5.7 million in
capital expenditures for budgeted 2006 projects remains to be spent.
During 2005, in calculating Royalty Income, BROG deducted approximately $19.1 million of capital
expenditures for projects, including drilling and completion of 38 gross (2.72 net) conventional
wells, five gross (0.011 net) payadds, one gross (o.57 net) conventional restimulation, 25 gross
(2.89 net) coal seam wells, one gross (0.99 net) coal seam recavitation, two gross (0.61 net) coal
seam recompletions, and five gross (0.20 net) miscellaneous coal seam capital projects. There were
110 gross (19.08 net) conventional wells, eight gross (1.73 net) payadds, six gross (3.30 net)
conventional recompletions, seven gross (5.04 net) conventional restimulations, 59 gross (10.06
net) coal seam wells, five gross (2.32 net) coal seam recompletions, and one gross (0.04 net)
miscellaneous coal seam capital project in progress as of December 31, 2005.
During 2004, in calculating Royalty Income, BROG deducted approximately $22.3 million of capital
expenditures for projects, including drilling and completion of 25 gross (6.49 net) conventional
wells, recompletion of 11 gross (8.05 net) conventional wells, nine gross (5.95 net)
restimulations, three gross (0.007 net) conventional payadds, 61 gross (6.10 net) coal seam wells,
four gross (3.41 net) coal seam recompletions, and two gross (0.05 net) miscellaneous coal seam
capital projects and facilities maintenance. There were 57 gross
(6.94 net) new conventional wells, recompletion of three gross (0.89 net) conventional wells, four
gross (2.24 net) conventional well restimulations, 13 gross (1.74 net) conventional payadds, 48
gross (4.74 net) coal seam wells, four gross (1.90 net) coal seam recompletions, and six gross
(0.27 net) miscellaneous coal seam capital projects in progress as of December 31, 2004.
BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties
in 2007 is estimated at $28 million. Approximately $24 million of that budget is allocable to 112
new wells, including 33 wells scheduled to be dually completed in the Mesaverde and Dakota
formations and 10 wells scheduled to be dually completed in the Fruitland Coal and Pictured Cliffs
formations. BROG indicates that 34 of the new wells, at an aggregate cost of approximately $11.4
million, are projected to be drilled to formations producing coal seam gas. BROG reports that based
on its actual capital requirements, the pace of regulatory approvals, the mix of projects and
swings in the price of natural gas, the actual capital expenditures for 2007 could range from $20
million to $50 million.
Contractual
Obligations
Under the Indenture governing the Trust, the Trustee is entitled to an administrative fee for
its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of
1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual
gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates
(currently ranging from $75.00 to $250.00 per hour) for time in excess of 300 hours annually. As of
January 1, 2003, the administrative fee due under items (i) and (ii) above will not be less than
$36,000 per year (as adjusted annually to reflect the increase (if any) in the Producers Price
Index as published by the U.S. Department of Labor, Bureau of Labor Statistics).
Effects
of Securities Regulation
As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is
and will continue to be subject to extensive regulation under, among others, the Securities Act of
1933, the Securities Exchange Act of 1934 (which contains many of the provisions of the
Sarbanes-Oxley Act of 2002) and the rules and regulations of the NYSE. Issuers failing to comply
with such authorities risk serious consequences, including criminal as well as civil and
administrative penalties.
N
o
9
Trustee’s
Discussion and Analysis
In most instances, these laws, rules and regulations do not specifically address their
applicability to publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act
of 2002 provides for the adoption by the Securities and Exchange Commission (the “Commission”) and
NYSE of certain rules and regulations that may be impossible for the Trust to literally satisfy
because of its nature as a pass-through trust. It is the Trustee’s intention to follow the
Commission’s and NYSE’s rulemaking closely, attempt to comply with such rules and regulations and,
where appropriate, request relief from these rules and regulations. However, if the Trust is unable
to comply with such rules and regulations or to obtain appropriate relief, the Trust may be
required to expend as yet unknown but potentially material costs to amend the Indenture that
governs the Trust to allow for compliance with such rules and regulations. To date, the rules
implementing the Sarbanes-Oxley Act of 2002 have generally made appropriate accommodation for
passive entities such as the Trust.
Critical
Accounting Policies
In accordance with the Commission’s staff accounting bulletins and consistent with other
royalty trusts, the financial statements of the Trust are prepared on the following basis:
|
•
|
|
Royalty Income recorded for a month is the amount
computed and paid by BROG to the Trustee for the
Trust. Royalty Income consists of the proceeds
received by BROG from the sale of production from
the Underlying Properties less accrued production
costs, development and drilling costs, applicable
taxes, operating charges, and other costs and deductions,
multiplied by
75%.
The calculation of net proceeds
by BROG for any month includes adjustments to
proceeds and costs for prior months and impacts the
Royalty Income paid to the Trust and the distribution
to Unit holders for that month.
|
|
|
|
•
|
|
Trust expenses recorded are based on liabilities paid
and cash reserves established from Royalty Income
for liabilities and contingencies.
|
|
|
|
•
|
|
Distributions to Unit holders are recorded when
declared by the Trustee.
|
|
|
|
•
|
|
The conveyance which transferred the Royalty to the
Trust provides that any excess of production costs
applicable to the Underlying Properties over gross
proceeds from such properties must be recovered from
future net profits before Royalty Income is again paid
to the Trust.
|
The financial statements of the Trust differ from financial statements prepared in accordance with
U.S. generally accepted accounting principles (“GAAP”) because revenues are not accrued in the
month of production; certain cash reserves may be established for contingencies which would not be
accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid
instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis
is charged directly to trust corpus instead of an expense.
N
o
10
Trustee’s
Discussion and Analysis
Results
of the
4
TH
Ruarters
of
2006 & 2005
For the three months ended December 31, 2006, Distributable Income was $26,356,915 ($.565491
per Unit), which was less than the $46,012,856 ($.987214 per Unit) of income distributed during
the same period in 2005. The decrease in Distributable Income resulted primarily from lower
average gas prices.
Royalty Income of the Trust for the fourth quarter is based on actual gas and oil production
during August through October of each year. Gas and oil sales for the quarters ended December 31,
2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
2005
|
|
|
|
Underlying Properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas — Mcf
|
|
|
9,782,562
|
|
|
|
10,248,571
|
|
|
Mcf per Day
|
|
|
106,332
|
|
|
|
111,398
|
|
|
Average Price (per Mcf)
|
|
$
|
5.49
|
|
|
$
|
7.77
|
|
|
Oil — Bbls
|
|
|
14,992
|
|
|
|
16,477
|
|
|
Bbls per Day
|
|
|
163
|
|
|
|
179
|
|
|
Average Price (per Bbl)
|
|
$
|
60.72
|
|
|
$
|
59.06
|
|
|
|
|
|
|
|
|
|
|
|
|
Attributable
to the Royalty
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas — Mcf
|
|
|
5,156,724
|
|
|
|
6,516,096
|
|
|
Oil — Bbls
|
|
|
7,794
|
|
|
|
10,429
|
|
The average price of gas decreased and the average price of oil increased in 2006 compared to
the prior year. The price per barrel of oil during the fourth quarter of 2006 was $1.66 per Bbl
higher than that received in the fourth quarter of 2005 due to increases in oil prices in world
markets generally, including the posted price applicable to the Royalty. Gas production decreased
because new production brought on line in 2006 failed to completely offset the natural decline in
production from existing wells. In addition, production volumes were reduced in 2006 due to
operational difficulties in the San Juan Basin, including: weather-related shut downs, pipeline
maintenance work, compressor repairs and downtime at processing facilities.
Capital costs for the fourth quarter of 2006 totaled $8,436,427 compared to $4,734,866 during the
same period of 2005. Lease operating expenses and property taxes for the fourth quarter of 2006
averaged $1,819,291 per month compared to $1,939,447 per month in the fourth quarter of 2005.
Operating expenses were lower in the fourth quarter of 2006 than for the fourth quarter of 2005
primarily because in calculating Royalty Income for December 2006, BROG included a deduction of
$583,725 from lease operating expense as a result of the granting of certain audit exceptions for
the period 2003-2005.
Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarter of
2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
October
|
|
$
|
.257200
|
|
|
$
|
.243762
|
|
|
November
|
|
|
.210820
|
|
|
|
.334553
|
|
|
December
|
|
|
.097471
|
|
|
|
.408899
|
|
|
|
|
|
|
|
|
|
|
QUARTER TOTAL
|
|
$
|
.565491
|
|
|
$
|
.987214
|
|
|
|
|
|
|
|
|
|
N
o
11
San
Juan Basin Royalty Trust
S
tatements
of
A
ssets,
L
iabilities and
T
rust
C
orpus
December 31, 2006 and 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Cash and Short-Term
Investments
|
|
$
|
4,657,886
|
|
|
$
|
19,173,162
|
|
|
Net
Overriding Royalty Interests in Producing Oil and gas Properties
— Net
|
|
|
21,823,390
|
|
|
|
23,881,494
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
26,481,276
|
|
|
$
|
43,054,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
|
|
Liabilities
and Trust Corpus
|
|
|
|
|
|
|
|
|
|
Distribution Payable to Unit holders
|
|
$
|
4,543,028
|
|
|
$
|
19,058,304
|
|
|
Cash Reserves
|
|
|
114,858
|
|
|
|
114,858
|
|
|
Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding
|
|
|
21,823,390
|
|
|
|
23,881,494
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
26,481,276
|
|
|
$
|
43,054,656
|
|
|
|
|
|
|
|
|
|
S
tatements
of
D
istributable
I
ncome
For the three years ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Royalty Income
|
|
$
|
136,311,892
|
|
|
$
|
153,858,264
|
|
|
$
|
111,042,767
|
|
|
Interest Income
|
|
|
1,207,360
|
|
|
|
167,367
|
|
|
|
58,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137,519,252
|
|
|
|
154,025,631
|
|
|
|
111,101,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenditures — General and Administrative
|
|
|
1,651,927
|
|
|
|
2,465,550
|
|
|
|
1,710,917
|
|
|
Distributable Income
|
|
$
|
135,867,325
|
|
|
$
|
151,560,081
|
|
|
$
|
109,390,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable Income per Unit (46,608,796 Units)
|
|
$
|
2.915055
|
|
|
$
|
3.251747
|
|
|
$
|
2.346998
|
|
|
|
|
|
|
|
|
|
|
|
|
S
tatements
of
C
hanges in
T
rust
C
orpus
For the three years ended December 31 ,2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
|
Trust Corpus, Beginning of Period
|
|
$
|
23,881,494
|
|
|
$
|
26,674,821
|
|
|
$
|
29,822,820
|
|
|
Amortization of Net Overriding Royalty Interest
|
|
|
(2,058,104
|
)
|
|
|
(2,793,327
|
)
|
|
|
(3,147,999
|
)
|
|
Distributable Income
|
|
|
135,867,325
|
|
|
|
151,560,081
|
|
|
|
109,390,735
|
|
|
Distributions Declared
|
|
|
(135,867,325
|
)
|
|
|
(151,560,081
|
)
|
|
|
(109,390,735
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust Corpus, End of Period
|
|
$
|
21,823,390
|
|
|
$
|
23,881,494
|
|
|
$
|
26,674,821
|
|
|
|
|
|
|
|
|
|
|
|
|
These financial statements should be read in conjunction with the accompanying Notes to
Financial Statements included herein.
N
o
13
Notes to Financial Statements
1. T
rust
O
rganization
A
nd
P
rovisions
The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. Southland
Royalty Company (“Southland”) conveyed to the Trust a 75% net overriding royalty interest
(“Royalty”) carved out of Southland’s working interests and royalty interests (the “Underlying
Properties”) in the properties located in the San Juan Basin of northwestern New Mexico. Through
an acquisition completed March 24, 2006, Compass Bank succeeded TexasBank as “Trustee” (herein so
called) of the Trust. On February 16, 2007, Compass Bancshares, Inc. announced the signing of a
definitive agreement to be acquired by Banco Bilbao Vizcaya Argentaria, S.A (“BBVA”). Under the
terms of that agreement, Compass Bancshares, Inc. would become a wholly-owned subsidiary of BBVA.
The transaction is expected to close in the second half of 2007 and is subject to the approval of
shareholders of BBVA and Compass Bancshares, Inc. as well as to regulatory approval and customary
closing conditions.
On November 3, 1980, units of beneficial interest (“Units”) in the Trust were distributed to the
Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received
one Unit in the Trust for each share of Southland common stock held. The Units are traded on the
New York Stock Exchange.
The terms of the Trust Indenture provide, among other things, that:
|
•
|
|
The Trust shall not engage in any business or commercial
activity of any kind or acquire any assets other than
those initially conveyed to the Trust;
|
|
|
|
•
|
|
The Trustee may not sell all or any part of the
Royalty unless approved by holders of 75% of all Units
outstanding in which case the sale must be for cash
and the proceeds promptly distributed;
|
|
|
|
•
|
|
The Trustee may establish a cash reserve for the payment
of any liability which is contingent or uncertain in
amount;
|
|
|
|
•
|
|
The Trustee is authorized to borrow funds to pay liabilities
of the Trust; and
|
|
|
|
•
|
|
The Trustee will make monthly cash distributions to
Unit holders (see Note 2).
|
2. N
et
O
verriding
R
oyalty
I
nterest
A
nd
D
istribution
T
o
U
nit
H
olders
The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are
determined on a monthly basis by the Trustee. The Monthly Distribution Amount is an amount equal
to the sum of cash received by the Trustee during a calendar month attributable to the Royalty,
any reduction in cash reserves and any other
cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any
increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative
number, then the distribution will be zero for such month and such negative amount will be carried
forward and deducted from future monthly distributions until the cumulative distribution
calculation becomes a positive number, at which time a distribution will be made. Unit holders of
record will be entitled to receive the calculated Monthly Distribution Amount for each month on or
before 10 business days after the monthly record date, which is generally the last business day of
each calendar month.
The cash received by the Trustee consists of the proceeds received by the owner of the Underlying
Properties from the sale of production less the sum of applicable taxes, accrued production costs,
development and drilling costs, operating charges and other costs and deductions, multiplied by
75%.
The initial carrying value of the Royalty ($133,275,528) represented Southland’s historical net
book value at the date of the transfer of the Trust. Accumulated amortization as of December 31,
2006 and 2005 aggregated $111,452,138 and $109,394,034, respectively.
3.
B
asis
O
f
A
ccounting
The financial statements of the Trust are prepared on the following basis:
|
•
|
|
Royalty Income (as defined in the Glossary of Terms)
recorded for a month is the amount computed and
paid by the owner of the Underlying Properties,
Burlington Resources Oil & Gas Company LP
(“BROG”), the present owner of the Underlying
Properties, to the Trustee for the Trust. Royalty
Income consists of the proceeds received by BROG
from the sale of production less accrued production
costs, development and drilling costs, applicable
taxes, operating charges, and other costs and deductions,
multiplied by 75%. The calculation of net proceeds
by BROG for any month includes adjustments to
proceeds and costs for prior months and impacts the
Royalty Income paid to the Trust and the distribution
to Unit holders for that month.
|
|
•
|
|
Trust expenses recorded are based on liabilities paid
and cash reserves established from Royalty Income for
liabilities and contingencies.
|
|
|
|
•
|
|
Distributions to Unit holders are recorded when
declared by the Trustee.
|
|
|
|
•
|
|
The conveyance which transferred the Royalty to the
Trust provides that any excess of production costs
applicable to the Underlying Properties over gross
|
N
o
14
Notes to financial Statements
proceeds from such properties must be recovered from future net proceeds before
Royalty Income is again paid to the Trust.
The financial statements of the Trust differ from financial statements prepared in accordance with
United States generally accepted accounting principles (“GAAP”) because revenues are not accrued in
the month of production; certain cash reserves may be established for contingencies which would not
be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when
paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production
basis is charged directly to trust corpus instead of an expense. The basis of accounting used by
the Trust is widely used by royalty trusts for financial purposes.
4.
F
ederal
I
ncome
T
axes
For federal income tax purposes, the Trust constitutes a fixed investment trust which is
taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit
holders are considered to own the Trust’s income and principal as though no trust were in
existence. The income of the Trust is deemed to have been received or accrued by each Unit holder
at the time such income is received or accrued by the Trust rather than when distributed by the
Trust.
The Royalty constitutes an “economic interest” in oil and gas properties for federal income tax
purposes. Unit holders must report their share of the revenues of the Trust as ordinary income
from oil and gas royalties and are entitled to claim depletion with respect to such income. The
Royalty is treated as a single property for depletion purposes. The Trust has on file technical
advice memoranda confirming such tax treatment.
Sales of gas production from certain coal seam wells drilled prior to January 1, 1993, qualified
for federal income tax credits under Section 29 (now Section 45K) of the Internal Revenue Code of
1986, as amended (the “Code”), through 2002, but not thereafter. Accordingly, under present law,
the Trust’s production and sale of gas from coal seam wells does not qualify for tax credit under
Section 45K of the Code (the “Section 45K Tax Credit”). Congress has at various times since 2002
considered energy legislation, including provisions to reinstate the Section 45K Tax Credit in
various ways and to various extents, but no legislation that would qualify the Trust’s current
production for such credit has been enacted. For example, on August 8, 2005, new energy tax
legislation was enacted which, among other things, modified the Section 45K Tax Credit in several
respects, but did not extend the credit for production from coal seam wells. No prediction can be
made as to
what future tax legislation affecting Section 45K of the Code, may be proposed or enacted or, if
enacted, its impact, if any, on the Trust and the Unit holders.
The classification of the Trust’s income for purposes of the passive loss rules may be important to
a Unit holder. As a result of the Tax Reform Act of 1986, royalty income such as that derived
through the Trust will generally be treated as portfolio income and will not reduce passive losses.
5.
C
ertain
C
ontracts
BROG previously entered into two contracts for the sale of all volumes of gas produced from
the Underlying Properties. These contracts provided for (i) the sale of such gas to Duke Energy and
Marketing L.L.C. and PNM Gas Services (“PNM”), respectively, (ii) the delivery of such gas at
various delivery points through March 31, 2005, and from year-to-year thereafter until terminated
by either party on 12 months’ notice, and (iii) the sale of such gas at prices which fluctuate in
accordance with published indices for gas sold in the San Juan Basin of New Mexico. Effective
January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by
ConocoPhillips Company (“ConocoPhillips”) pursuant to an Assignment and Novation Agreement. By
correspondence dated March 25, 2004, BROG notified ConocoPhillips of BROG’s election to terminate
such contract as of March 31, 2005. BROG then prepared a form of request for proposal and
circulated it to a number of potential purchasers, including ConocoPhillips, inviting them to bid
for the purchase of the gas currently sold under the contract expiring March 31, 2005. Effective as
of April 1, 2005, BROG entered into two new contracts for the sale of all volumes of gas produced
from the Underlying Properties and formerly sold to ConocoPhillips. These new contracts provide for
(i) the sale of such gas to ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc.
(“ChevronTexaco”), and Coral Energy Resources, L.P. (“Coral”), respectively, (ii) the delivery of
such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until
terminated by either party on 12 months’ notice, and (iii) the sale of such gas at prices which
fluctuate in accordance with the published indices for gas sold in the San Juan Basin of New
Mexico. With respect to BROG’s contract with PNM, BROG and PNM have entered into a letter agreement
dated January 31, 2005, pursuant to which the parties waive the right to terminate the underlying
contract as of March 31, 2006, so that the term of that contract will continue until at least March
31, 2007, and from year-to-year thereafter until terminated by either party upon 12 months’ notice
to the
N
o
15
Notes to financial Statements
other. Neither BROG nor any of ChevronTexaco, Coral nor PNM gave notice to terminate
the three contracts described above for the sale of all volumes of gas produced from the
Underlying Properties, and, accordingly, the terms of those contracts have been extended through
March 31, 2008.
Confidentiality agreements with purchasers of gas produced from the Underlying Properties prohibit
public disclosure of certain terms and conditions of gas sales contracts with those entities,
including specific pricing terms and gas receipt points. Such disclosure could compromise the
ability to compete effectively in the marketplace for the sale of gas produced from the Underlying
Properties.
6.
Significant
Customers
Information as to significant purchasers of oil and gas production attributable to the
Trust’s economic interests is included in Note 5 above and Item 2 of the Trust’s Annual Report on
Form 10-K which is included in this report.
7.
Settlements and
Litigation
During 2004, an aggregate of $3,314,808 was included in calculating net proceeds paid to the
Trust by BROG as part of the ongoing negotiation of joint interest audit exceptions, interest for
resolved audit exceptions, and insurance proceeds for a business interruption claim.
In 2005, as part of the ongoing negotiations between the Trust and BROG concerning a number of
revenue and expense audit issues, an aggregate of $2,405,486 was included in calculating net
proceeds BROG paid to the Trust in settlement of certain of those audit issues.
During 2006, as part of the ongoing negotiations between the Trust and BROG concerning a number of
revenue and expense audit issues, an aggregate of $1,981,933 was included in calculating net
proceeds paid to the Trust, together with interest of $1,124,063 in settlement of certain of those
audit issues.
On November 11, 2005, an Arbitration Award was issued in favor of the Trust in the aggregate amount
of $7,683,699 in arbitration styled
San Juan Basin Royalty Trust vs. Burlington Resources Oil
&
Gas
Company LP
. The purpose of the arbitration was to resolve certain joint interest audit issues as
between the parties to the arbitration. On November 21, 2005, BROG filed its Original Petition to
Vacate or to Modify or Correct Arbitration Award in the cause styled
Burlington Resources Oil
&
Gas
Company LP vs. San Juan Basin Royalty Trust,
No. 2005-74370, in the District Court of Harris
County, Texas, 281st Judicial District. In this litigation, BROG alleged that the award in favor of
the Trust should be vacated or modified because one of the issues decided was beyond the scope of
the matters agreed to be arbitrated, the award was issued in manifest disregard of applicable law, and a
portion of the award is barred by limitations. BROG also sought to recover its attorneys’ fees. The
Trust filed an answer and counterclaim in the litigation filed by BROG denying those allegations
and asking that the arbitrator’s award be confirmed. On April 20, 2006, the Court entered an Order
denying BROG’s motion to vacate and granting the Trust’s application to confirm the Arbitration
Award and on June 6, 2006, rendered a final judgment in favor of the Trust. However, on May 22,
2006, BROG filed a Notice of Appeal indicating its desire to appeal the Order and any final
judgment confirming the Arbitration Award and on July 5, 2006, filed a Motion for New Trial in the
District Court of Harris County, Texas, urging substantially similar arguments made at the hearing.
The Trust responded to the Motion for New Trial and served BROG with post-judgment discovery
requests. BROG’s Motion for New Trial was overruled on August 4, 2006. BROG’s distribution to the
Trust for July 2006 included $1,534,182 representing a portion of the Arbitration Award, plus
accrued interest. Of this amount, $1,325,826 (the equivalent of $994,270 grossed up to account for
the Trust’s 75% net overriding royalty interest) was included in calculating the net proceeds paid
to the Trust, and the accrued interest thereon was $539,812. The balance of the Arbitration Award
is pending BROG’s appeal, which has been assigned No. 01-06-00485-CV in the First Court of Appeals
in Houston, Texas. On August 24, 2006, BROG filed its Supersedeas Bond to secure payment of the
balance of the Arbitration Award, plus interest, if the appeal is dismissed or BROG does not
perform the adverse judgment which becomes final on appeal. BROG filed its Brief of Appellant in
the First Court of Appeals on November 29, 2006 and the Trust filed its Brief of Appellee on
January 29, 2007. BROG was entitled to file its reply brief on or before February 20, 2007, but on
February 16, 2007, BROG filed a motion requesting an extension through March 22, 2007. Once all
briefs are filed, the parties will await either a ruling on their respective requests to present
oral arguments or a ruling on the merits based solely on the briefs. No reliable estimate can be
given as to when the First Court of Appeals will act and it should be noted that the ruling of that
Court on the merits of the appeal will itself be subject to possible discretionary review by the
Texas Supreme Court.
8.
Proved Oil and Gas Reserves
(unaudited)
Proved oil and gas reserve information is included in Item 2 of the Trust’s Annual Report on
Form 10-K which is included in this report.
N
o
16
9.
Quarterly Schedule Of Distributable Income (unaudited)
The following is a summary of the unaudited quarterly schedule of Distributable Income for the
two years ended December 31, 2006 (in thousands, except unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISTRIBUTABLE
|
|
|
|
|
ROYALTY
|
|
|
DISTRIBUTABLE
|
|
|
INCOME AND
|
|
|
|
|
INCOME
|
|
|
INCOME
|
|
|
DISTRIBUTION PER UNIT
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
50,481
|
|
|
$
|
50,490
|
|
|
$
|
1.083276
|
|
|
Second Quarter
|
|
|
28,532
|
|
|
|
27,933
|
|
|
|
.599299
|
|
|
Third Quarter
|
|
|
30,780
|
|
|
|
31,087
|
|
|
|
.666989
|
|
|
Fourth Quarter
|
|
|
26,519
|
|
|
|
26,357
|
|
|
|
.565491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
|
|
$
|
136,312
|
|
|
$
|
135,867
|
|
|
$
|
2.915055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First Quarter
|
|
$
|
39,242
|
|
|
$
|
38,736
|
|
|
$
|
.831092
|
|
|
Second Quarter
|
|
|
35,296
|
|
|
|
34,519
|
|
|
|
.740612
|
|
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Third Quarter
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32,833
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|
|
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32,292
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|
|
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.692829
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Fourth Quarter
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46,487
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|
|
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46,013
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.987214
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TOTAL
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$
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153,858
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$
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151,560
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$
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3.251747
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Report of Independent Registered Public Accounting Firm
WE HAVE AUDITED THE ACCOMPANYING STATEMENTS
of assets, liabilities and trust corpus of the San
Juan Basin Royalty Trust as of December 31, 2006 and 2005 and the related statements of
distributable income and changes in trust corpus for each of the three years in the period ended
December 31, 2006. These financial statements are the responsibility of the Trustee. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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 financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by the Trustee, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a reasonable basis for our
opinion.
As described in Note 3 to the financial statements, these financial statements were 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 financial statements referred to above present fairly, in all material
respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of
December 31, 2006 and 2005 and the distributable income and changes in trust corpus for each of
the three years in the period ended December 31, 2006, on the basis of accounting described in
Note 3 to the financial statements.
We have also audited in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Trust’s internal control over financial reporting
as of December 31, 2006, based on criteria established in
Internal Control — Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report
dated February 28, 2007, expressed an unqualified opinion thereon.
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Weaver and Tidwell,
L.L.P.
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Fort Worth, Texas
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February 28, 2007
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N
o
17
Glossary of Terms
Aggregate Monthly Distribution
:
An amount paid to Unit
holders equal to the Royalty Income received by the Trustee during a calendar month plus interest,
less the general and administrative expenses of the Trust, adjusted by any changes in cash
reserves.
BBL
:
Barrel, generally 42 U.S. gallons measured at 60°F.
BCF:
Billion cubic feet.
BROG:
Burlington Resources Oil & Gas Company LP.
BTU:
British thermal unit; the amount of heat necessary to raise the temperature of one pound of
water one degree Fahrenheit.
Coal Seam Well:
A well completed to a coal deposit found to contain and emit natural gas.
Commingled Well:
A well which produces from two or more formations through a common well
casing and a single tubing string.
Conventional Well:
A well completed to a formation historically found to contain deposits
of oil or gas (for example, in the San Juan Basin, the Pictured Cliffs, Dakota and Mesaverde
formations) and operated in the conventional manner.
Depletion:
The exhaustion of a petroleum reservoir; the reduction in value of a wasting
asset by removing minerals; for tax purposes, the removal and sale of minerals from a mineral
deposit.
Distributable Income:
An amount paid to Unit holders equal to the Royalty Income received
by the Trustee during a given period plus interest, less the general and administrative expenses
of the Trust, adjusted by any changes in cash reserves.
Dual Completion:
The completion of a well into two separate producing formations at
different depths, generally through one string of pipe producing from one of the formations,
inside of which is a smaller string of pipe producing from the other formation.
Estimated Future Net Revenues:
An estimate computed by applying current prices of oil and
gas (with consideration of price changes only to the extent provided by contractual arrangements
and allowed by Federal regulation) to estimated future production of proved oil and gas reserves
as of the date of the latest balance sheet presented, less estimated future expenditures (based on
current costs) to be incurred in developing and producing the proved reserves,and assuming
continuation of existing economic conditions; sometimes referred to as “estimated future net cash
flows.”
Grantor Trust:
A trust (or portion thereof) with respect to which the grantor or an
assignee of the grantor, rather than the trust, is treated as the owner of the trust properties and
is taxed directly on the trust income for federal income tax purposes under Sections 671 through
679 of the Internal Revenue Code of 1986, as amended.
Gross Acres or Wells:
The interests of all persons owning interests in such acres or
wells.
Gross Proceeds:
The amount received by BROG (or any subsequent owner of the Underlying
Properties) from the sale of the production attributable to such interests.
Infill Drilling:
The drilling of wells intended to be completed to proven reservoirs or
formations, sometimes occurring in conjunction with regulatory approval for increased density in
the spacing of wells.
Lease Operating Expenses:
Expenses incurred in the operation of a producing property as
apportioned among the several parties in interest.
MCF:
1,000 cubic feet; the standard unit for measuring the volume of natural gas.
MMBTU:
One million British thermal units.
Multiple Completion Well:
A well which produces simultaneously through separate tubing
strings from two or more producing horizons or alternatively from each.
Net Acres or Wells:
The interests of BROG in such acres or wells.
Net Overriding Royalty Interest:
A share of gross production from a property, measured by
net profits from operation of the property and carved out of the working interest, i.e., a net
profits interest.
Net Proceeds:
The excess of Gross Proceeds received by BROG during a particular period
over Production Costs for such period.
Payadd:
Completion in an existing well of additional productive zone(s) within a
producing formation.
Present Value Of Estimated Future Net Revenues:
The present value of the Estimated Future
Net Revenues computed using a discount rate of 10%.
Production Costs:
Costs incurred on an accrual basis by BROG in operating the Underlying
Properties, including both capital and non-capital costs and including, for example, development
drilling, production and processing costs, applicable taxes and operating charges.
Proved Developed Reserves:
Those Proved Reserves which can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves:
Those estimated quantities of crude oil, 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 oil and gas reservoirs under existing economic and
operating conditions.
Proved Undeveloped Reserves:
Those Proved Reserves which are expected to be recovered from new
wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required.
Recavitated Well:
A coal seam well, the production from which has been enhanced or
extended by the enlargement of the cavity within the coal deposit to which the well has been
completed.
Recompleted Well:
A well completed by drilling a separate well bore from an existing
casing in order to reach the same reservoir, or re-drilling the same well bore to reach a new
reservoir after production from the original reservoir has been abandoned.
Royalty:
The principal asset of the Trust; the 75% net overriding royalty interest
conveyed to the Trust on November 3,1980, by Southland Royalty Company, the predecessor to BROG,
which was carved out of the Underlying Properties.
Royalty Income:
The monthly Net Proceeds attributable to the Royalty.
Section
45K
tax credit:
A Federal income tax credit available under Section 45K
of the Internal Revenue Code of 1986, as amended, for coal seam gas (and certain other
nonconventional fuels) that was (i) sold prior to January 1, 2003 and (ii) produced from wells
drilled (or certain later recompletions treated as wells drilled) after December 31,1979, but
prior to January 1, 1993.
Spot Price:
The price paid for gas, oil or oil products sold under contracts for the
purchase and sale of such minerals on a short-term basis.
Underlying Properties:
The working, royalty and other interests owned by Southland
Royalty Company, the predecessor to BROG, in properties located in the San Juan Basin of
northwestern New Mexico, out of which the Royalty was carved.
Units of Beneficial Interest:
The units of ownership of the Trust, equal to the number of
shares of common stock of Southland Royalty Company outstanding at the close of business on
November 3,1980.
Working Interest:
The operating interest under an oil and gas lease.
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2525 Ridgmar Boulevard, Suite 100 ~S.CONT
Fort Worth, Texas 76116
Toll-free telephone: 966.809.4553
www.sjbrt.com
sjt@compassbank.com
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auditors
Weaver and Tidwell, L.L.P.
Dallas, Texas
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transfer Agent
Computershare Investor Services
P.O. Box 43078
Providence, RI 02940-43078
www.computershare.com
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for question about distribution checks, address
change, and transfer providers call 312-360-5154
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