e10vk
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, 2007
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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
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75-6279898
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(State or other jurisdiction
of
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(I.R.S. Employer
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incorporation or
organization)
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Identification No.)
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Compass Bank
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76116
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2525 Ridgmar Boulevard, Suite 100
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(Zip Code)
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Fort Worth, Texas
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(Address of principal executive
offices)
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(866) 809-4553
(Registrants 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 þ No o
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 þ
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 þ No o
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 registrants 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. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Rule
12b-2 of the Exchange Act. (Check one):
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Large accelerated filer
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Accelerated filer
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Non-accelerated
filer o
(Do not check if a smaller reporting company)
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Smaller Reporting
company o
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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 o No þ
State the aggregate market value of the Units of Beneficial
Interest held by non-affiliates of the registrant as of
June 30, 2007: $1,482,120,022.
At February 28, 2008, 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;
Trustees 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
registrants Annual Report to Unit Holders for the year
ended December 31, 2007, are incorporated herein by
reference for Item 5 (Market for Registrants Units,
Related Security Holder Matters and Issuer Purchases of Units),
Item 7 (Trustees 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 Trusts
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 LPs
(BROG), the working interest owners, 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 First Restated
Indenture) and, effective as of December 12, 2007,
the First Restated Indenture was amended and restated (the First
Restated 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 companys 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
companys 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 September 7, 2007, Compass Bancshares, Inc. was acquired
by Banco Bilbao Vizcaya Argentaria, S.A. (BBVA) and
is now a wholly-owned subsidiary of BBVA.
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 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
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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
Royaltys successor became BROG. On March 31, 2006, a
subsidiary of ConocoPhillips completed its acquisition of
Burlington Resources, Inc., BROGs 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 is a widely held fixed investment trust
(WHFIT) classified as a non-mortgage widely held
fixed investment trust (NMWHFIT) for federal income
tax purposes. The Trustee, 2525 Ridgmar Boulevard,
Suite 100, Fort Worth, Texas 76116, telephone number
1-866-809-4553, email address:
[email protected], is the
representative of the Trust that will provide tax information in
accordance with the applicable U.S. Treasury Regulations
governing the information reporting requirements of the Trust as
a WHFIT and a NMWHFIT. The tax information is generally posted
by the Trustee at www.sjbrt.com.
The Trust received approximately $113.8 million,
$136.3 million and $153.9 million in Royalty Income
from BROG in each of the fiscal years ended December 31,
2007, 2006 and 2005, respectively. After deducting
administrative expenses and accounting for interest income and
any change in cash reserves, the Trust distributed approximately
$113.2 million, $135.9 million and $151.6 million
to Unit Holders in each of the fiscal years ended
December 31, 2007, 2006 and 2005, respectively. The
Trusts corpus was approximately $19.9 million,
$21.8 million and $23.9 million as of
December 31, 2007, 2006 and 2005, 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. Additionally, BROG 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
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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 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
Trustees 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 at
least AAm by Standard & Poors and at least Aa by
Moodys, 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.
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 Trusts 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, including liquefied
natural 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.
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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 sale of
natural gas and oil production following the gathering and
processing of those minerals, 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 Trusts 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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During the period of time that is not less than 180 days
before the end of the Trusts fiscal year to which this
Annual Report on
Form 10-K
relates, the Trust did not receive 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
Royaltys (now BROGs) 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
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northwestern New Mexico and 3,823 gross (1,111 net) wells,
calculated on a well bore basis and not including multiple
completions as separate wells. Of those wells, seven gross (5.50
net) are oil wells and the balance are gas wells. BROG reports
that approximately 739 of the wells are multiple completion
wells resulting in a total of 4,599 completions. The Trust has
inquired of BROG whether the acreage is developed or
undeveloped. BROG has informed the Trust that all of the subject
acreage is held by production, and even though it has not been
fully developed in every formation, BROG has classified all of
such acreage as developed. Production 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 2007, in calculating Royalty Income, BROG deducted
$27.4 million of capital expenditures for projects,
including drilling and completion of 45 gross (21.47 net)
conventional wells and 21 gross (15.31 net) coal seam
wells. There were ten gross (0.35 net) conventional wells and
nine gross (4.52 net) coal seam wells in progress as of
December 31, 2007. All of the wells were development wells.
The aggregate capital expenditures deducted by BROG in
calculating Royalty Income for 2007 include approximately
$16.8 million attributable to the capital budgets for prior
years. This occurs because projects within a given years
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, BROGs 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 years
capital expenditures. In addition, with respect to wells not
operated by BROG, BROGs 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 $10.6 million for
2007 budgeted projects were used in calculating net proceeds
payable to the Trust in calendar year 2007. The
$10.6 million covered 140 projects, including the drilling
of 79 new wells operated by BROG and one new well operated by a
third party. New drilling activity was at an aggregate cost of
approximately $7.8 million. The balance of the expenditures
was attributable to the workover of existing wells and the
maintenance and improvement of production facilities. BROG
reports that an additional approximately $5 million in
capital expenditures for budgeted 2007 projects is estimated to
be spent in 2008.
During 2006, in calculating Royalty Income, BROG deducted
approximately $39.2 million of capital expenditures for
projects, including drilling a 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. All of
the wells were development wells. A payadd is the completion of
an additional productive interval in an existing completed zone
in a well.
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. All of the wells were development wells.
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BROG has informed the Trust that it has revised the 2008 budget
for capital expenditures for the Underlying Properties to
$24.4 million, an increase from the $18.3 million that
was previously disclosed in the Trusts press release dated
February 19, 2008. Approximately 35% of the planned
expenditures will be on Fruitland Coal formation projects with
the remainder to be spent on conventional projects. In addition,
BROG estimates that during 2008 it will incur capital expenses
in the amount of approximately $5 million attributable to
the capital budgets for 2007 and prior years. 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 2008 could
range from $15 million to $50 million.
BROG anticipates 361 projects in 2008 at an aggregate cost of
$24.4 million. Approximately $19.7 million of that
budget is allocable to 70 new wells, including 37 wells
scheduled to be dually completed in the Mesaverde and Dakota
formations at an aggregate projected cost of approximately
$9.4 million, and four wells to be completed to the Dakota
formation at an aggregate cost of approximately
$2.3 million. BROG indicates that 16 of the new wells, at
an aggregate cost of approximately $7.3 million, are
projected to be drilled to formations producing coal seam gas.
BROG also mentioned that the possible implementation of new
rules restricting the use of open reserve pits could reduce the
number of projects due to increased compliance costs. Of the
$5 million attributable to the budgets for prior years,
approximately $2 million is allocable to new wells to be
operated by BROG; an estimated $1 million is allocable to
new wells to be operated by others; and the $2 million
balance will be applied to miscellaneous capital projects such
as workovers and operated facility projects.
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
density in the Fruitland Coal formation.
Eighty-acre
density has been permitted in the Mesaverde formation since
1997. In January 2008, BROG reported to the Trust that it will
participate in a study involving a total of 16 test wells to be
completed to the Mesaverde
and/or
Dakota formations, with some of the test wells to be drilled on
a 40-acre
spacing basis and others on a
20-acre
spacing. In addition, BROG is scheduled to participate in a
pilot project for the drilling of four horizontal wells, with
two to be completed to each of the Dakota and Mesaverde
formations. Although none of the four horizontal wells are to be
drilled on acreage burdened by the Royalty, the pilot project
could have implications for the San Juan Basin generally.
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, 2007, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
Gas
|
|
|
Oil
|
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
(Bbls)
|
|
|
Production
|
|
|
20,116,806
|
|
|
|
35,129
|
|
|
|
22,475,405
|
|
|
|
40,702
|
|
|
|
26,600,644
|
|
|
|
43,142
|
|
Average Price
|
|
$
|
6.11
|
|
|
$
|
63.14
|
|
|
$
|
6.55
|
|
|
$
|
61.30
|
|
|
$
|
6.27
|
|
|
$
|
49.62
|
|
Production volumes and costs attributable to the Underlying
Properties for the three years ended December 31, 2007,
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Production
|
|
|
36,961,349
|
Mcf
|
|
|
40,900,570
|
Mcf
|
|
|
42,867,162
|
Mcf
|
Total Production Costs
|
|
$
|
77,932,758
|
|
|
$
|
88,625,021
|
|
|
$
|
68,607,709
|
|
Lease Operating Expenses
|
|
$
|
27,947,790
|
|
|
$
|
22,463,687
|
|
|
$
|
21,234,459
|
|
Average Lifting Cost per Unit of Production
|
|
$
|
.7561
|
|
|
$
|
.5492
|
|
|
$
|
.4953
|
|
8
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 36,961,349 Mcf during 2007.
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 BROGs 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
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 northwestern 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 BROGs
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
northwestern New Mexico. With respect to BROGs contract
with PNM, BROG and PNM entered into a letter agreement dated
January 31, 2005, pursuant to which the term of that
contract was adjusted to coincide with the contracts with
ChevronTexaco and Coral. Neither BROG nor any of ChevronTexaco,
Coral nor PNM gave notice by March 31, 2007 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 at least through
March 31, 2009. On January 15, 2008, PNM Resources,
the corporate parent of PNM, announced a definitive agreement to
sell its natural gas operations to a subsidiary of Continental
Energy Systems. The sale is conditioned upon regulatory approval
and customary closing conditions and is currently expected to
close by the end of 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.
9
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 developed reserves are those reserves that
can be expected to be recovered through existing wells with
existing equipment and operating methods. See 17 CFR
210.4-10(a)(3).
Proved reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known oil and gas reservoirs
under existing economic and operating conditions. See
17 CFR 210.4-10(a)(2) (2)(iii).
Proved undeveloped reserves are those reserves that
are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major
expenditure is required for recompletion. See 17 CFR
210.4-10(a)(4).
The independent petroleum engineers reports as to the
proved oil and gas reserves as of December 31, 2005, 2006
and 2007, were prepared by Cawley, Gillespie &
Associates, Inc. The following table presents a reconciliation
of proved reserve quantities attributable to the Royalty from
December 31, 2004, to December 31, 2007, (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
Crude
|
|
|
Natural
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates
|
|
|
3
|
|
|
|
(15,263
|
)
|
Extensions, discoveries and other additions
|
|
|
20
|
|
|
|
9,774
|
|
Production
|
|
|
(35
|
)
|
|
|
(20,117
|
)
|
|
|
|
|
|
|
|
|
|
Reserves as of December 31, 2007
|
|
|
388
|
|
|
|
194,855
|
|
|
|
|
|
|
|
|
|
|
10
Estimated quantities of proved developed reserves of crude oil
and natural gas as of December 31, 2007, 2006 and 2005 were
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Crude Oil (Bbls)
|
|
|
333
|
|
|
|
357
|
|
|
|
395
|
|
Natural Gas (Mcf)
|
|
|
171,165
|
|
|
|
197,466
|
|
|
|
231,235
|
|
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 enterprises 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 Trusts quantity of proved
reserves, changes in prices will result in changes in quantities
of proved oil and gas reserves and estimated future net revenues.
The 2007, 2006 and 2005 changes in the standardized measure of
discounted future net cash flows related to future royalty
income from proved reserves are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Balance, January 1
|
|
$
|
746,327
|
|
|
$
|
1,090,324
|
|
|
$
|
756,017
|
|
Revisions of prior-year estimates, change in prices and other
|
|
|
7,282
|
|
|
|
(345,237
|
)
|
|
|
339,865
|
|
Extensions, discoveries and other additions
|
|
|
36,319
|
|
|
|
28,520
|
|
|
|
72,698
|
|
Accretion of discount
|
|
|
74,633
|
|
|
|
109,032
|
|
|
|
75,602
|
|
Royalty Income
|
|
|
(113,803
|
)
|
|
|
(136,312
|
)
|
|
|
(153,858
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
750,758
|
|
|
$
|
746,327
|
|
|
$
|
1,090,324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
The December 31, 2007 price of $7.14 per Mcf of gas and
$87.22 per Bbl of oil were used in determining future net
revenue. The upward revision in reserve quantities for 2007 is
due primarily to an increase in gas prices in December 2007 as
compared to December 2006, offset by increased lease operating
expenses and reduced gas and oil production.
11
The December 31, 2006 price of $6.39 per Mcf of gas and
$58.65 per Bbl of oil were used in determining future net
revenue. The downward revision in reserve quantities for 2006 as
compared to 2005 is due primarily to lower gas prices in
December 2006 as compared to December 2005.
The December 31, 2005 price of $8.19 per Mcf of gas and
$54.17 per Bbl of oil were used 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, 2007, 2006
and 2005 (in thousands, except amounts per Unit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
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
|
|
$
|
1,329,974
|
|
|
$
|
750,758
|
|
|
$
|
1,337,575
|
|
|
$
|
746,327
|
|
|
$
|
2,018,722
|
|
|
$
|
1,090,324
|
|
Proved Developed
|
|
$
|
1,167,273
|
|
|
$
|
670,144
|
|
|
$
|
1,198,784
|
|
|
$
|
677,276
|
|
|
$
|
1,785,597
|
|
|
$
|
965,615
|
|
Total Proved Per Unit
|
|
$
|
28.53
|
|
|
$
|
16.11
|
|
|
$
|
28.70
|
|
|
$
|
16.01
|
|
|
$
|
43.31
|
|
|
$
|
23.39
|
|
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.
Reserve estimates were not filed with any Federal authority or
agency other than the SEC.
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
12
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 FERCs
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 Trusts 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 Trusts
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.
Passive
Loss Rules
The classification of the Trusts 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 that may not be offset or reduced by 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
Trusts ability to timely report certain information
required to be disclosed in the Trusts periodic reports is
dependent on BROGs 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 a lawsuit in the state
District Court of Harris County, Texas
13
alleging that the award in favor of the Trust should be vacated
or modified. BROG also sought to recover its attorneys
fees. On April 20, 2006, the state District Court of Harris
County, Texas entered an Order denying BROGs motion to
vacate and granting the Trusts 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 state District Court of Harris County, Texas, urging
substantially similar arguments made at the hearing. BROGs
Motion for New Trial was overruled on August 4, 2006.
BROGs 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
$994,370 grossed up to account for the Trusts 75% net
overriding royalty interest) was included in calculating the net
proceeds paid to the Trust, and the accrued interest thereon was
$539,812. In August 2007 the First Court of Appeals in Houston,
Texas, issued an opinion reversing the judgment of the trial
court and vacating the Arbitration Award as it relates to the
unpaid balance. The Trust filed a Petition for Review in the
Supreme Court of Texas. On January 11, 2008, the Texas
Supreme Court declined to review the ruling of the First Court
of Appeals. The Trust is considering the remedies available to
it. No estimate can be given at this time as to either the date
the litigation will be completed or the eventual outcome.
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
|
At a special meeting of the Unit Holders held on
December 12, 2007, the following proposals were submitted
to the Unit Holders with the following results (each of the four
proposals were adopted by the Unit Holders):
1. Amendment to the First Restated Indenture regarding a
direct registration system (DRS) due to the
SECs approval of an amendment to the listing requirements
of the New York Stock Exchange that require listed companies to
be eligible to participate in a DRS.
|
|
|
|
|
|
|
Number of Units
|
|
|
For
|
|
|
39,063,892
|
|
Against
|
|
|
362,111
|
|
Abstain
|
|
|
337,263
|
|
2. Amendment to the First Restated Indenture regarding
asset sales to permit the Trustee to sell up to one percent (1%)
of the value (based on prior year engineering reports) of the
Royalty in any twelve month period.
|
|
|
|
|
|
|
Number of Units
|
|
|
For
|
|
|
38,126,487
|
|
Against
|
|
|
1,236,687
|
|
Abstain
|
|
|
400,092
|
|
3. Amendment to the First Restated Indenture regarding
electronic voting to take advantage of technological advances
and to offer Unit Holders a variety of voting methods, including
telephone and internet voting.
|
|
|
|
|
|
|
Number of Units
|
|
|
For
|
|
|
38,692,169
|
|
Against
|
|
|
681,828
|
|
Abstain
|
|
|
389,269
|
|
14
4. Amendment to the First Restated Indenture regarding
investments to revise the types of money market mutual funds
registered under the Investment Company Act of 1940, as amended,
in which the Trustee may invest.
|
|
|
|
|
|
|
Number of Units
|
|
|
For
|
|
|
38,413,680
|
|
Against
|
|
|
930,612
|
|
Abstain
|
|
|
418,974
|
|
PART II
|
|
ITEM 5.
|
MARKET
FOR REGISTRANTS UNITS, RELATED UNIT HOLDER MATTERS AND
ISSUER PURCHASES OF UNITS
|
The information under Units of Beneficial Interest
at page 2 of the Trusts Annual Report to Unit Holders
for the year ended December 31, 2007, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
Royalty Income
|
|
$
|
113,803,339
|
|
|
$
|
136,311,892
|
|
|
$
|
153,858,264
|
|
|
$
|
111,042,767
|
|
|
$
|
91,997,262
|
|
Distributable income
|
|
|
113,221,235
|
|
|
|
135,867,325
|
|
|
|
151,560,081
|
|
|
|
109,390,735
|
|
|
|
90,357,837
|
|
Distributable income per Unit
|
|
|
2.429184
|
|
|
|
2.915055
|
|
|
|
3.251747
|
|
|
|
2.346998
|
|
|
|
1.938644
|
|
Distributions per Unit
|
|
|
2.429184
|
|
|
|
2.915055
|
|
|
|
3.251747
|
|
|
|
2.346998
|
|
|
|
1.938644
|
|
Total assets, December 31
|
|
|
28,923,416
|
|
|
|
26,481,276
|
|
|
|
43,054,656
|
|
|
|
36,814,866
|
|
|
|
36,905,104
|
|
|
|
ITEM 7.
|
TRUSTEES
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
|
The Description of the Properties and
Trustees Discussion and Analysis at pages 5
through 11 of the Trusts Annual Report to Unit Holders for
the year ended December 31, 2007, 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 Trusts
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 Trusts Annual Report to Unit
Holders for the year ended December 31, 2007, are herein
incorporated by reference.
15
|
|
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 Trusts 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 Trusts filings under the Securities
Exchange Act of 1934 (the Exchange Act) is recorded,
processed, summarized and reported, within the time periods
specified in the SECs 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 Trusts
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 Trusts
ability to timely report certain information required to be
disclosed in the Trusts periodic reports is dependent on
BROGs 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 Trusts
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 Trusts disclosure controls
and procedures as of December 31, 2007, 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
Trusts periodic reports. In reaching its conclusion, the
Trustee considered the Trusts dependence on BROG to
deliver timely and accurate information to the Trust. The
Trustee has not reviewed the Trusts 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, 2007, there were no
changes in the Trusts 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 Trusts internal control
over financial reporting. The Trustee has not evaluated the
Trusts 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.
16
Trustees
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 Trusts 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 Trusts 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, 2007, the Trustee assessed the
effectiveness of the Trusts 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, 2007, 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 Trusts internal
control over financial reporting as of December 31, 2007.
The report, which expresses an unqualified opinion on the the
effectiveness of the Trusts internal control over
financial reporting as of December 31, 2007, 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 San Juan Basin Royalty Trusts (the
Trust) internal control over financial reporting as
of December 31, 2007, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission
(the COSO criteria). Compass Bank (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 included in the Trustees Report On Internal
Control Over Financial Reporting in Item 9A. Our
responsibility is to express an opinion on the Trusts
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, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control, based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A trusts 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 Trusts modified cash basis of accounting, which is a
comprehensive basis of accounting other than U.S. generally
accepted accounting principles. A trusts 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 trusts assets that could have a
material effect on the financial statements.
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.
17
In our opinion, the Trust maintained, in all material respects,
effective internal control over financial reporting as of
December 31, 2007, 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, 2007 and 2006 and the related statements of
distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2007 of the
Trust and our report dated February 29, 2008 expressed an
unqualified opinion thereon.
/s/ Weaver
and Tidwell, L.L.P.
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
February 29, 2008
|
|
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,
2007, 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 Trusts 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 2007.
|
|
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.
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
|
|
|
2007
|
|
|
|
Trustee
|
|
|
$
|
304,668
|
|
Compass Bank(2)
|
|
|
2006
|
|
|
|
Trustee
|
|
|
$
|
249,924
|
|
TexasBank
|
|
|
2005
|
|
|
|
Trustee
|
|
|
$
|
310,461
|
|
18
|
|
|
(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
Trustees 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 September 7,
2007, Compass Bancshares, Inc. was acquired by Banco Bilbao
Vizcaya Argentaria, S.A. (BBVA) and is now a
wholly-owned subsidiary of BBVA. |
|
|
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. The following table sets forth as of
February 22, 2008 information with respect to the only Unit
Holder who was known to the Trustee to be a beneficial owner of
more than 5 percent of the outstanding Units.
|
|
|
|
|
|
|
|
|
|
|
Number of Units
|
|
Percent of
|
Name and Address of Beneficial Owner
|
|
Beneficially Owned
|
|
Class
|
|
Arnhold and S. Bleichroeder Advisors, LLC
|
|
|
3,061,220
|
|
|
|
6.57
|
%
|
1345 Avenue of the Americas
New York, NY 10105(1)
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
This information was provided to the SEC and to the Trustee in a
Schedule 13G filed with the SEC on February 12, 2008,
on behalf of Arnohld and S. Bleichroeder Advisors, LLC. |
(b) Security Ownership of Trustee. As of
February 22, 2008, Compass Bank beneficially owned 15,530
Units, or less than one percent of the Units. Compass Bank has
sole voting power over 14,030 of these Units and has the sole
power to dispose of 1,080 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, 2007 and Item 12 for information
concerning Units owned by the Trustee.
19
|
|
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
Trusts principal accountants, for the audit of the
Trusts annual financial statements for the fiscal years
ended December 31, 2007 and 2006 and fees billed for other
services rendered to the Trust by Weaver and Tidwell, L.L.P.
during those periods.
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Audit Fees
|
|
$
|
73,050
|
|
|
$
|
71,125
|
|
Audit-Related Fees
|
|
|
-0-
|
|
|
|
-0-
|
|
Tax Fees
|
|
|
3,750
|
|
|
|
5,475
|
|
All Other Fees
|
|
|
-0-
|
|
|
|
-0-
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
76,800
|
|
|
$
|
76,600
|
|
|
|
|
|
|
|
|
|
|
Audit Fees consist of fees billed for professional services
rendered for the audit of the Trusts annual financial
statements and internal control over financial reporting, review
of the interim financial statements included in the Trusts
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 Trusts 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 Trusts independent accountants.
Pursuant to the terms of the Indenture, the Trustee engages and
approves all services rendered by the Trusts 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 Trusts Annual Report to Unit Holders
for the year ended December 31, 2007:
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
20
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
December 12, 2007 (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, which was amended and
restated effective September 30, 2002), heretofore filed as
Exhibit 99.2 to the Trusts Current Report on
Form 8-K
filed with the SEC on December 14, 2007, 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), heretofore filed as
Exhibit 4(b) to the Trusts Annual Report on
Form 10-K
filed with the SEC on March 1, 2007, is incorporated herein
by reference.
|
|
4(c)
|
|
|
Assignment of Net Overriding Interest (San Juan Basin
Royalty Trust), dated September 30, 2002, between Bank One,
N.A. and TexasBank.*
|
|
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 Trusts Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended March 31, 2003, is
incorporated herein by reference.
|
|
13
|
|
|
Registrants Annual Report to Unit Holders for the fiscal
year ended December 31, 2007.*
|
|
23
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.*
|
|
31
|
|
|
Certification required by
Rule 13a-14(a),
dated February 29, 2008, 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 February 29, 2008, 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. |
21
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: February 29, 2008
(The Trust
has no directors or executive officers)
22
EXHIBIT INDEX
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|
|
|
|
Exhibit
|
|
|
Number
|
|
Description
|
|
|
4(a)
|
|
|
Amended and Restated Royalty Trust Indenture, dated
December 12, 2007 (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, which was amended and
restated effective September 30, 2002), heretofore filed as
Exhibit 99.2 to the Trusts Current Report on
Form 8-K
filed with the SEC on December 14, 2007, 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), heretofore filed as
Exhibit 4(b) to the Trusts Annual Report on
Form 10-K
filed with the SEC on March 1, 2007, is incorporated herein
by reference.
|
|
4(c)
|
|
|
Assignment of Net Overriding Interest (San Juan Basin
Royalty Trust), dated September 30, 2002, between Bank One,
N.A. and TexasBank.*
|
|
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 Trusts Quarterly Report on
Form 10-Q
filed with the SEC for the quarter ended March 31, 2003, is
incorporated herein by reference.
|
|
13
|
|
|
Registrants Annual Report to Unit Holders for the fiscal
year ended December 31, 2007.*
|
|
23
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.,
reservoir engineer.*
|
|
31
|
|
|
Certification required by
Rule 13a-14(a),
dated February 29, 2008, 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 February 29, 2008, 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. |
23