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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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(Mark One) FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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COMMISSION FILE NUMBER: 1-11608
WILLIAMS COAL SEAM GAS ROYALTY TRUST
(Exact name of registrant as specified in its charter)
DELAWARE 75-6437433
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification number)
TRUST DIVISION 75202
NATIONSBANK OF TEXAS, N.A. (Zip Code)
NATIONSBANK PLAZA
901 MAIN STREET, 17TH FLOOR
DALLAS, TEXAS
(Address of principal executive offices)
Registrant's telephone number, including area code:
(214) 508-2364
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Units of Beneficial Interest New York Stock Exchange, Inc.
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
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 X No
--- ---
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 the 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. X
---
At March 15, 1996, there were 9,700,000 units of beneficial interest
outstanding and the aggregate market value of such units (based on the closing
sale price on the New York Stock Exchange) held by non-affiliates of the
registrant was approximately $197,637,500.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below are documents parts of which are incorporated herein by
reference and the part of this report into which the document is incorporated:
1995 Annual Report to Unitholders--Part II.
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TABLE OF CONTENTS
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PART I
ITEM 1. Business........................................................ 1
Glossary...................................................... 1
Description of the Trust...................................... 5
Creation and Organization of the Trust...................... 5
Assets of the Trust......................................... 5
Liabilities of the Trust.................................... 6
Duties and Limited Powers of the Trustee.................... 6
Liabilities of the Delaware Trustee and the Trustee......... 7
Termination and Liquidation of the Trust.................... 7
Description of Units.......................................... 9
Distributions and Income Computations....................... 9
Transfer of Royalty Interests............................... 10
Possible Divestiture of Units............................... 10
Periodic Reports to Unitholders............................. 10
Voting Rights of Unitholders................................ 11
Liability of Unitholders.................................... 12
Transfer Agent.............................................. 12
Federal Income Taxation....................................... 12
Summary of Certain Federal Income Tax Consequences.......... 13
ERISA Considerations.......................................... 17
State Tax Considerations...................................... 18
Regulation and Prices......................................... 18
Regulation of Natural Gas................................... 18
Environmental Regulation.................................... 19
Competition, Markets and Prices............................. 20
ITEM 2. Properties...................................................... 21
The Royalty Interests......................................... 21
The Underlying Properties................................... 22
The NPI..................................................... 24
Reserve Report.............................................. 25
Historical Gas Sales Prices and Production.................. 27
Purchase Price Adjustments.................................. 27
NPI Percentage Changes...................................... 27
Gas Purchase Contract....................................... 28
Gas Gathering Contract...................................... 30
Federal and Indian Lands.................................... 31
Sale and Abandonment of Underlying Properties............... 32
The Infill NPI.............................................. 33
Williams' Performance Assurances............................ 33
Title to Properties......................................... 34
Methane Contamination Litigation............................ 36
ITEM 3. Legal Proceedings............................................... 36
ITEM 4. Submission of Matters to a Vote of Security Holders............. 37
PART II
Market for Registrant's Common Equity and Related Stockholder
ITEM 5. Matters......................................................... 37
ITEM 6. Selected Financial Data......................................... 37
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ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 37
ITEM 8. Financial Statements and Supplementary Data.................... 37
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 37
PART III
ITEM 10. Directors and Executive Officers of the Registrant............. 37
ITEM 11. Executive Compensation......................................... 37
ITEM 12. Security Ownership of Certain Beneficial Owners and Management. 38
Williams' Ownership of Units................................. 38
ITEM 13. Certain Relationships and Related Transactions................. 39
Administrative Services Agreement............................ 39
Potential Conflicts of Interest.............................. 39
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K.............................................................. 40
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PART I
ITEM 1. BUSINESS.
The following is a glossary of certain defined terms used in this Annual
Report on Form 10-K.
GLOSSARY
"Administrative Services Agreement" means the Administrative Services
Agreement, dated effective December 1, 1992, between Williams and the Trust, a
copy of which is filed as an exhibit to this Form 10-K.
"Aftertax Cash Flow per Unit" means the sum of the following amounts that a
hypothetical purchaser of a Unit in the Public Offering would have received or
been allocated if such Unit were held through the date of such determination:
(a) total cash distributions per Unit plus (b) total tax credits available per
Unit under Section 29 of the IRC less (c) the net taxes payable per Unit
(assuming a Federal income tax rate of 31 percent, which at the time of the
formation of the Trust was the highest Federal income tax rate applicable to
individuals).
"Bcf" means billion cubic feet of natural gas. Natural gas volumes are
stated herein at the legal pressure base of 14.73 pounds per square inch
absolute at 60 degrees Fahrenheit.
"Blanco Hub Spot Price" means the posted index price of spot gas delivered
to pipelines per MMBtu (dry basis) as published in the first issue of the
month during which gas is delivered or such determination is made, as the case
may be, in Inside FERC's Gas Market Report for "El Paso Natural Gas Company,
San Juan," or in the event a Blanco Hub posted index price is at some time in
the future reported by Inside FERC's Gas Market Report, then the Blanco Hub
posted index price will be substituted in place of the "El Paso Natural Gas
Company, San Juan" posted index price.
"Btu" means British Thermal Unit, the common unit of gross heating value
measurement.
"Citibank's Base Rate" means a fluctuating interest rate per annum
(compounded quarterly) as shall be in effect from time to time which rate per
annum shall at all times be equal to the rate of interest announced publicly
by Citibank, N.A. in New York, New York, from time to time, as its base rate.
"Comparison Reserve Report" means the Reserve Report, dated February 23,
1994, on the estimated reserves attributable to the Royalty Interests as of
December 31, 1993 (but using October 1, 1992 Reserve Report pricing), prepared
by Miller and Lents, Ltd., independent petroleum engineers, a copy of which is
filed as an exhibit to this Form 10-K.
"Confirmation Agreement" means the Confirmation Agreement dated effective as
of May 1, 1995 by and among WPC, Williams and the Trust, a copy of which is
filed as an exhibit to this Form 10-K.
"Conveyance" means the Net Profits Conveyance dated effective as of October
1, 1992, by and among Williams, WPC, the Trustee and the Delaware Trustee, a
copy of which is filed as an exhibit to this Form 10-K.
"December 31, 1992 Reserve Report" means the Reserve Report, dated March 10,
1993, on the estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1992, prepared by Miller and
Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
"December 31, 1993 Reserve Report" means the Reserve Report, dated February
23, 1994, on the estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1993, prepared by Miller and
Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
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"December 31, 1994 Reserve Report" means the Reserve Report, dated February
28, 1995, on the estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1994, prepared by Miller and
Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
"December 31, 1995 Reserve Report" means the Reserve Report, dated March 8,
1996, on the estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of December 31, 1995, prepared by Miller and
Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
"Delaware Code" means the Delaware Business Trust Act, Title 12, Chapter 38
of the Delaware Code, Sections 3801 et seq.
"Delaware Trustee" means Chemical Bank Delaware, in its capacity as a trustee
of the Trust.
"Enhanced recovery or similar operations" means operations conducted for the
purpose of maintaining, sustaining or enhancing production from the Underlying
Properties. These operations may include additional compression, the injection
of carbon dioxide or other gases or hydraulic fracturing.
"Farmout Properties" means the 5,348 gross acres in La Plata County, Colorado
on which WPC owns a 35 percent net profits interest, also referred to as the
PLA-9 Properties.
"Gas Gathering Contract" means the Gas Gathering and Treating Agreement,
dated October 1, 1992, as amended, between WFS Gas Resources Company (as
successor in interest to WGM) and WFS, a copy of which is filed as an exhibit
to this Form 10-K.
"Gas Purchase Contract" means the Gas Purchase Agreement, dated October 1,
1992, as amended, between WFS Resources (as successor in interest to WGM) and
WPC, a copy of which is filed as an exhibit to this Form 10-K.
"Grantor trust" means a trust as to which the grantor, or his successor, has
retained an interest in the income from the trust.
"Gross acres" means the total number of surface acres of land.
"Gross wells" means the total whole number of gas wells.
"Index Price" means 97 percent of the Blanco Hub Spot Price as of the date
the determination is made.
"Infill Net Proceeds" consists generally of the aggregate proceeds based on
the price at the Wellhead of gas produced from WPC's net revenue interest in
any possible Infill Wells less (a) WPC's working interest share of property and
production taxes on such Infill Wells; (b) WPC's working interest share of
operating costs on such Infill Wells; (c) WPC's working interest share of
capital costs on such Infill Wells, including costs of drilling and completing
such Infill Wells and the costs of associated surface facilities; and (d)
interest on the unrecovered portion, if any, of the foregoing costs at
Citibank's Base Rate.
"Infill NPI" refers to one of the net profits interests conveyed to the
Trust, consisting of a 20 percent interest in WPC's Infill Net Proceeds.
"Infill Wells" means any possible additional well drilled on a producing
drilling block when well spacing rules are effectively modified from the
existing 320 acre spacing.
"IRC" means the Internal Revenue Code of 1986, as amended.
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"IRR" means the annual discount rate (compounded quarterly) that equates the
present value of the Aftertax Cash Flow per Unit to the initial price to the
public of the Units in the Public Offering (which was $20.00 per Unit).
"Mcf" means thousand cubic feet of natural gas.
"Minimum Purchase Price" means 97 percent of $1.75 per MMBtu (dry basis).
"MMBtu" means million Btu.
"MMcf" means million cubic feet of natural gas.
"Net profits interest" generally refers to a real property interest entitling
the owner to receive a specified percentage of the net proceeds from the sale
of production attributable to the properties burdened thereby, the amount of
which is based on a revenue formula specified in such net profits interest.
"NPI" refers to one of the net profits interests conveyed to the Trust,
generally entitling the Trust to receive 81 percent of the NPI Net Proceeds
attributable to (i) WPC's net revenue interest (working interest less lease
burdens) in the WI Properties and (ii) the revenue stream received by WPC
attributable to its 35 percent net profits interest in the Farmout Properties.
The NPI is subject to reduction as described under "Item 2--The Royalty
Interests--NPI Percentage Changes."
"NPI Net Proceeds" consists generally of the aggregate proceeds attributable
to (i) WPC's net revenue interest based on the sale at the Wellhead of gas
produced from the WI Properties and (ii) the revenue stream received by WPC
from its 35 percent net profits interest in the Farmout Properties, less (a)
WPC's working interest share of property and production taxes on the WI
Properties; (b) WPC's working interest share of actual operating costs on the
WI Properties to the extent in excess of those agreed to be paid by WPC as
described herein; (c) WPC's working interest share of capital costs on the WI
Properties to the extent in excess of those agreed to be paid by WPC as
described herein; and (d) interest on the unrecovered portion, if any, of the
foregoing costs at Citibank's Base Rate.
"Net wells" and "net acres" are calculated by multiplying gross wells or
gross acres by the interest in such wells or acres.
"October 1, 1992 Reserve Report" means the Reserve Report, dated November 21,
1992, on the estimated reserves, estimated future net revenues and the
discounted estimated future net revenues attributable to the Royalty Interests
and the Underlying Properties as of October 1, 1992, prepared by Miller and
Lents, Ltd., independent petroleum engineers, a copy of which is filed as an
exhibit to this Form 10-K.
"Price Credit" means the credit received by WFS Resources from WPC for each
MMBtu of natural gas purchased by WFS Resources when the Index Price is less
than the Minimum Purchase Price on or after January 1, 1994, equal to the
difference between the Minimum Purchase Price and the Index Price.
"Price Credit Account" means the account established by WPC containing the
accrued and unrecouped amount of any Price Credits.
"Price Differential" means 50 percent of the excess of the Index Price over
$1.94 per MMBtu.
"Public Offering" has the meaning assigned to such term herein under "Item
1--Description of the Trust--Creation and Organization of the Trust."
"Royalty Interests" means the NPI and Infill NPI conveyed to the Trust.
"Trust" means Williams Coal Seam Gas Royalty Trust, a Delaware business trust
formed pursuant to the Trust Agreement.
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"Trust Agreement" means the Trust Agreement, dated as of December 1, 1992,
among Williams, WPC, as grantor, Chemical Bank Delaware, as the Delaware
Trustee, and NationsBank of Texas, N.A., as the Trustee, as amended by the
First Amendment thereto effective as of December 15, 1992 and by the Second
Amendment thereto effective as of January 12, 1993, a copy of each of which is
filed as an exhibit to this Form 10-K.
"Trustee" means NationsBank of Texas, N.A., in its capacity as a trustee of
the Trust.
"Underlying Properties" means the net revenue interests (working interests
less lease burdens) and net profits interests of WPC in certain proved
properties in the Fruitland coal formation in the San Juan Basin of New Mexico
and Colorado as specified in the Conveyance.
"Units" means the 9,700,000 units of beneficial interest issued by, and
evidencing the entire beneficial interest in, the Trust.
"Wellhead" means at or in the vicinity of the wellhead of gas produced.
"WFS" means Williams Field Services Company, a wholly-owned subsidiary of
Williams Field Services Group, Inc. (a wholly-owned subsidiary of Williams).
"WFS Resources" means WFS Gas Resources Company, a Delaware corporation and a
wholly-owned subsidiary of Williams.
"WGM" means Williams Gas Marketing Company, a wholly-owned subsidiary of
Williams Field Services Group, Inc. (a wholly-owned subsidiary of Williams).
"WGM Payment Obligations" has the meaning assigned to such term under "Item
2--The Royalty Interests--Williams' Performance Assurances."
"WHD" means Williams Holdings of Delaware, Inc., a wholly-owned subsidiary of
Williams.
"Williams" means The Williams Companies, Inc.
"WI Properties" means the net revenue interests (working interests less lease
burdens) of WPC in the Underlying Properties including WPC's interests in 13
Federal producing units in New Mexico.
"Working interest" generally refers to a real property interest entitling the
owner to receive a specified percentage of the proceeds from the sale of oil
and gas production or a percentage of such production, but requiring the owner
of such working interest to bear the costs to explore for, develop and produce
such oil and gas.
"WPC" means Williams Production Company, a wholly-owned subsidiary of
Williams Field Services Group, Inc. (a wholly-owned subsidiary of Williams).
"WPC Payment Obligations" has the meaning assigned to such term under "Item
2--The Royalty Interests--Williams' Performance Assurances."
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DESCRIPTION OF THE TRUST
Williams Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware
business trust under the Delaware Business Trust Act, Title 12, Chapter 38 of
the Delaware Code, Sections 3801 et seq. (the "Delaware Code"). The following
information is subject to the detailed provisions of (i) the Trust Agreement
of Williams Coal Seam Gas Royalty Trust (as amended, the "Trust Agreement")
entered into effective as of December 1, 1992 by and among Williams Production
Company, a Delaware corporation ("WPC"), as trustor, The Williams Companies,
Inc., a Delaware corporation ("Williams"), and Chemical Bank Delaware, a
Delaware banking corporation (the "Delaware Trustee"), and NationsBank of
Texas, N.A., a national banking association (the "Trustee"), as trustees, and
(ii) the Net Profits Conveyance (the "Conveyance") dated effective as of
October 1, 1992 by and among WPC, Williams, the Trustee, and the Delaware
Trustee. Copies of the Trust Agreement and of the Conveyance are filed as
exhibits to this Form 10-K. The provisions governing the Trust are complex and
extensive and no attempt has been made below to describe or reference all of
such provisions. The following is a general description of the basic framework
of the Trust and a summary of the material terms of the Trust Agreement, and
detailed provisions concerning the Trust may be found in the Trust Agreement.
CREATION AND ORGANIZATION OF THE TRUST
All of the authorized units of beneficial interest in the Trust ("Units")
were issued to WPC on January 21, 1993. On that date, WPC transferred its
Units to its parent, Williams, by dividend. Williams, in turn, sold, by means
of a prospectus dated January 13, 1993, 5,200,000 Units on January 21, 1993,
and an additional 780,000 Units on February 16, 1993, to the public through
various underwriters (the "Public Offering"). In the second quarter of 1993,
Williams sold an additional 151,209 Units. During the second quarter of 1995
Williams transferred its Units to Williams Holdings of Delaware, Inc. ("WHD"),
a separate holding and finance company for Williams' non-regulated businesses.
The Trust has been formed under Delaware law pursuant to the terms of the
Trust Agreement to acquire and hold certain net profits interests (the
"Royalty Interests") in proved natural gas properties located in the San Juan
Basin of New Mexico and Colorado (the "Underlying Properties"). The Royalty
Interests were conveyed to the Trust on January 21, 1993 pursuant to the
Conveyance for the benefit of the Unitholders. The Trustee has powers to
collect and distribute proceeds received by the Trust and to pay Trust
liabilities and expenses. The Delaware Trustee has only such powers as are set
forth in the Trust Agreement and is not empowered to otherwise manage or take
part in the business of the Trust. The Royalty Interests are passive in nature
and neither the Delaware Trustee nor the Trustee has any control over or any
responsibility relating to the operation of the Underlying Properties. Except
for the commitment by WPC to pay the costs incurred to place into production
certain proved nonproducing wells, neither WPC nor the operators of the
Underlying Properties has any contractual commitments to the Trust to further
develop the Underlying Properties, to remain as operator with respect to any
of the leases on the Underlying Properties or to maintain their ownership
interest in any of the properties. However, WPC retained an interest in each
of the Underlying Properties immediately after conveyance of the Royalty
Interests to the Trust. WPC may sell the Underlying Properties subject to and
burdened by the Royalty Interests. For a description of the Underlying
Properties and other information relating to such properties, see "Item 2--The
Royalty Interests."
The Delaware Trustee and the Trustee may resign at any time or be removed
with or without cause by a vote of not less than a majority of the outstanding
Units. Any successor trustee must be a bank or trust company meeting certain
requirements including having capital, surplus and undivided profits of at
least $20,000,000, in the case of the Delaware Trustee, and $100,000,000, in
the case of the Trustee.
ASSETS OF THE TRUST
The only assets of the Trust, other than cash and temporary investments
being held for the payment of expenses and liabilities and for distribution to
Unitholders, are the Royalty Interests. The
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Royalty Interests consist primarily of a net profits interest (the "NPI") in
the Underlying Properties. The NPI generally entitles the Trust to receive 81
percent of the NPI Net Proceeds, as defined below, attributable to (i) gas
produced and sold from WPC's net revenue interests (working interests less
lease burdens) in the properties in which WPC has a working interest (the "WI
Properties") and (ii) the revenue stream received by WPC attributable to its
35 percent net profits interest on 5,348 gross acres in La Plata County,
Colorado (the "Farmout Properties"). The Royalty Interests also include a 20
percent interest in the Infill Net Proceeds, as defined below (the "Infill
NPI"), from the sale of production if well spacing rules are effectively
modified and additional wells are drilled on producing drilling blocks on the
WI Properties (the "Infill Wells") during the term of the Trust. "NPI Net
Proceeds" consists generally of the revenue stream received by WPC from its 35
percent net profits interest in the Farmout Properties plus the aggregate
proceeds attributable to WPC's net revenue interest based on the price paid at
or in the vicinity of the wellhead (the "Wellhead") of gas produced from the
WI Properties less WPC's share of certain taxes and costs. "Infill Net
Proceeds" consists generally of the aggregate proceeds based on the price at
the Wellhead of gas produced from WPC's net revenue interest on any Infill
Wells less certain taxes and costs. The complete definitions of NPI Net
Proceeds and Infill Net Proceeds are set forth in the Conveyance. See "Item
2--The Royalty Interests" for more information.
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on
the power of the Trustee to incur obligations, the only liabilities the Trust
generally incurs are those for routine administrative expenses, such as the
trustee's fees and accounting, engineering, legal and other professional fees
and the administrative services fee paid to Williams. However, if a court were
to hold that the Trust is taxable as a corporation, then the Trust would incur
substantial Federal income tax liabilities. See "--Federal Income Taxation."
DUTIES AND LIMITED POWERS OF THE TRUSTEE
Under the Trust Agreement, the Trustee receives the payments attributable to
the Royalty Interests and pays all expenses, liabilities and obligations of
the Trust. With respect to any liability that is contingent or uncertain in
amount or that otherwise is not currently due and payable, the Trustee has the
discretion to establish a cash reserve for the payment of such liability. The
Trustee is also entitled to cause the Trust to borrow money to pay expenses,
liabilities and obligations that cannot be paid out of cash held by the Trust.
Any such borrowings may be from any source, including from the entity serving
as Trustee or Delaware Trustee, provided that the entity serving as Trustee or
Delaware Trustee shall not be obligated to lend to the Trust. To secure
payment of any such indebtedness (including any indebtedness to the entity
serving as Trustee or Delaware Trustee), the Trustee is authorized to (i)
mortgage and otherwise encumber the entire Trust estate or any portion
thereof; (ii) carve out and convey production payments; (iii) include all
terms, powers, remedies, covenants and provisions it deems necessary or
advisable, including confession of judgment and the power of sale with or
without judicial proceedings; and (iv) provide for the exercise of those and
other remedies available to a secured lender in the event of a default on such
loan. The terms of such indebtedness and security interest, if funds were
loaned by the entity serving as Trustee or Delaware Trustee, must be similar
to the terms which such entity would grant to a similarly situated commercial
customer with whom it did not have a fiduciary relationship, and such entity
shall be entitled to enforce its rights with respect to any such indebtedness
and security interest as if it were not then serving as trustee.
The Trustee is authorized and directed to sell and convey the Royalty
Interests without Unitholder approval in certain instances as described in the
Trust Agreement, including (i) upon termination of the Trust, (ii) commencing
January 1, 2003, if a portion of the NPI ceases to produce or is not capable
of producing in commercially paying quantities (see "Item 2--The Royalty
Interests--Sale and
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Abandonment of Underlying Properties") and (iii) in connection with payment of
a purchase price adjustment for uncompleted wells or successful Southern Ute
Indian claims (see "Item 2--The Royalty Interests--Purchase Price Adjustments"
and "--Title to Properties"). The Trustee is empowered by the Trust Agreement
to employ consultants and agents (including WPC and Williams) and to make
payments of all fees for services or expenses out of the assets of the Trust.
The Trust has no employees. The administrative functions of the Trust are
performed by the Trustee.
The Trust Agreement authorizes the Trustee to take such action as in its
judgment is necessary or advisable to achieve the purposes of the Trust. The
Trustee is authorized to agree to modifications of the terms of the Conveyance
and to settle disputes with respect thereto, so long as such modifications or
settlements do not result in treatment of the Trust as an association taxable
as a corporation for Federal income tax purposes and such modifications or
settlements do not alter the nature of the Royalty Interests as a right to
receive a share of the proceeds of production from the Underlying Properties
which, with respect to the Trust, are free of any operating rights, expense or
cost. The Trust Agreement provides that cash being held by the Trustee as a
reserve for liabilities or for distribution at the next distribution date will
be placed in demand accounts, U.S. government obligations, repurchase
agreements secured by such obligations, or certificates of deposit, but the
Trustee is otherwise prohibited from acquiring any asset other than the Royalty
Interests or engaging in any business or investment activity of any kind
whatsoever. The Trustee may deposit funds awaiting distribution in an account
with the Trustee or Delaware Trustee provided the interest paid equals the
amount paid by the Trustee or Delaware Trustee on similar deposits.
LIABILITIES OF THE DELAWARE TRUSTEE AND THE TRUSTEE
Each of the Delaware Trustee and the Trustee may act in its discretion and
shall be personally or individually liable only for fraud or acts or omissions
in bad faith or which constitute gross negligence and will not be otherwise
liable for any act or omission of any agent or employee unless such trustee has
acted in bad faith or with gross negligence in the selection and retention of
such agent or employee. Each of the Delaware Trustee and the Trustee will be
indemnified from the Trust assets for any liability, expense, claim, damage or
other loss incurred in performing its duties, unless resulting from gross
negligence, fraud or bad faith (the Delaware Trustee or the Trustee will be
indemnified from the Trust assets against its own negligence which does not
constitute gross negligence), and will have a first lien upon the assets of the
Trust as security for such indemnification and for reimbursements and
compensation to which it is entitled. WPC and Williams have agreed to indemnify
each of the Delaware Trustee and the Trustee against certain environmental and
securities laws liabilities, respectively, provided that the Trustee and
Delaware Trustee are generally required to first be indemnified from Trust
assets before seeking indemnification from WPC or Williams. Neither the
Delaware Trustee nor the Trustee shall be entitled to indemnification from
Unitholders (except in connection with lost or destroyed Unit certificates).
TERMINATION AND LIQUIDATION OF THE TRUST
The Trust will not terminate prior to January 1, 2003, except upon the
affirmative vote of the holders of not less than 75 percent of the outstanding
Units to liquidate the Trust. Thereafter, the Trust will terminate upon the
first to occur of (i) an affirmative vote of the holders of not less than a
majority of the outstanding Units to liquidate the Trust; (ii) such time as the
ratio of the cash amounts received by the Trust from the Royalty Interests
(excluding deductions for capital expenditures for enhanced recovery or similar
operations on the WI Properties) to administrative costs of the Trust is less
than 1.2 to 1.0 for three consecutive calendar quarters; (iii) such time as the
Royalty Interests held by the Trust have been sold by the Trust; (iv) March 1
of any calendar year if, based on a reserve report as of December 31 of the
prior year, it is determined that, as of such date, the net present value
(discounted at 10 percent) of the estimated future net revenues (calculated in
accordance with
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criteria established by the Securities and Exchange Commission (the
"Commission") but using the average monthly Blanco Hub Spot Price (as defined;
see "Item 2--The Royalty Interests--Gas Purchase Contract")) of proved reserves
attributable to the Royalty Interests is equal to or less than $30 million; and
(v) December 31, 2012 (the date of any such occurrence is referred to herein as
the "Termination Date"). Following termination, the Trustee and the Delaware
Trustee will continue to act as trustees of the Trust until all remaining Trust
assets have been sold and the net proceeds from such sales distributed to
Unitholders.
Upon the termination of the Trust, the Trustee will use best efforts (as
defined in the Trust Agreement) to sell any remaining Royalty Interests for
cash pursuant to the procedures described herein. The Trustee will retain an
investment banking firm (the "Advisor") on behalf of the Trust who will assist
the Trustee in selling the remaining Royalty Interests then owned by the Trust.
WPC has the right, but not the obligation, to purchase all remaining Royalty
Interests following termination of the Trust as described in the following
paragraph.
WPC may, within 60 days following the Termination Date, make a cash offer to
purchase all of the remaining Royalty Interests then held by the Trust. In the
event such an offer is made by WPC, the Trustee will decide, based on the
recommendation of the Advisor, to either (i) accept such offer (in which case
no sale to WPC will be made unless a fairness opinion is given by the Advisor
that the purchase price is fair to the Trust and Unitholders) or (ii) defer
action on the offer for approximately 60 days and seek to locate other buyers
for the remaining Royalty Interests. If the Trustee defers action on WPC's
offer, the offer will be deemed withdrawn and the Trustee will then use best
efforts (as defined in the Trust Agreement), assisted by the Advisor, to locate
other buyers for the Royalty Interests. At the end of a 120-day period
following the Termination Date, the Trustee is required to notify WPC of the
highest of any other offers, acceptable to the Trustee (which must be an all
cash offer), received during such period (the "Highest Offer Price"). WPC then
has the right (whether or not it made an initial offer), but not the
obligation, to purchase all remaining Royalty Interests for a cash purchase
price computed as follows: (i) if the Highest Offer Price is more than 105
percent of WPC's original offer (or if WPC did not make an initial offer), the
purchase price will be 105 percent of the Highest Offer Price, or (ii) if the
Highest Offer Price is equal to or less than 105 percent of WPC's original
offer, the purchase price will be equal to the Highest Offer Price. If no other
acceptable offers are received for all remaining Royalty Interests, the Trustee
may request WPC to submit another offer for consideration by the Trustee and
may accept or reject such offer.
If a sale of the Royalty Interests is made or a definitive contract for sale
of the Royalty Interests is entered into within a 150-day period following the
Termination Date, the buyer of the Royalty Interests, and not the Trust or
Unitholders, will be entitled to all proceeds of production attributable to the
Royalty Interests following the Termination Date.
In the event that WPC does not purchase the Royalty Interests, the Trustee
may accept any offer for all or any part of the Royalty Interests as it deems
to be in the best interests of the Trust and Unitholders and may continue, for
up to one calendar year after the Termination Date, to attempt to locate a
buyer or buyers of the remaining Royalty Interests in order to sell such
interests in an orderly fashion. If any Royalty Interests have not been sold or
a definitive agreement for sale has not been entered into by the end of such
calendar year, the Trustee is required to sell the remaining Royalty Interests
at public auction, which sale may be to WPC or any of its affiliates.
WPC's purchase rights, as described, may be exercised by WPC and each of its
successors in interest and assigns. WPC's purchase rights are fully assignable
by WPC to any person. The costs of liquidation, including the fees and expenses
of the Advisor, and the Trustee's liquidation fee will be paid by the Trust.
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DESCRIPTION OF UNITS
Each Unit represents an equal undivided share of beneficial interest in the
Trust and is evidenced by a transferable certificate issued by the Trustee.
Each Unit entitles its holder to the same rights as the holder of any other
Unit, and the Trust has no other authorized or outstanding class of equity
security. At March 15, 1996, there were 9,700,000 Units outstanding. The Trust
may not issue additional Units.
DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee determines for each quarter the amount of cash available for
distribution to Unitholders. Such amount (the "Quarterly Distribution Amount")
is equal to the excess, if any, of the cash received by the Trust, on or prior
to the last day of the month following the end of each calendar quarter ending
prior to the dissolution of the Trust from the Royalty Interests then held by
the Trust, plus, with certain exceptions, any other cash receipts of the Trust
during such quarter (which might include purchase price adjustments paid by WPC
and sales proceeds not sufficient in amount to qualify for special distribution
as described in the next paragraph, and interest), over the liabilities of the
Trust paid during such quarter, subject to adjustments for changes made by the
Trustee during such quarter in any cash reserves established for the payment of
contingent or future obligations of the Trust. Based on the payment procedures
relating to the Royalty Interests, cash received by the Trustee in a particular
quarter from the Royalty Interests generally represents the sum of (i) proceeds
from the sale of gas produced from the WI Properties during the preceding
calendar quarter, plus, (ii) cash received by WPC with respect to the Farmout
Properties either (a) during the preceding calendar quarter or (b) if received
in sufficient time to be paid to the Trust, in the month immediately following
such calendar quarter. The Quarterly Distribution Amount for each quarter is
payable to Unitholders of record on the 45th day following the end of such
calendar quarter unless such day is not a business day in which case the record
date is the next business day thereafter. The Trustee distributes the Quarterly
Distribution Amount within 60 days after the end of each calendar quarter to
each person who was a Unitholder of record on the associated record date,
together with interest expected to be earned on such Quarterly Distribution
Amount from the date of receipt thereof by the Trustee to the payment date.
WPC may be required to pay to the Trust amounts as an adjustment to the
original purchase price paid for Units. See "Item 2--The Royalty Interests--
Title to Properties--Southern Ute Litigation." In addition, the Royalty
Interests may be sold under certain circumstances and will be sold following
termination of the Trust. Any purchase price adjustments and the proceeds from
sales of the Royalty Interests, less liabilities and expenses of the Trust and
amounts used for cash reserves, will be distributed, together with any interest
expected to be earned thereon, to Unitholders of record on the record date
established for such distribution. A special distribution will be made of
undistributed sales proceeds, purchase price adjustments and other amounts
received by the Trust aggregating in excess of $9,000,000 (a "Special
Distribution Amount"). The record date for a Special Distribution Amount will
be the 15th day following receipt of amounts aggregating a Special Distribution
Amount by the Trust (unless such day is not a business day in which case the
record date will be the next business day thereafter) unless such day is within
10 days of the record date for a Quarterly Distribution Amount in which case
the record date will be the date as is established for the next Quarterly
Distribution Amount. Distribution to Unitholders will be made no later than 15
days after the Special Distribution Amount record date.
The terms of the Trust Agreement seek to assure to the extent practicable
that gross income attributable to cash being distributed will be reported by
the Unitholder who receives such distributions assuming that such Unitholder is
the owner of record on the applicable record date. In certain circumstances,
however, a Unitholder will not receive the cash giving rise to such income. For
example, the Trustee maintains a cash reserve, and is authorized to borrow
money under certain conditions, in order to pay or provide for the payment of
Trust liabilities. Income associated with the
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cash used to increase that reserve or to repay that loan must be reported by
the Unitholder, even though that cash is not distributed to him. Likewise, if a
portion of a cash distribution is attributable to a reduction in the cash
reserve maintained by the Trustee, such cash is treated as a reduction to the
Unitholder's basis in his Units and is not treated as taxable income to such
Unitholder (assuming such Unitholder's basis exceeds the amount of the
distribution of cash reserve).
TRANSFER OF ROYALTY INTERESTS
WPC is required to pay to the Trust, as a purchase price adjustment, certain
amounts in the event WPC is prohibited from producing or receiving proceeds
from coal seam gas from certain Underlying Properties because of Southern Ute
Indian claims. In such event, the affected Royalty Interests will be released
by the Trust or reconveyed, as the case may be, to WPC or its assigns. WPC or
its assigns may also, at any time after January 1, 2003, purchase for cash all
Royalty Interests attributable to Underlying Properties which are uneconomical
to operate. See "Item 2--The Royalty Interests--Title to Properties" and "--
Sale and Abandonment of Underlying Properties." Upon termination of the Trust,
any remaining Royalty Interests will be sold by the Trust and any such sales
may, and under certain circumstances will, be made to WPC or Williams or their
respective successors or assigns. See "--Description of the Trust--Termination
and Liquidation of the Trust."
POSSIBLE DIVESTITURE OF UNITS
The Trust Agreement imposes no restrictions based on nationality or other
status of Unitholders. However, the Trust Agreement provides that in the event
of certain judicial or administrative proceedings seeking the cancellation or
forfeiture of any property in which the Trust has an interest, or asserting the
invalidity of or otherwise challenging any portion of the Royalty Interests,
because of the nationality, citizenship or any other status, of any one or more
Unitholders, the Trustee will give written notice thereof to each Unitholder
whose nationality, citizenship or other status is an issue in the proceeding,
which notice will constitute a demand that such Unitholder dispose of his Units
within 30 days. If any Unitholder fails to dispose of his Units in accordance
with such notice, the Trustee shall have the right to cancel all outstanding
certificates issued in the name of such Unitholder, transfer all Units held by
such Unitholder to the Trustee and sell such Units (including by private sale).
The proceeds of such sale (net of sales expenses), pending delivery of
certificates representing the Units, will be held by the Trustee in a non-
interest bearing account for the benefit of the Unitholder and paid to the
Unitholder upon surrender of such certificates. Cash distributions payable to
such Unitholder will also be held in a non-interest bearing account pending
disposition by the Unitholder of the Units or cancellation of certificates
representing the Units by the Trustee.
PERIODIC REPORTS TO UNITHOLDERS
Within 60 days following the end of each of the first three calendar quarters
of each calendar year, the Trustee mails to each party who was a Unitholder of
record (i) on the quarterly record date for such quarter or (ii) on a Special
Distribution Amount record date occurring during such quarter (if any), a
report which shows in reasonable detail the assets and liabilities and receipts
and disbursements of the Trust for such quarter. Unitholders are also furnished
with comparable quarterly information with respect to the Underlying
Properties. Within 120 days following the end of each fiscal year or such
shorter period of time as may be required by the rules of the New York Stock
Exchange, the Trustee mails to Unitholders of record as of a date to be
selected by the Trustee an annual report containing audited financial
statements relating to the Trust and the Underlying Properties.
The Trustee files such returns for Federal income tax purposes as it is
advised are required to comply with applicable law. The Trustee mails to each
party who was a Unitholder of record (i) on the quarterly record date for such
quarter or (ii) on a Special Distribution Amount record date
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occurring during such quarter (if any), a report which shows in reasonable
detail the information necessary to permit each Unitholder to make all
calculations reasonably necessary for tax purposes. The Trustee treats all
income, credits and deductions recognized during each quarter as having been
recognized by holders of record on the quarterly record date established for
the distribution unless otherwise advised by counsel. Available year-end tax
information permitting each Unitholder to make all calculations reasonably
necessary for tax purposes is distributed by the Trustee to Unitholders no
later than March 15 of each calendar year, with final information furnished
after publication by the Internal Revenue Service ("IRS") of the prior year's
Section 29 tax credit amount. The 1994 Section 29 tax credit of $0.9958 per
MMBtu was determined as of March 31, 1995, and the Trustee estimates, based on
the first estimate of the GNP implicit price deflator published by the Bureau
of Economic Analysis for calendar year 1995, that the 1995 Section 29 tax
credit will be approximately $1.0029 per MMBtu. The Trustee will furnish
Unitholders with the final Section 29 tax credit information for 1995, after it
is published by the IRS, in the next quarterly report to Unitholders unless it
differs materially from the Trustee's estimate, in which case the Trustee will
promptly mail this information to each Unitholder.
Each Unitholder and his duly authorized agents and attorneys have the right
during reasonable business hours to examine and inspect records of the Trust
and the Trustee.
VOTING RIGHTS OF UNITHOLDERS
Unitholders have only such voting rights as are provided in the Trust
Agreement and such rights are more limited than those of stockholders of most
corporations. Unitholder approval is, however, required to terminate the Trust
before January 1, 2003 and to appoint a successor Trustee or Delaware Trustee.
Also, Unitholder approval is required to amend the Trust Agreement (except for
changing the name of the Trust and except to correct or cure ambiguities in the
Trust Agreement which do not adversely affect Unitholders) and to adopt any
amendment to the gas gathering contract relating to production from the
Underlying Properties (the "Gas Gathering Contract") entered into between
Williams Field Services Company (a subsidiary of Williams Field Services Group,
Inc., "WFS") and WFS Gas Resources Company (a subsidiary of Williams, "WFS
Resources")) (as successor in interest to Williams Gas Marketing Company (a
subsidiary of Williams Field Services Group, Inc., "WGM")) or to the gas
purchase contract relating to production from the Underlying Properties (the
"Gas Purchase Contract") entered into between WPC and WFS Resources (as
successor in interest to WGM), if such amendment would materially adversely
affect revenues of the Trust. Unitholders may also remove the Trustee or
Delaware Trustee. Unitholders are not entitled to any rights of appraisal or
similar rights in connection with the termination of the Trust.
The Trust Agreement may be amended, the Delaware Trustee and the Trustee may
be removed and, after December 31, 2002, the Trust may be terminated by a vote
of holders of a majority of the outstanding Units, but no provision of the
Trust Agreement may be amended that would (i) increase the power of the
Delaware Trustee or the Trustee to engage in business or investment activities,
or (ii) alter the rights of the Unitholders as among themselves. Prior to
January 1, 2003, the Trust may be terminated only upon the affirmative vote of
the holders of not less than 75 percent of the outstanding Units. All other
actions may be approved by a majority vote of the Units represented at a
meeting at which a quorum, constituting a majority of the outstanding Units, is
present or represented (except that amendment of required voting percentages
requires approval of at least 80 percent of the outstanding Units). The parties
to the Trust Agreement may, without approval of the Unitholders, from time to
time, supplement or amend the Trust Agreement in order to cure any ambiguity or
to correct or supplement any defective or inconsistent provisions, provided
such supplement or amendment is not adverse to the interest of the Unitholders.
In addition, Williams may direct the Trustee to change the name of the Trust
which change shall not require approval of the Unitholders.
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Meetings of Unitholders may be called by the Trustee or by Unitholders owning
not less than 10 percent in number of the outstanding Units. All such meetings
shall be held in Dallas, Texas, and written notice of every such meeting
setting forth a time and place of the meeting and the matters proposed to be
acted upon shall be given not more than 60 nor less than 20 days before such
meeting. Each Unitholder shall be entitled to one vote for each Unit owned by
such holder.
LIABILITY OF UNITHOLDERS
Consistent with Delaware law, the Trust Agreement provides that the
Unitholders will have the same limitation on personal liability as is accorded
under the laws of such state to stockholders of a corporation for profit. No
assurance can be given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
TRANSFER AGENT
The Trustee has appointed Chemical Shareholder Services Group, Inc. transfer
agent and registrar for the Units (the "Transfer Agent").
FEDERAL INCOME TAXATION
THE TAX CONSEQUENCES TO A UNITHOLDER OF THE OWNERSHIP AND SALE OF UNITS WILL
DEPEND IN PART ON THE UNITHOLDER'S TAX CIRCUMSTANCES. EACH UNITHOLDER SHOULD
THEREFORE CONSULT THE UNITHOLDER'S TAX ADVISOR ABOUT THE FEDERAL, STATE AND
LOCAL TAX CONSEQUENCES TO THE UNITHOLDER OF THE OWNERSHIP OF UNITS.
The sections entitled "Federal Income Tax Consequences" and "Risk Factors--
Tax Considerations" appearing in the Prospectus (the "Public Offering
Prospectus") dated January 13, 1993, which constitutes a part of the
Registration Statement on Form S-3 of Williams (Registration No. 33-53662)
filed in connection with the registration of the Units under the Securities Act
of 1933 for offer and sale in the Public Offering, set forth, respectively, a
summary of Federal income tax matters of general application that addresses all
material tax consequences of the ownership and sale of the Units acquired in
the Public Offering and a discussion of certain risk factors associated with
matters of Federal income taxation as applied to the Trust and such
Unitholders. A copy of such sections of the Public Offering Prospectus is filed
as an exhibit to this Form 10-K.
In connection with the registration of the Units for offer and sale in the
Public Offering, Williams and the underwriters of the Units received certain
opinions of counsel to Williams (upon which the Trustee and the Delaware
Trustee were entitled to rely), including, without limitation, opinions as to
the material Federal income tax consequences of the ownership and sale of the
Units acquired in the Public Offering. The opinions of counsel to Williams as
to such Federal income tax consequences were based on provisions of the
Internal Revenue Code of 1986, as amended (the "IRC"), as of January 21, 1993,
the date of the closing of the Public Offering, existing and proposed
regulations thereunder and administrative rulings and court decisions as of
January 21, 1993, all of which are subject to changes that may or may not be
retroactively applied. Some of the applicable provisions of the IRC have not
been interpreted by the courts or the IRS. In addition, such opinions of
counsel to Williams were based on various representations as to factual matters
made by Williams and WPC in connection with the Public Offering. As is
typically the case, these opinions were limited in their application to certain
investors purchasing Units in the Public Offering and, as a result, provide no
assurance to investors purchasing Units following the Public Offering.
Neither counsel to the Trust, the Trustee nor the Delaware Trustee,
respectively, has rendered any opinions with respect to any tax matters
associated with the Trust or the Units.
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No ruling was requested by Williams, as the sponsor of the Trust, from the
IRS with respect to any matter affecting the Trust or Unitholders. No
assurance can be provided that the opinions of counsel to Williams (which do
not bind the IRS) will not be challenged by the IRS or will be sustained by a
court if so challenged.
SUMMARY OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES
The following summary of certain Federal income tax consequences of
acquiring, owning and disposing of Units is based on the opinions of counsel
to Williams on Federal income tax matters, which are set forth in the Public
Offering Prospectus, and is qualified in its entirety by express reference to
the sections of the Public Offering Prospectus identified in the first
paragraph of this "Federal Income Taxation" section. Although the Trust
believes that the following summary contains a description of all of the
material matters discussed in the opinions referenced above, the summary is
not exhaustive and many other provisions of the Federal tax laws may affect
individual Unitholders. Furthermore, the summary does not purport to be
complete or to address the tax issues potentially affecting Unitholders
acquiring Units other than by purchase through the Public Offering. Each
Unitholder should consult the Unitholder's tax advisor with respect to the
effects of the Unitholder's ownership of Units on the Unitholder's personal
tax situation.
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Classification and Taxation of the The Trust will be treated as a grantor trust and not
Trust.............................. as an association taxable as a corporation. As a
grantor trust, the Trust will not be subject to
Federal income tax. There can be no assurance that
the IRS will not challenge this treatment. The tax
treatment of the Trust and Unitholders could be
materially different if the IRS were to
successfully challenge this treatment.
Taxation of Unitholders............. Each Unitholder will be taxed directly on his
proportionate rata share of income, deductions and
credits of the Trust attributable to the Royalty
Interests consistent with such Unitholder's taxable
year and method of accounting, and without regard
to the taxable year or method of accounting
employed by the Trust.
Income and Deductions............... The income of the Trust consists primarily of a
specified share of the proceeds from the sale of
coal seam gas produced from the Underlying
Properties. During 1995, the Trust earned interest
income on funds held for distribution and made
adjustments to the cash reserve maintained for the
payment of contingent or future obligations of the
Trust. The deductions of the Trust consist of
severance taxes and administrative expenses. In
addition, each Unitholder is entitled to depletion
deductions. See "Unitholder's Depletion Allowance"
below.
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Limits on Deductions and Credits.... Generally, a taxpayer is entitled to claim
deductions and tax credits generated by an
investment only if the investment has economic
substance. The application of this principle in the
context of the production and sale of
nonconventional fuels (like coal seam gas) which
generate the Section 29 tax credit is uncertain
because such application has not been addressed
either by a court or the IRS. An investment has
economic substance if the investor can demonstrate
that there is a reasonable possibility of deriving
an economic profit from the investment in excess of
a de minimis amount, apart from tax benefits. In
many cases, economic profit has been computed by
comparing the taxpayer's total cash investment to
the total cash reasonably expected to be received
by the taxpayer as a result of the investment. At
the time of the Public Offering, Williams, after
consultation with its counsel, expressed its belief
only in connection with the Public Offering that
the purchaser of a Unit in the Public Offering, who
did not borrow funds in order to purchase his Unit,
had a reasonable possibility of deriving an
economic profit in excess of a de minimis amount
apart from tax benefits associated with ownership
of the Unit. No assurance is given either by the
Trustee or counsel to the Trustee to a purchaser of
Units in or following the Public Offering as to
whether (and to what extent) such purchaser will be
entitled to claim deductions and the Section 29 tax
credit generated with respect to such Units.
Section 29 Tax Credits.............. Unitholders will be entitled, provided certain
requirements are met, to claim tax credits pursuant
to Section 29 of the IRC with respect to sales of
coal seam gas production attributable to the NPI,
the gross income from which is included in their
taxable income. The Section 29 tax credit provides
to a taxpayer a dollar-for-dollar reduction in his
regular Federal income tax liability, and,
therefore, generally provides to him a greater
benefit than a deduction which merely reduces the
amount of his taxable income. The Section 29 tax
credit applies to coal seam gas produced and sold
prior to January 1, 2003 from qualifying wells. For
a Unitholder who owned the same Units of record on
all four quarterly record dates during 1995, the
available Section 29 tax credit is approximately
$2.600718 per Unit, based on the first estimate of
the GNP implicit price deflator published by the
Bureau of Economic Analysis of approximately
$1.0029 per MMBtu.
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The availability of Section 29 tax credits is
dependent upon meeting a number of requirements,
many of which are factual in nature. Williams
represented only in connection with the Public
Offering that those factual requirements were met
and Williams expressed its belief in connection
with the Public Offering that substantially all of
the production attributable to the NPI from the
coal seam gas wells identified in the October 1,
1992 Reserve Report (defined herein) qualified for
Section 29 tax credits. At the time of the Public
Offering, counsel to Williams opined as to those
requirements which are statutory or legal in
nature. If any of the factual requirements are not
met, or the opinion not followed, some or all of
the expected Section 29 tax credits may not be
available.
If any portion of the NPI is treated as a production
payment because the NPI is reduced due to WPC's
retained interest, no Section 29 tax credit will be
available to a Unitholder with respect to
production attributable to that portion. In
addition, if the production units or participating
areas are expanded to include additional production
which does not qualify for the Section 29 tax
credit, the amount of Section 29 tax credits
available to a Unitholder will be reduced even
though his share of production does not diminish.
Neither WPC nor the Trust can control whether a
production unit or participating area is expanded.
No Section 29 tax credits will be available under
current law to a Unitholder with respect to
production attributable to the Infill NPI even if
an Infill Well recovers a portion of the reserves
that prior to the drilling and completion of an
Infill Well were recoverable from a well burdened
by the NPI that qualified for Section 29 tax
credits.
Limits on Unitholder's Use of In any year, a Unitholder is permitted to reduce his
Credits............................. regular Federal income tax liability by the Section
29 tax credits allocated to such Unitholder for
such year on a dollar-for-dollar basis, but only to
the extent such Unitholder's regular tax liability
exceeds his alternative minimum tax liability (with
certain adjustments). Any amount of Section 29 tax
credit in excess of a Unitholder's total regular
Federal income tax liability for a year is
permanently lost. Section 29 tax credits cannot be
used to reduce a Unitholder's liability for any
alternative minimum tax for any taxable year but
can be carried forward to reduce his regular tax
liability in a subsequent year (subject to the
applicable rules governing such carryforward(s)).
</TABLE>
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Quarterly Allocations............... Under the IRC, a Unitholder is entitled to Section
29 tax credits only to the extent that he is an
owner of the economic interest at the time the coal
seam gas is produced. The Trustee allocates the
income received by the Trust for a quarter, and the
Section 29 tax credit allocable to such income, to
Unitholders of record on the quarterly record date
for such quarter. Such an allocation may be
challenged by the IRS, but any challenge is likely
to have a material adverse effect only if
successful and only for Unitholders who do not own
Units for a full quarter for each record date,
particularly Unitholders who acquire Units shortly
before a record date and sell shortly after a
record date.
Unitholder's Depletion Allowance.... Each Unitholder is entitled to amortize the cost of
the Units through cost depletion over the life of
the NPI (or if greater, through percentage
depletion equal to 15 percent of gross income). If
any portion of the NPI is treated as a production
payment or is not treated as an economic interest,
however, a Unitholder will not be entitled to
depletion in respect of such portion.
Non-Passive Activity Income, Credits
and Loss................... The income, credits and expenses of the Trust will
not be taken into account in computing the passive
activity losses and income under Section 469 of the
IRC for a Unitholder who acquires and holds Units
as an investment and did not acquire them in the
ordinary course of a trade or business. Section 29
tax credits generated by an investment in Units,
therefore, can be utilized to offset regular tax
liability on income from any source, whether active
or passive, subject to other limitations discussed
herein or arising from the individual tax
circumstances of each Unitholder. See "Limits on
Unitholder's Use of Credits" above.
Unitholder Reporting Information.... The Trustee furnishes to Unitholders tax information
concerning royalty income, depletion and the
Section 29 tax credits on an annual basis. Year-end
tax information is furnished to Unitholders no
later than March 15 of the following year. See the
second paragraph under "Description of Units--
Periodic Reports to Unitholders."
Tax Shelter Registration............ The Trust is registered as a "tax shelter" and its
tax shelter registration number is 92-364000072.
Issuance of a tax shelter registration number does
not indicate that the investment in Units or the
claimed tax benefits have been reviewed, examined
or approved by the IRS.
</TABLE>
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Substantial Understatement Penalty.. Section 6662 of the IRC imposes a penalty in certain
circumstances for a substantial understatement of
taxes if a taxpayer's tax liability is understated
by more than the greater of (a) 10 percent of the
taxes required to be shown on the return and (b)
$5,000 ($10,000 for most corporations). The penalty
(which is not deductible) is 20 percent of the
understatement.
Except in the case of understatements attributable
to "tax shelter" items, which are subject to
special rules discussed below, an item of
understatement will not give rise to the penalty
if: (i) there is or was "substantial authority" for
the taxpayer's treatment of the item or (ii) all
the facts relevant to the tax treatment of the item
are adequately disclosed on the return or on a
statement attached to the return and there is a
reasonable basis for the tax treatment of such
item. In the case of Units, an individual
Unitholder may make adequate disclosure with
respect to particular tax items if certain
conditions are met. Special rules enacted in
December 1994 could affect the application of these
provisions with regard to a corporation acquiring
Units after December 8, 1994, to the extent such
provisions were found to apply to the ownership of
Units.
In the case of understatements attributable to "tax
shelter" items, the substantial understatement
penalty may be avoided only if the taxpayer
establishes that, in addition to having substantial
authority for his position, he reasonably believed
that the treatment claimed was more likely than not
the proper treatment of the item. A "tax shelter"
item is one that arises from a form of investment
if its principal purpose was the avoidance or
evasion of Federal income tax. Regulations
promulgated by the IRS indicate that an entity or
person has a principal purpose of avoidance or
evasion of Federal income tax if that purpose
"exceeds any other purpose." No assurance is given
either by the Trustee or counsel to the Trustee as
to the possible application of this penalty, in
part because such application depends largely upon
the individual circumstances under which the Units
were acquired. As a result, purchasers of Units in
and after the Public Offering should consult with
their personal tax advisors.
</TABLE>
ERISA CONSIDERATIONS
The section entitled "ERISA Considerations" appearing in the Public Offering
Prospectus sets forth certain information regarding the applicability of the
Employee Retirement Income Security Act of 1974, as amended, and the IRC to
pension, profit-sharing and other employee benefit plans, and is incorporated
herein by reference.
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Due to the complexity of the prohibited transaction rules and the penalties
imposed upon persons involved in prohibited transactions, it is important that
potential Qualified Plan investors consult with their counsel regarding the
consequences under ERISA and the IRC of their acquisition and ownership of
Units.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information
regarding state income taxes and other state tax matters affecting individuals
who are Unitholders. Unitholders are urged to consult their own legal and tax
advisors with respect to these matters.
Unitholders should consider state and local tax consequences of holding
Units. The Trust owns Royalty Interests burdening gas properties located in
New Mexico and Colorado. Both New Mexico and Colorado have income taxes
applicable to individuals. A Unitholder is generally required to file state
income tax returns and/or pay taxes in those states and may be subject to
penalties for failure to comply with such requirements. In addition, these
states may require the Trust to withhold tax from distributions to Unitholders
to the extent such distributions are attributable to income from properties
located in such states.
The Trustee will provide information concerning the Units sufficient to
identify the income from Units that is allocable to each state. Unitholders
should consult their own tax advisors to determine their income tax filing
requirements with respect to their share of income of the Trust allocable to
states imposing an income tax on such income.
The Trust has been structured to cause the Units to be treated for certain
state law purposes essentially the same as other securities, that is, as
interests in intangible personal property rather than as interests in real
property. If the Units are held to be real property or an interest in real
property under the laws of either or both of such states, a Unitholder, even
if not a resident of such state, could be subject to devolution, probate and
administration laws, and inheritance or estate and similar taxes, under the
laws of such state.
REGULATION AND PRICES
REGULATION OF NATURAL GAS
The production, transportation and sale of natural gas from the Underlying
Properties are subject to Federal and state governmental regulation, including
regulation of tariffs charged by pipelines, taxes, the prevention of waste,
the conservation of gas, pollution controls and various other matters. The
United States has governmental power to impose pollution control measures.
Federal Regulation of Gas. The Underlying Properties are subject to the
jurisdiction of the Federal Energy Regulatory Commission ("FERC") and the
Department of Energy ("DOE") with respect to various aspects of gas operations
including marketing and production of gas. As a result of the Natural Gas
Policy Act of 1978 ("NGPA") and the Natural Gas Wellhead Decontrol Act of 1989
("NGWDA"), as of January 1, 1993, the wellhead price for natural gas is no
longer subject to federal regulation. All sales of natural gas produced from
the Underlying Properties are considered under NGPA and NGWDA to be sold at
the wellhead (as opposed to downstream sales or resales) for purposes of
pricing and therefore are not subject to federal regulation.
The transportation of natural gas in interstate commerce is subject to
federal regulation by FERC under the Natural Gas Act ("NGA") and the NGPA.
FERC has initiated a number of regulatory policy initiatives that may affect
the transportation of natural gas from the wellhead to the market and thus
18
<PAGE>
may affect the marketing of natural gas. Such initiatives include regulations
which are intended to further open access to interstate pipelines by requiring
such pipelines to unbundle their transportation services from sales services
and allow customers to choose and pay for only the services they require,
regardless of whether the customer purchases natural gas from such pipelines
or from other suppliers. Although these regulations should generally
facilitate the transportation of natural gas produced from the Underlying
Properties to natural gas markets, the impact of these regulations on
marketing production from the Underlying Properties cannot be predicted at
this time, and such impacts could be significant.
Legislative Proposals. In the past, Congress has been very active in the
area of gas regulation. Legislation enacted in recent years repeals
incremental pricing requirements and gas use restraints previously applicable.
At the present time, it is impossible to predict what proposals, if any, might
actually be enacted by Congress or the various state legislatures and what
effect, if any, such proposals might have on the Underlying Properties and the
Trust.
State Regulation. Many state jurisdictions have at times imposed limitations
on the production of gas by restricting the rate of flow for gas wells below
their actual capacity to produce and by imposing acreage limitations for the
drilling of a well. States may also impose additional regulation of these
matters. Most states regulate the production of gas, including requirements
for obtaining drilling permits, the method of developing new fields,
provisions for the unitization or pooling of gas properties, the spacing,
operation, plugging and abandonment of wells and the prevention of waste of
gas resources. The rate of production may be regulated and the maximum daily
production allowable from gas wells may be established on a market demand or
conservation basis or both.
Several states have in recent years enacted or proposed regulations intended
to revise significantly current systems of prorationing gas production. The
modified rules may decrease the total amount of gas produced in New Mexico or
Colorado, and could result in an increase in market prices for gas. The
foregoing developments have fostered debate regarding the purpose and effect
of the new prorationing rules, with opponents of such rules arguing that the
primary purpose thereof is to increase gas prices by withholding supplies from
the market. The Trustee cannot predict what effect, if any, proration rules
will have on the availability of or prices for the Underlying Properties' gas
supplies.
ENVIRONMENTAL REGULATION
General. Activities on the Underlying Properties are subject to existing
Federal, state and local laws (including case law), rules and regulations
governing health, safety, environmental quality and pollution control. It is
anticipated that, absent the occurrence of an extraordinary circumstance or
event, compliance with existing Federal, state and local laws, rules and
regulations regulating health, safety, the release of materials into the
environment or otherwise relating to the protection of the environment will
not have a material adverse effect upon the Trust or Unitholders. The Trustee
cannot predict what effect additional regulation or legislation, enforcement
policies thereunder, and claims for damages to property, employees, other
persons and the environment resulting from operations on the Underlying
Properties could have on the Trust or Unitholders. However, pursuant to the
terms of the Conveyance, any costs or expenses incurred by WPC in connection
with environmental liabilities arising out of or relating to activities
occurring on, in or in connection with, or conditions existing on or under,
the Underlying Properties before October 1, 1992, will be borne by WPC and not
the Trust and will not be deducted in calculating NPI Net Proceeds or Infill
Net Proceeds. Any environmental costs or expenses that are attributable to
WPC's working interest share of the WI Properties that do not fall within the
preceding sentence will be paid by WPC but will be deducted in calculating NPI
Net Proceeds or Infill Net Proceeds, as the case may be, and will, therefore,
reduce amounts payable to the Trust. Environmental costs or expenses that are
attributable to the Farmout Properties that arise after October 1, 1992 could
reduce the revenue paid to WPC and, therefore, the amount of NPI Net Proceeds.
19
<PAGE>
Solid and Hazardous Waste. The Underlying Properties are carved out of WPC's
interests in certain properties that have produced gas from other formations
for many years. WPC has acted as operator for only a small number of the coal
seam gas wells, and for a relatively short period of time. Williams and WPC
have advised the Trustee that to their knowledge, although WPC and the other
operators have utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other solid or hazardous wastes may
have been disposed or released on or under the Underlying Properties by the
current or previous operators. Federal, state and local laws applicable to
gas-related wastes and properties have become increasingly more stringent.
Under these laws, WPC or an operator of the Underlying Properties could be
required to remove or remediate previously disposed wastes or property
contamination (including groundwater contamination) or to perform remedial
plugging operations to prevent future contamination.
The operations of the Underlying Properties may generate wastes that are
subject to the Federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The Environmental Protection Agency (the "EPA") has
limited the disposal options for certain hazardous wastes and may adopt more
stringent disposal standards for nonhazardous wastes.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes
liability, regardless of fault or the legality of the original conduct, on
certain classes of persons that contributed to the release of a "hazardous
substance" into the environment. These persons include the current or previous
owner and the current or previous operator of a site and companies that
disposed or arranged for the disposal of, the hazardous substance found at a
site. CERCLA also authorizes the EPA and, in some cases, private parties to
take actions in response to threats to the public health or the environment
and to seek recovery from such responsible classes of persons of the costs of
such action. In the course of their operations, the operators of the
Underlying Properties have generated and will generate wastes that may fall
within CERCLA's definition of "hazardous substances." WPC or an operator of
the Underlying Properties may be responsible under CERCLA for all or part of
the costs to clean up sites at which such substances have been disposed.
Air Emissions. The operations of the Underlying Properties are subject to
Federal, state and local regulations concerning the control of emissions from
sources of air contaminants. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Regulatory agencies could require the operators to forego or modify
construction or operation of certain air emission sources.
OSHA/Right-to-know. The operations of the Underlying Properties are subject
to the requirements of the Federal Occupational Safety and Health Act ("OSHA")
and comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act and similar state statutes require that
information be organized and maintained about hazardous materials used or
produced in the operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.
COMPETITION, MARKETS AND PRICES
The revenues of the Trust and the amount of cash distributions to
Unitholders depend upon, among other things, the effect of competition and
other factors in the market for natural gas. The gas industry is highly
competitive in all of its phases. WPC encounters competition from major oil
and gas companies, independent oil and gas concerns, and individual producers
and operators. Many of these competitors have greater financial and other
resources than WPC. Competition is also presented by alternative fuel sources,
including heating oil and other fossil fuels.
20
<PAGE>
Demand for natural gas has decreased in recent years in response to economic
factors, conservation, lower prices for alternative energy sources,
unseasonably warm weather, and other factors. Decreased demand has resulted in
curtailments of natural gas production. No assurances can be made that such
curtailments will not continue. In addition, excess natural gas production
capacity in the United States has generally resulted in increased competitive
pressure and significantly lower natural gas prices. The effect of any excess
production capacity which exists in the future cannot be predicted with
certainty; however, any such excess capacity may have a material adverse effect
on distributions from the Trust through its impact on prices and volumes. See
"Item 2--The Royalty Interests--Historical Gas Sales Prices and Production."
Demand for natural gas production has historically been seasonal in nature
and prices for gas fluctuate accordingly. Consequently, the amount of cash
distributions by the Trust may vary substantially on a seasonal basis.
Generally, gas production volumes and prices tend to be higher during the first
and fourth quarters of the calendar year. Because of the lag between the
receipt of revenues related to the Underlying Properties and the dates on which
distributions are made to Unitholders, however, any seasonality that affects
production and prices generally should be reflected in distributions that are
made to Unitholders in later periods. See "--Description of Units--
Distributions and Income Computations."
Prices for natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust, Williams and WPC.
These factors include political conditions in the Middle East, the price and
quantity of imported oil and gas, the level of consumer product demand, the
severity of weather conditions, government regulations, the price and
availability of alternative fuels and overall economic conditions. In view of
the many uncertainties affecting the supply and demand for natural gas and
natural gas prices, the Trust and Williams are unable to make reliable
predictions of future gas prices, production, or demand or the overall effect
they will have on the Trust.
ITEM 2. PROPERTIES.
THE ROYALTY INTERESTS
The Royalty Interests conveyed to the Trust consist of net profits interests
in the Underlying Properties. The Royalty Interests were conveyed to the Trust
by means of a single instrument of conveyance. The Conveyance was recorded in
the appropriate real property records in each county in New Mexico and Colorado
where the Underlying Properties are located so as to give notice of the Royalty
Interests to creditors and transferees, who would take an interest in the
Underlying Properties subject to the Royalty Interests. The Conveyance was
intended to convey the Royalty Interests as real property interests under
applicable state law.
Williams, through WPC, owns the Underlying Properties subject to and burdened
by the Royalty Interests conveyed to the Trust pursuant to the Conveyance. WPC
receives all payments relating to the Underlying Properties and is required,
pursuant to the Conveyance, to pay to the Trust the portion thereof
attributable to the Royalty Interests. Under the Conveyance, the amounts
payable with respect to the Royalty Interests are computed with respect to each
calendar quarter ending prior to termination of the Trust, and such amounts are
to be paid to the Trust not later than the last day of the calendar month next
following the end of each calendar quarter. The amount paid to the Trust does
not include interest on any amounts payable with respect to the Royalty
Interests which are held by WPC prior to payment to the Trust. WPC is entitled
to retain any amounts attributable to the Underlying Properties which are not
required to be paid to the Trust with respect to the Royalty Interests.
21
<PAGE>
The following description contains a summary of the material terms of the
Conveyance and is subject to and qualified by the more detailed provisions of
the Conveyance, a copy of which is filed as an exhibit to this Form 10-K.
THE UNDERLYING PROPERTIES
The Royalty Interests were conveyed by WPC to the Trust from its net revenue
interest (working interest less lease burdens) in the WI Properties and its
net profits interest in the Farmout Properties. Substantially all of the
production from the Underlying Properties is from the Fruitland coal formation
in the San Juan Basin. The San Juan Basin (the "Basin"), one of the largest
gas producing basins in the United States, encompasses approximately 12,000
square miles in northwest New Mexico and southwest Colorado, just east of the
common corner of the states of Utah, Arizona, New Mexico and Colorado known as
the Four Corners. It covers parts of La Plata and Archuleta counties in
Colorado, as well as parts of San Juan, Rio Arriba, McKinley and Sandoval
counties in New Mexico. The Basin has been an active area for coal seam gas
development with the Fruitland coal formation.
Williams acquired the Underlying Properties in 1983 through the acquisition
of Northwest Pipeline Corporation ("Northwest"), and such Underlying
Properties were transferred to WPC on December 31, 1990. Northwest originally
owned working interests which were burdened by overriding royalty interests in
the Underlying Properties. The overriding royalty interests resulted in
excessive burdens and Northwest negotiated settlements with the owners of the
overriding royalty interests. Pursuant to one of these settlements, Northwest
and Amoco Production Company ("Amoco") entered into a joint venture under
which Northwest agreed to assign to Amoco certain oil and gas properties in
two exploratory areas, one of which (the PLA-9 properties) comprises the
Farmout Properties. In consideration for such assignment, Northwest received
an overriding royalty interest in the Farmout Properties. Northwest's rights
under the joint venture agreement were subsequently assigned to WPC, which
elected, effective as of October 1, 1992, to convert the overriding royalty
interest in the Farmout Properties to a 35 percent net profits interest.
Development of the Fruitland coal formation acreage has resulted in the
drilling of 504 gross coal seam gas wells in the Underlying Properties, 21 of
which are in the Farmout Properties. WPC owns mineral rights in the Fruitland
coal formation under 214 oil and gas leases. Under the terms of these leases,
WPC has the right to extract oil and gas from the lease properties. WPC holds
either a record title interest, operating right interest or net profits
interest in the leases. Record title and operating right interests are
commonly referred to as working interests. The Underlying Properties
constitute substantially all of WPC's proved reserves in the Fruitland coal
formation. WPC does not operate any of the coal seam gas wells on the
Underlying Properties.
Unitized Areas. Approximately 90 percent of the Fruitland coal formation
proved developed coal seam gas wells on the WI Properties are located within
the boundaries of New Mexico Federal Units. Pursuant to the Federal Mineral
Leasing Act of 1920, as amended, and applicable state regulations, owners of
oil and gas leases in New Mexico created large unitized areas consisting of
several contiguous sections for the orderly development and conservation of
oil and gas reserves. The WI Properties participate in production from the 13
unitized areas in New Mexico referred to in the following table (the "Federal
Units"). Operation and development of the Federal Units is governed by unit
agreements and unit operating agreements (collectively, the "Unit Agreement").
Under the Unit Agreement and applicable government regulations, the Federal
Unit operators request regulatory approval from the New Mexico Commission of
Public Lands, the New Mexico Oil Conservation Commission and the Bureau of
Land Management to establish or expand participating areas which produce oil
and gas in paying quantities from designated formations. The interests of
participants in a participating area are based on the surface acreage included
in the participating area. Under the terms of the Unit Agreements, the
operators, selected by a vote of the respective working interest owners,
perform all operating functions.
22
<PAGE>
In all of the Federal Units, participating areas have been formed for the
Fruitland coal formation. After the wells capable of producing gas in paying
quantities from the Fruitland coal formation are drilled on the undeveloped
drill blocks included within a Federal Unit, such wells are added to the
participating area if approved in accordance with the appropriate Unit
Agreement. A delay of at least 18-36 months is usually incurred after a well is
completed and producing before it is added to a participating area. As
participating areas are created and expanded, such modification (which will be
effective retroactively to the date production commenced from the wells causing
such expansion) results in a participant owning undivided interests in all of
the producing wells within the participating area. Therefore, WPC's working
interest and net revenue interest in the wells in a Federal Unit or
participating area may be modified retroactively, which could affect
significantly the amount of NPI Net Proceeds with respect to production from
October 1, 1992. An expansion of several participating areas resulted in
increased revenues to the Trust in 1995. If any well(s) that produced or may
have produced marketable quantities of coal seam gas prior to 1980 is included
in or added to a participating area in which the WI Properties participate, the
Conveyance provides that such well(s) will be treated as, and the Trust will
own, a separate net profits interest in such well(s) (the "Pre-80 Production
NPI"). The net proceeds for such Pre-80 Production NPI would be calculated in a
manner similar to the calculation of Infill Net Proceeds, and the Trust's share
of such net proceeds will be 81 percent, subject to possible decrease upon the
same terms as the NPI. If a participating area expansion includes production
from wells that do not qualify for Section 29 tax credits, the tax credit
available to Unitholders in respect of production attributable to the NPI from
such Federal Unit could be reduced. See "Item 1--Federal Income Taxation."
The following table reflects certain information from the Reserve Report as
of December 31, 1995 prepared by Miller and Lents, Ltd. dated March 8, 1996
(the "December 31, 1995 Reserve Report") regarding the Federal Units in which
the WI Properties participate. At December 31, 1995, the WI Properties covered
521 gross (70 net) coal seam gas wells with working interests ranging from.059
percent to 100 percent, with an average working interest of approximately 13.5
percent. The Royalty Interests participate in each Federal Unit and
participating area in which the WI Properties participate based on the acreage
containing wells with proved reserves on December 31, 1995.
<TABLE>
<CAPTION>
UNDERLYING PROPERTIES
-------------------------
ESTIMATED
DISCOUNTED
FUTURE NET
NET PROVED REVENUES
RESERVES (DISCOUNTED
FEDERAL UNIT FEDERAL UNIT OPERATOR (BCF) AT 10%)
------------ --------------------- ---------- --------------
(IN THOUSANDS)
<S> <C> <C> <C>
San Juan 30-5 Phillips Petroleum Company 35.4 $14,992
San Juan 29-6 Phillips Petroleum Company 29.6 12,175
San Juan 32-8 Phillips Petroleum Company 27.1 11,284
San Juan 30-6 Meridian Oil Inc. 23.0 10,182
San Juan 31-6 Phillips Petroleum Company 12.8 5,540
San Juan 29-7 Meridian Oil Inc. 9.6 4,172
San Juan 32-7 Phillips Petroleum Company 6.4 2,590
San Juan 32-9 Meridian Oil Inc. 3.7 1,806
Northeast Blanco Blackwood & Nichols Co., Ltd. 3.2 1,407
San Juan 29-5 Phillips Petroleum Company 1.5 739
Huerfano Meridian Oil Inc. 0.8 365
San Juan 28-6 Meridian Oil Inc. 0.3 152
San Juan 28-5 Meridian Oil Inc. -- 13
</TABLE>
Meridian Oil Inc. is a subsidiary of Burlington Resources Inc. and Blackwood
& Nichols Co., Ltd. is a subsidiary of Devon Energy Corporation.
23
<PAGE>
Well Count and Acreage Summary. The following table shows as of December 31,
1993, 1994 and 1995, the gross and net wells and acreage by proved producing
and nonproducing categories for the WI Properties.
<TABLE>
<CAPTION>
NUMBER OF
WELLS ACRES
--------- --------------
GROSS NET GROSS NET
----- --- ------- ------
DECEMBER 31,
- ------------
<S> <C> <C> <C> <C>
1993
Producing............................................ 477 65 150,988 20,681
Nonproducing......................................... 2 0 400 72
--- --- ------- ------
Total.............................................. 479 65 151,388 20,753
=== === ======= ======
1994
Producing............................................ 488 65 150,988 20,681
Nonproducing......................................... 0 0 0 0
--- --- ------- ------
Total.............................................. 488 65 150,988 20,681
=== === ======= ======
1995
Producing............................................ 521 70 150,988 20,681
Nonproducing......................................... 0 0 0 0
--- --- ------- ------
Total.............................................. 521 70 150,988 20,681
=== === ======= ======
</TABLE>
Of the total gross wells described above, 496 gross wells are located in
unitized areas. In addition to the above, the Farmout Properties have 21 gross
wells.
Properties Outside Unitized Areas. The WI Properties also include interests
held by WPC in 25 proved developed Fruitland formation coal seam gas wells
held in areas outside of Federal Units that are not reflected in the foregoing
table. As of December 31, 1995, WPC's working interest and net revenue
interests in these wells averaged 10.3 percent and 8.5 percent, respectively.
The Farmout Properties consist of a 35 percent net profits interest on a
property farmed out to Amoco in La Plata County, Colorado. Such properties are
not within any Federal Unit boundary. The Farmout Properties are owned, and
most of the wells thereon are operated, by Amoco. Neither Williams, WPC, the
Delaware Trustee, the Trustee nor the Unitholders are able to influence or
control the operation or future development of the Farmout Properties. WPC has
advised the Trustee that it believes that a majority of the production from
the Farmout Properties is sold by Amoco under short-term marketing
arrangements at spot market prices and qualifies for the Section 29 tax
credit. No assurance can be given, however, that Amoco will not in the future
subject production from the Farmout Properties to long-term sales contracts at
non-market responsive prices. A portion of the production from the Farmout
Properties is gathered by WFS pursuant to a gathering contract at rates and
subject to other terms that were negotiated on an arms-length basis. As of
December 31, 1995, 21 gross wells had been drilled on the Farmout Properties.
For a further description of the Farmout Properties, see "--The NPI."
THE NPI
The NPI generally entitles the Trust to receive 81 percent of the NPI Net
Proceeds, subject to possible decrease as described under "--NPI Percentage
Changes." NPI Net Proceeds consists generally of the aggregate proceeds
attributable to (i) WPC's net revenue interest based on the sale at the
Wellhead of gas produced from the WI Properties and (ii) the revenue stream
received by WPC from its 35 percent net profits interest in the Farmout
Properties, less (a) WPC's working interest share of property and production
taxes on the WI Properties; (b) WPC's working interest share of actual
24
<PAGE>
operating costs on the WI Properties to the extent in excess of those agreed
to be paid by WPC as described herein; (c) WPC's working interest share of
capital costs on the WI Properties to the extent in excess of those agreed to
be paid by WPC as described herein; and (d) interest on the unrecovered
portion, if any, of the foregoing costs at Citibank's Base Rate.
Most of the wells reflected in the December 31, 1995 Reserve Report were
drilled prior to 1994. Significant additional capital expenditures were not
incurred during the early years of the production lives of such wells, and it
is not anticipated that further significant capital expenditures will be
incurred. Consequently, the December 31, 1995 Reserve Report was prepared on
the basis that there will be no capital expenditures borne by the Royalty
Interests. Nevertheless, the operators and working interest owners of the
wells could elect at any time to implement measures to increase the producible
reserves. These measures, if implemented, could involve additional compression
or enhanced or secondary recovery operations requiring substantial capital
expenditures which would be proportionately borne by the Royalty Interests.
Exhibit B to the Conveyance reflects estimated annual operating expenses for
wells on the WI Properties. No operating expenses in respect of the WI
Properties will be deducted in calculating NPI Net Proceeds except when the
actual cumulative operating expenses attributable to WPC's working interests
in the WI Properties exceed the estimated cumulative operating expenses
reflected in Exhibit B to the Conveyance as of the close of a calendar quarter
(less the estimated operating costs in such Exhibit that are allocable to two
wells that were repurchased effective as of January 1, 1994 by WPC as a
purchase price adjustment or to any wells that are reconveyed to WPC as
uneconomic). The amount by which such actual cumulative operating expenses
exceed estimated cumulative operating expenses reflected in such Exhibit will
be deducted in calculating NPI Net Proceeds and, therefore, will reduce the
amounts payable to the Trust.
If, during any period, costs and expenses deductible in calculating the NPI
Net Proceeds exceed gross proceeds, neither the Trust nor Unitholders will be
liable for such excess, but the Trust will receive no payments for
distribution to Unitholders with respect to the NPI until future gross
proceeds exceed future costs and expenses plus the cumulative excess of such
costs and expenses plus interest thereon at Citibank's Base Rate. However, if
the excess costs are the result of capital costs incurred for enhanced
recovery or similar operations on the WI Properties, the Trust will receive no
less than 20 percent of the NPI Net Proceeds (calculated before such capital
costs are deducted) until such excess costs plus interest thereon at
Citibank's Base Rate are recovered by WPC unless such capital costs are
$3,000,000 or more, in which event the Trust will only receive payments equal
to the administrative costs of the Trust until such unrecovered costs plus
interest thereon at Citibank's Base Rate are less than $3,000,000.
The calculation of NPI Net Proceeds includes amounts received by WPC in
respect of its 35 percent net profits interest in the Farmout Properties.
WPC's net profits interest in the Farmout Properties is calculated on a total
operations basis and is defined as lease revenues less burdens, operating
expenses (including overhead as defined in the applicable operating agreement)
and all taxes related to the value of reserves, production, property and
equipment (e.g., severance and ad valorem taxes).
WPC has advised the Trustee that the majority of the coal seam gas from the
Farmout Properties is sold by Amoco under short-term marketing arrangements at
spot market prices and the remainder is marketed by the other operators of the
wells in the Farmout Properties. Neither the Gas Purchase Contract nor the Gas
Gathering Contract covers the volumes produced from the Farmout Properties.
RESERVE REPORT
The following table summarizes net proved reserves estimated as of December
31, 1995, and certain related information for the Royalty Interests and
Underlying Properties from the December 31, 1995 Reserve Report prepared by
Miller and Lents, Ltd., independent petroleum engineers.
25
<PAGE>
Summaries of the December 31, 1995 Reserve Report, the December 31, 1994
Reserve Report, the December 31, 1993 Reserve Report and the December 31, 1992
Reserve Report are filed as exhibits to this Form 10-K and incorporated herein
by reference. See Note 9 of the Notes to Financial Statements incorporated by
reference in Item 8 hereof for additional information regarding the net proved
reserves of the Trust.
A net profits interest does not entitle the Trust to a specific quantity of
gas but to a portion of the net proceeds derived therefrom. Ordinarily and in
the case of the Farmout Properties, proved reserves attributable to a net
profits interest are calculated by deducting an amount of gas sufficient, if
sold at the prices used in preparing the reserve estimates for such net
profits interest, to pay the future estimated costs and expenses deducted in
the calculation of the net proceeds of such interest. Because WPC has agreed
to pay certain operating and capital costs with respect to the WI Properties,
no amount of gas in respect of such costs has been deducted from the amount of
reserves attributable to the WI Properties in determining the amount of
reserves attributable to the Royalty Interests. Accordingly, the reserves
presented for the Royalty Interests reflect quantities of gas that are free of
future costs and expenses (other than production, severance and ad valorem
taxes in respect of the WI Properties) if the price and cost assumptions set
forth in the December 31, 1995 Reserve Report occur. The December 31, 1995
Reserve Report was prepared in accordance with criteria established by the
Commission and, accordingly, is based upon a constant delivered Blanco Hub
Spot Price for gas for December 1995, of $1.34 per MMBtu. The December 31,
1995 Reserve Report is also based on the percentage share of NPI Net Proceeds
payable to the Trust remaining at 81 percent.
<TABLE>
<CAPTION>
ROYALTY UNDERLYING
INTERESTS PROPERTIES
--------- ----------
<S> <C> <C>
Net Proved Gas Reserves (Bcf)(a)(b).................... 162.8 201.0
Estimated Future Net Revenues (in millions)(c)......... $122.9 $136.1
Discounted Estimated Future Net Revenues (in
millions)(c)........................................... $ 79.8 $ 90.9
</TABLE>
- --------
(a) Although the prices utilized in preparing the estimates in this table are
in accordance with criteria established by the Commission, such prices
were influenced by seasonal demand for natural gas and other factors and
may not be the most representative prices for estimating future net
revenues or related reserve data.
(b) The gas reserves were estimated by Miller and Lents, Ltd. by applying
decline curve analyses utilizing type curves for the various areas in the
Basin. The bases for the consideration of type curves are the production
histories, the water and gas production rates and the initial reservoir
pressures of the wells in the separate areas.
(c) Estimated future net revenues are defined as the total revenues
attributable to the Underlying Properties and Royalty Interests less
royalties, severance and ad valorem taxes, operating costs and future
capital expenditures in excess of estimated amounts to be paid by WPC.
Overhead costs (beyond the standard overhead charges for the nonoperated
properties) have not been included, nor have the effects of depreciation,
depletion and Federal income tax. Estimated future net revenues and
discounted estimated future net revenues are not intended and should not
be interpreted as representing the fair market value for the estimated
reserves.
Based upon the production estimates used in the December 31, 1995 Reserve
Report for the January 1, 1996 through December 31, 2002 period, and assuming
constant future Section 29 tax credits at the estimated 1996 rate of $1.028
per MMBtu, the estimated total future tax credits available from the
production and sale of the net proved reserves from the Royalty Interests
would be approximately $112.0 million, having a discounted present value
(assuming a 10 percent discount rate) of approximately $86.0 million.
26
<PAGE>
There are many uncertainties inherent in estimating quantities and values of
proved reserves and in projecting future rates of production and the timing of
development expenditures. The reserve data set forth herein, although prepared
by independent petroleum engineers in a manner customary in the industry, are
estimates only, and actual quantities and values of natural gas are likely to
differ from the estimated amounts set forth herein. In addition, the reserve
estimates for the Royalty Interests will be affected by future changes in
sales prices for natural gas produced and costs that are deducted in
calculating NPI Net Proceeds and Infill Net Proceeds. Further, the discounted
present values shown herein were prepared using guidelines established by the
Commission for disclosure of reserves and should not be considered
representative of the market value of such reserves or the Units. A market
value determination would include many additional factors.
Information concerning historical changes in net proved reserves
attributable to the Underlying Properties, and the calculation of the
standardized measure of discounted future net revenues related thereto, are
contained in Note 5 (Supplemental Oil and Gas Reserve Information (Unaudited))
to the Statement of Revenues and Direct Operating Expenses for the Underlying
Properties contained in the Trust's annual report to Unitholders for the year
ended December 31, 1995. Williams has not filed reserve estimates covering the
Underlying Properties with any Federal authority or agency other than the
Commission.
HISTORICAL GAS SALES PRICES AND PRODUCTION
The following table sets forth the actual net production volumes from the WI
Properties, weighted average lifting costs and information regarding
historical gas sales prices for each of the years ended December 31, 1993,
1994 and 1995:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1993 1994 1995
------- ------- -------
<S> <C> <C> <C>
Production from the WI Properties (MMcf)............ 19,839 20,528 29,050
Weighted average lifting costs (dollars per Mcf).... $ 0.08 $ 0.09 $ 0.07
Weighted average sales price of gas produced from
the WI
Properties (dollars per Mcf)....................... $ 1.14 $ 1.11 $ 1.10
Average Blanco Hub Spot Price (dollars per MMBtu)... $ 1.89 $ 1.63 $ 1.18
</TABLE>
The published Blanco Hub Spot Price for December 1995 was $1.34 per MMBtu.
Information regarding average wellhead sales prices for production from the
Farmout Properties is not available to WPC, although WPC has advised the
Trustee that it believes production from such properties is currently sold by
Amoco under short-term marketing arrangements at spot market prices.
PURCHASE PRICE ADJUSTMENTS
For a description of a potential purchase price adjustment provision, see
"Title to Properties--Southern Ute Litigation."
NPI PERCENTAGE CHANGES
Possible Reduction. If there has been production since October 1, 1992 of
approximately 178.5 Bcf of gas in respect of the Underlying Properties, the
percentage of NPI Net Proceeds payable in respect of the NPI will be reduced
with respect to any additional production from the Underlying Properties if
the internal rate of return of the "Aftertax Cash Flow per Unit" (as defined
below) exceeds certain specified levels. For purposes hereof, "Aftertax Cash
Flow per Unit" is equal to the sum of the following amounts that a
hypothetical purchaser of a Unit in the Public Offering would have received or
been allocated if such Unit were held through the date of such determination:
(a) total cash distributions per Unit plus (b) total tax credits available per
Unit under Section 29 of the IRC less (c)
27
<PAGE>
the net taxes payable per Unit (assuming a Federal income tax rate of 31
percent, which at the time of the formation of the Trust was the highest
Federal income tax rate applicable to individuals). Internal rate of return
("IRR") is the annual discount rate (compounded quarterly) that equates the
present value of the Aftertax Cash Flow per Unit to the initial price to the
public of the Units in the Public Offering (which was $20.00 per Unit). Set
forth below is a table that reflects the IRR and the corresponding percentage
of NPI Net Proceeds represented by the NPI and the retained interest of WPC in
the NPI Net Proceeds:
<TABLE>
<CAPTION>
NPI WPC'S RETAINED
PERCENTAGE OF PERCENTAGE OF
NPI NET NPI NET
PROCEEDS PROCEEDS
------------- --------------
<S> <C> <C>
Internal Rate of Return:
Less than 12%................................ 81% 19%
12% to 14%................................... 60 40
More than 14%................................ 40 60
</TABLE>
To the extent that WPC pays to the Trust, as a purchase price adjustment, any
amounts in connection with the litigation described under "--Title to
Properties--Southern Ute Litigation," the Underlying Properties reserve
threshold specified above (approximately 178.5 Bcf) will be reduced by the
reserves estimated in the October 1, 1992 Reserve Report and attributable to
the Underlying Properties burdened by Royalty Interests in respect of which
such payments are made.
Through December 31, 1995, cumulative production since October 1, 1992 was
94.8 Bcf. The IRR for this period was approximately 20.44 percent based on the
assumptions referred to above.
GAS PURCHASE CONTRACT
In accordance with a Confirmation Agreement dated as of May 1, 1995 by and
among WPC, Williams and the Trust (the "Confirmation Agreement"), effective May
1, 1995, WGM assigned to WFS Resources all of its right, title, interest,
duties and obligations under the Gas Purchase Contract, and WFS Resources
assumed all of WGM's right, title, interest, duties and obligations thereunder.
In connection with the Confirmation Agreement, the Trustee received an opinion
of counsel to Williams that the Confirmation Agreement need not be submitted
for approval by vote of the Unitholders.
A copy of the Confirmation Agreement is filed as an exhibit to this Form 10-
K. The following summary of the material provisions of the Confirmation
Agreement is qualified in its entirety by reference to the terms of such
agreement as set forth in such exhibit.
Under the terms of the Gas Purchase Contract, WFS Resources purchases the
natural gas produced by WPC from the WI Properties (except for certain small
volumes) at the Wellhead. The Gas Purchase Contract commenced October 1, 1992
and expires on the termination of the Trust. For the five-year period ending
December 31, 1997 (the "Primary Term"), the monthly price to be paid by WFS
Resources for natural gas purchased pursuant to the Gas Purchase Contract shall
be (a) the $1.70 Minimum Purchase Price, less (b) any costs paid by WFS
Resources to gather, treat and process the gas and deliver it to specified
delivery points and plus (c) under certain circumstances, additional amounts
determined as described below:
(i) If the Index Price in any month during the Primary Term is greater
than $1.94 per MMBtu, then WFS Resources will pay WPC an amount for gas
purchased equal to $1.94 per MMBtu, less the costs paid by WFS Resources to
gather and process such gas and deliver it to specified delivery points,
plus 50 percent of the excess of the Index Price over $1.94 per MMBtu (the
"Price Differential"), provided WFS Resources has no accrued Price Credits
(defined below) in the Price Credit Account (defined below). If WFS
Resources has accrued Price Credits in the Price Credit
28
<PAGE>
Account, then WFS Resources will be entitled to reduce the amount in excess
of the Minimum Purchase Price (before deducting gathering and processing
costs and costs to deliver the gas to specified delivery points) that
otherwise would be payable by any accrued and unrecouped Price Credits in
the Price Credit Account, and WFS Resources will not be obligated to pay
WPC any amounts in excess of the Minimum Purchase Price until such time as
all accrued Price Credits have been recouped and a zero balance exists in
the Price Credit Account.
(ii) If the Index Price in any month during the Primary Term is greater
than the Minimum Purchase Price but less than or equal to $1.94 per MMBtu,
then WFS Resources will pay WPC an amount for each MMBtu purchased equal to
the Index Price less the costs paid by WFS Resources to gather and process
such gas and deliver it to specified delivery points, provided WFS
Resources has no accrued Price Credits in the Price Credit Account. If WFS
Resources has accrued and unrecouped Price Credits in the Price Credit
Account, then WFS Resources will be entitled to reduce the amount in excess
of the Minimum Purchase Price (before deducting gathering and processing
costs and costs to deliver the gas to specified delivery points) that
otherwise would be payable by any accrued and unrecouped Price Credits in
the Price Credit Account, and WFS Resources will not be obligated to pay
WPC any amounts in excess of the Minimum Purchase Price until such time as
all accrued Price Credits have been recouped and a zero balance exists in
the Price Credit Account.
(iii) If the Index Price in any month during the Primary Term (or
thereafter as long as WFS Resources elects to continue paying the Minimum
Purchase Price) is less than the Minimum Purchase Price, then WFS Resources
will pay for each MMBtu of gas purchased the Minimum Purchase Price less
the costs paid by WFS Resources to gather and process such gas and deliver
it to specified delivery points, and if such month commences on or after
January 1, 1994, WFS Resources will receive a credit (the "Price Credit")
from WPC for each MMBtu of natural gas so purchased by WFS Resources equal
to the difference between the Minimum Purchase Price and the Index Price.
WPC is required to establish and maintain an account (the "Price Credit
Account") containing the accrued and unrecouped amount of such Price
Credits. No Price Credits were accrued in respect of production purchased
by WFS Resources prior to January 1, 1994.
The Index Price was below the Minimum Purchase Price in each month during
1995 and has been below the Minimum Purchase Price in each month since April
1994. WPC estimates that, as of December 31, 1995, WFS Resources had aggregate
Price Credits in the Price Credit Account of approximately $19.6 million of
which the Trust's 81 percent interest was approximately $15.9 million. The
Index Price was also below the Minimum Purchase Price in January and February
1996.
This entitlement to recoup the Price Credits means that if and when the Index
Price rises above the Minimum Purchase Price, future royalty income paid to the
Trust would be reduced until such time as such Price Credits have been fully
recouped. Corresponding cash distributions to Unitholders would also be
reduced.
After the Primary Term, WFS Resources will have an annual option (which
option can be exercised only once during the term of the Gas Purchase Contract)
to discontinue paying the Minimum Purchase Price by giving notice of its
election to pay solely the Index Price (less the costs paid by WFS Resources to
gather, treat and process such gas and deliver it to specified delivery
points). If WFS Resources so elects to discontinue paying the Minimum Purchase
Price, WFS Resources will no longer be entitled to retain the Price
Differential when the Index Price exceeds $1.94 per MMBtu and any accrued and
unrecouped Price Credits will be extinguished. Since there is no published
price in the Basin for wellhead deliveries, the wellhead price in the Gas
Purchase Contract is determined by utilizing a published price which is
inclusive of gathering, treating and processing costs. As used herein, "Index
Price" means 97 percent of the Blanco Hub Spot Price. The Blanco Hub Spot Price
is a posted index price per MMBtu (dry basis) published bi-monthly in Inside
FERC's Gas
29
<PAGE>
Market Report for "El Paso Natural Gas Company, San Juan." In the event a
Blanco Hub posted index price is at some time in the future reported by Inside
FERC's Gas Market Report, then the Blanco Hub posted index price will be
substituted for the "El Paso/San Juan" posted index price. The Gas Purchase
Contract provides for an alternative indexing mechanism in the event the Inside
FERC's Gas Market Report indexes are modified or discontinued. All prices used
as index prices are delivered prices at the specified point of delivery and
are, therefore, before deducting gathering and/or transportation charges,
taxes, treating costs or other costs payable prior to the delivery points.
During periods when there is a Price Differential, WFS Resources will absorb a
portion of the gathering charges based on a formula specified in the Gas
Purchase Contract.
A small volume of gas produced from the WI Properties (less than 5 percent)
is sold by the operators of certain wells under gas purchase contracts with
other buyers.
The prices paid to WPC pursuant to the Gas Purchase Contract are prices
payable for the value of gas purchased for production at the Wellhead. Title to
the gas purchased pursuant to the Gas Purchase Contract passes to WFS Resources
at the Wellhead. WFS Resources is responsible for gathering, treating,
processing and marketing all gas purchased pursuant to the Gas Purchase
Contract. Approximately 90 percent of the production from the WI Properties is
gathered by WFS on behalf of WFS Resources. The balance of the production is
gathered on behalf of WFS Resources by third parties. See "--Gas Gathering
Contract." The price paid to WPC pursuant to the Gas Purchase Contract is after
deducting the costs incurred by WFS Resources to gather, treat and process such
gas (including costs incurred by WFS Resources under the Gas Gathering
Contract). Payments to WPC for gas purchased pursuant to the Gas Purchase
Contract are made by WFS Resources on or before the last day of the first
calendar month next following the end of each calendar quarter.
NPI Net Proceeds and Infill Net Proceeds are calculated on an entitlements or
entitled volume basis, whereby the aggregate proceeds from the sale of gas
under applicable gas sales contracts (excluding production from the Farmout
Properties) are determined by WPC as if WPC had produced and sold its working
interest share of production from the WI Properties, even if the actual volumes
delivered to and sold by WPC are different than the entitlement volumes. The
effect of such an "entitlements basis" calculation is that NPI Net Proceeds or
Infill Net Proceeds and, therefore, the amount thereof paid to the Trust, may
include amounts in respect of production not taken by WPC because of a so-
called imbalance (that is, where a working interest owner is delivered more or
less than the actual share of production to which it is entitled).
The Gas Purchase Contract may not be amended in a manner that would
materially adversely affect the revenues to the Trust without the approval of
the holders of a majority of the Units present or represented at a meeting of
Unitholders at which a quorum (consisting of a majority of the outstanding
Units) is present or represented. As noted elsewhere herein, the Units held by
Williams immediately after the Public Offering may not be voted on any such
amendment nor will such Units be counted for quorum purposes. A copy of the Gas
Purchase Contract is filed as an exhibit to this Form 10-K. The foregoing
summary of the material provisions of the Gas Purchase Contract is qualified in
its entirety by reference to the terms of such agreement as set forth in such
exhibit.
GAS GATHERING CONTRACT
In accordance with the Confirmation Agreement, effective May 1, 1995, WGM
assigned to WFS Resources all of its right, title, interest, duties and
obligations under the Gas Gathering Contract, and WFS Resources assumed all of
WGM's right, title, interest, duties and obligations thereunder.
The Gas Gathering Contract, which will be in effect until December 31, 2022,
subject to annual extensions thereafter, covers approximately 90 percent of the
production from the WI Properties and commits WFS on behalf of WFS Resources to
gather such production (except production from 19
30
<PAGE>
wells in the San Juan 29-7 unit as described below), at rates starting at $.35
per Mcf (plus a fuel reimbursement estimated to be 6.2 percent to 7.3 percent
of gathered volumes on a Btu equivalent basis, and subject to increase if the
CO content of the gas exceeds 10 percent) and adjusted annually based on
average annual price comparisons determined on the basis of the Blanco Hub Spot
Price, provided that the gathering rate will be no less than $.35 per Mcf
increased or decreased on the basis of an increase or decrease in a published
index measuring the gross domestic product. A significant portion of the gas to
be gathered pursuant to the Gas Gathering Contract must first be gathered from
the wellhead to a Federal Unit central delivery point by Meridian Oil Gathering
Inc. ("Meridian"). WFS Resources has been assigned a one-year gathering
contract (with a monthly evergreen provision) whereby Meridian provides
interruptible gathering service at the price of $.06 per Mcf which escalates
annually at 3 percent, plus actual fuel used (historically averaging
approximately .5 percent). It is anticipated that WFS Resources will be able to
extend the term of this agreement.
The remainder of the production on the WI Properties is not physically
connected to the WFS system and is not covered by the Gas Gathering Contract.
This gas is gathered either by Meridian or El Paso Natural Gas ("El Paso") for
delivery at the Blanco Hub or by Northwest for delivery at the outlet of the
Ignacio Plant in La Plata County, Colorado. WPC has existing long-term
gathering agreements with Northwest and El Paso and short-term gathering
agreements with Meridian with rates and terms generally comparable to the Gas
Gathering Contract.
The Gas Gathering Contract may not be amended in a manner that would
materially adversely affect the revenues to the Trust without the approval of
the holders of a majority of the Units present or represented at a meeting of
Unitholders at which a quorum (consisting of a majority of the outstanding
Units) is present or represented. As noted elsewhere herein, the Units held by
Williams immediately after the Public Offering may not be voted on any such
amendment nor will such Units be counted for quorum purposes.
The Gas Gathering Contract was twice amended each effective as of October 1,
1993 with respect to 19 wells located in the San Juan 29-7 unit. WFS is
obligated to gather production from such wells at a rate of $.36 per Mcf (plus
a fuel reimbursement of 5.5 percent of the Mcfs received at the Wellhead
Receipt Points (as defined)), fixed for a 10 year term. In connection with
these amendments to the Gas Gathering Contract, the Trustee received an opinion
of counsel to Williams that such amendments need not be submitted for approval
by vote of the Unitholders.
A copy of the Gas Gathering Contract is filed as an exhibit to this Form 10-
K. The foregoing summary of the material provisions of the Gas Gathering
Contract is qualified in its entirety by reference to the terms of such
agreement as set forth in such exhibit.
FEDERAL AND INDIAN LANDS
Approximately 80 percent of the Underlying Properties are burdened by royalty
interests held by the Federal government or the Southern Ute Indian Tribe.
Royalty payments due to the U.S. Government for gas produced from Federal and
Indian lands included in the Underlying Properties must be calculated in
conformance with its interpretation of regulations issued by the Minerals
Management Service ("MMS"), a subagency of the U.S. Department of the Interior
which administers and receives revenues from Federal and Indian royalties on
behalf of the U.S. Government and as agent for the Indian tribes. The MMS
regulations cover both valuation standards which establish the basis for
placing a value on production and cost allowances which define those post-
production costs that are deductible by the lessee.
Where gas is sold by a lessee to a marketing affiliate such as WFS Resources,
the MMS regulations essentially ignore the lessee-affiliate transaction and
consider the arm's-length sale by the affiliate as the point of valuation for
royalty purposes. Accordingly, WPC is required to calculate royalty payments
31
<PAGE>
based on the price WFS Resources receives when it markets the gas production
("Resale Price"), notwithstanding the price payable by WFS Resources to WPC
pursuant to the Gas Purchase Contract. With respect to the Farmout Properties,
Amoco pays royalties based on the price it receives for production from such
properties as long as the gas is purchased by nonaffiliates. The NPI Net
Proceeds, a portion of which is payable to the Trust, reflects the deduction of
all royalty and overriding royalty burdens. The ratio of royalties paid on
Federal and Indian lands to the NPI Net Proceeds increases as the Resale Price
exceeds the price under the Gas Purchase Contract.
The MMS regulations permit a lessee to deduct from its gross proceeds its
reasonable actual costs of transportation and processing to transport the gas
from the lease to the point of sale in calculating the market value of its
production. Although WFS Resources deducts the gathering charges paid by it to
WFS, Meridian, El Paso and Northwest in calculating the wellhead price it pays
to WPC, the MMS could disallow the deduction of some portion of the gathering
charges after review of such charges on audit of WPC's royalty as discussed
below. If some portion of the gathering charges is disallowed, the MMS will
likely demand additional royalties plus interest on the amount of the
underpayment.
The Trustee has been advised by WPC that the MMS has from time to time
considered the inclusion of the value of the Section 29 tax credits
attributable to coal seam gas production in the calculation of gross proceeds
for purposes of calculating the royalty that is payable to the MMS. On August
30, 1993, the U.S. Office of the Inspector General (the "OIG") issued an audit
report stating that Section 29 tax credits should be included in the
calculation of gross proceeds and recommending that the MMS pursue collection
of additional royalties with respect to past and future production. On December
8, 1993, however, the Office of the Solicitor of the U.S. Department of the
Interior gave its opinion to the MMS that the report of the OIG was incorrect
and that Section 29 tax credits are not part of gross proceeds for the purpose
of federal royalty calculations. WPC believes that any such inclusion of the
value of Section 29 tax credits for purposes of calculating royalty payments
required to be made on Federal and Indian lands would be inappropriate since
all mineral interest owners, including royalty owners, are entitled to Section
29 tax credits for their proportionate share of qualifying coal seam gas
production. WPC has advised the Trustee that it would vigorously oppose any
attempt by the MMS to require the inclusion of the value of Section 29 tax
credits in the calculation of gross proceeds. However, if regulations providing
for the inclusion of such value were adopted and upheld, royalty payments would
be increased which would decrease NPI Net Proceeds and, therefore, the amounts
payable to the Trust. The reduction in amounts payable to the Trust would cause
a corresponding reduction in associated Section 29 tax credits available to
Unitholders.
The MMS generally audits royalty payments within a six-year period. Although
WPC calculates royalty payments in accordance with its interpretation of the
then applicable MMS regulations, WPC does not know whether the royalty payments
made to the U.S. Government are totally in conformance with MMS standards until
the payments are audited. If an MMS audit, or any other audit by a Federal or
state body, results in additional royalty charges, together with interest,
relating to production from and after October 1, 1992 in respect of the
Underlying Properties, such charges and interest will be deducted in
calculating NPI Net Proceeds for the quarter in which the charges are billed
and in each quarter thereafter until the full amount of the additional royalty
charges and interest have been recovered.
SALE AND ABANDONMENT OF UNDERLYING PROPERTIES
WPC (and any transferees) have the right to abandon any well or working
interest included in the Underlying Properties if, in its opinion, such well or
property ceases to produce or is not capable of producing in commercially
paying quantities. Since WPC does not operate any of the wells on the
Underlying Properties, WPC does not normally control the timing of plugging and
abandoning wells. The Conveyance provides that WPC's working interest share of
the costs of plugging and abandoning uneconomic wells will be deducted in
calculating NPI Net Proceeds.
32
<PAGE>
WPC may sell the Underlying Properties, subject to and burdened by the
Royalty Interests, without the consent of the Unitholders. Under the Trust
Agreement, WPC has certain rights (but not the obligation) to purchase the
Royalty Interests upon termination of the Trust. See "Item 1--Description of
the Trust--Termination and Liquidation of the Trust."
WPC has retained the right to repurchase from the Trust, commencing January
1, 2003, any portion of the NPI conveyed to the Trust if WPC's interest in the
Underlying Properties burdened by such portion of the NPI ceases to produce or
is not capable of producing in commercially paying quantities (ignoring for
purposes of such determination the NPI and the Infill NPI). The purchase price
payable by WPC will be the fair market value at the date of repurchase of the
portion of the NPI or Infill NPI so purchased, as established on the basis of
an appraisal provided by an independent expert.
THE INFILL NPI
The Royalty Interests include the Infill NPI, a net profits interest on any
Infill Wells completed on the WI Properties. No Infill Wells have been drilled
and none will be drilled unless the well spacing limitations for coal seam gas
wells in the Basin are reduced. If such changes occur and Infill Wells are
drilled, the Infill NPI will entitle the Trust to receive 20 percent of the
Infill Net Proceeds. No reserves have been attributed to any Infill Wells in
the December 31, 1995 Reserve Report, the December 31, 1994 Reserve Report, the
December 31, 1993 Reserve Report or the October 1, 1992 Reserve Report.
WILLIAMS' PERFORMANCE ASSURANCES
Pursuant to the Conveyance, Williams has agreed to pay each of the following
to the extent not paid by WPC when due and payable: (i) any purchase price
adjustment which WPC is required under the Conveyance to pay to purchase any
proved developed nonproducing wells which are not completed and producing by
December 31, 1993; (ii) any purchase price adjustment which WPC is required
under the Conveyance to pay in the event the Southern Ute Indian Tribe is
successful in showing that WPC has no right to produce or receive proceeds from
the Fruitland coal formation and any loss, charge or liability which WPC is
required under the Conveyance to pay if the Trust is named as a defendant in
the pending Southern Ute Indian Tribe litigation; (iii) all liabilities and
operating and capital expenses which WPC is required under the Conveyance to
pay as owner of the Underlying Properties, including without limitation, WPC's
obligation to pay operating expenses with respect of the WI Properties up to
the cumulative amounts specified in Exhibit B to the Conveyance and the capital
costs incurred in respect of the WI Properties to the extent specified in the
Conveyance, including amounts which WPC is obligated to pay with respect to
environmental liabilities; (iv) all NPI Net Proceeds, Infill Net Proceeds and
other amounts which WPC is obligated to pay to the Trust under the Conveyance,
including amounts which WPC is obligated to pay with respect to environmental
liability; and (v) any proceeds from a sale of any remaining Royalty Interests
that WPC may elect to purchase upon termination of the Trust ((i) through (v)
collectively, the "WPC Payment Obligations"). Williams has also agreed, to the
extent not paid by WFS Resources when due and payable, to pay all amounts which
WFS Resources is required to pay to WPC in respect of production attributable
to the Royalty Interests pursuant to the terms of the Gas Purchase Contract
between WPC and WFS Resources (the "WFS Resources Payment Obligations"). In the
Confirmation Agreement, Williams expressly confirmed that its agreement to
cause the WFS Resources Payment Obligations to be paid in full when due shall
continue in full force and effect notwithstanding the assignments by WGM of the
Gas Purchase Contract and the Gas Gathering Contract.
In the event and to the extent that WPC does not pay any of the WPC Payment
Obligations in full when due and, in the event and to the extent that WFS
Resources does not pay any of the WFS Resources Payment Obligations in full
when due, the Trustee (but not Unitholders) is entitled, following notice to
Williams and demand for payment by the Trustee and after a 10-day cure period,
33
<PAGE>
to enforce payment by Williams. Williams' assurance obligations terminate upon
the earlier of (i) dissolution of the Trust, (ii) with respect to the WPC
Payment Obligations, upon sale or other transfer by WPC of all or
substantially all of the Underlying Properties, (iii) with respect to the WPC
Payment Obligations, upon one or more sales or other transfers of a majority
or more of Williams' ownership interests in WPC and (iv) with respect to the
WFS Resources Payment Obligations, upon one or more sales or other transfers
of a majority or more of Williams' ownership interests in WFS Resources;
provided that, with respect to (ii), (iii) and (iv) above, only if the
transferee has, at the time of transfer, a rating assigned to outstanding
unsecured long-term debt from Moody's Investor Services of at least Baa3 or
from Standard & Poor's Corporation of at least BBB (or an equivalent rating
from at least one nationally-recognized statistical rating organization), or
such transferee is approved by holders of a majority of outstanding Units, and
in any case, the transferee unconditionally agrees in writing, to assume and
be bound by Williams' remaining assurance obligations.
TITLE TO PROPERTIES
Williams has advised the Trustee that it believes that WPC's title to the
Underlying Properties, and the Trust's title to the Royalty Interests, are
good and defensible in accordance with standards generally accepted in the gas
industry, subject to such exceptions which, in the opinion of Williams, are
not so material as to detract substantially from the use or value of such
Underlying Properties or Royalty Interests. For a description of a lawsuit
challenging WPC's right to produce coal seam gas from certain properties, see
"Southern Ute Litigation" below. As is customary in the gas industry, only a
perfunctory title examination is performed as a lease is acquired, except
leases covering proved reserves. Generally, prior to drilling a well, a more
thorough title examination of the drill site tract is conducted and curative
work is performed with respect to significant title defects, if any, before
proceeding with operations. However, WPC (or its predecessor) has owned the
leases covering the Underlying Properties since 1974, and conventional gas has
been produced from formations other than the Fruitland formation covered by
all of the leases since the 1950s. Under these circumstances, WPC conducted an
internal review of its title records prior to the drilling of the coal seam
gas wells within the 13 Federal Units, but did not conduct title examinations.
In addition to its internal review, WPC, when requested by the operator,
participated in title examinations prior to the drilling of a few coal seam
gas wells located outside the Federal Units.
The Underlying Properties are typically subject, in one degree or another,
to one or more of the following: (i) royalties and other burdens and
obligations, expressed and implied, under gas leases; (ii) overriding
royalties and other burdens created by WPC or its predecessors in title; (iii)
a variety of contractual obligations (including, in some cases, development
obligations) arising under operating agreements, farmout agreements,
production sales contracts and other agreements that may affect the properties
or their titles; (iv) liens that arise in the normal course of operations,
such as those for unpaid taxes, statutory liens securing unpaid suppliers and
contractors and contractual liens under operating agreements; (v) pooling,
unitization and communitization agreements, declarations and orders; and (vi)
easements, restrictions, rights-of-way and other matters that commonly affect
property. To the extent that such burdens and obligations affect WPC's rights
to production and the value of production from the Underlying Properties, they
have been taken into account in calculating the Trust's interests and in
estimating the size and value of the reserves attributable to the Royalty
Interests. Except as noted below, Williams believes that the burdens and
obligations affecting the Underlying Properties and Royalty Interests are
conventional in the industry for similar properties, do not, in the aggregate,
materially interfere with the use of the Underlying Properties and will not
materially and adversely affect the value of the Royalty Interests.
Although the matter is not entirely free from doubt, Williams has advised
the Trustee that it believes (based upon the opinions of local counsel to WPC
with respect to matters of Colorado law and New Mexico law) that the Royalty
Interests should constitute real property interests under applicable state
law. Consistent therewith, the Conveyance states that the Royalty Interests
constitute
34
<PAGE>
real property interests and it was recorded in the appropriate real property
records of Colorado and New Mexico, the states in which the Underlying
Properties are located in accordance with local recordation provisions. If,
during the term of the Trust, WPC becomes involved as a debtor in bankruptcy
proceedings, it is not entirely clear that all of the Royalty Interests would
be treated as real property interests under the laws of Colorado and New
Mexico. If in such a proceeding a determination were made that the Royalty
Interests constitute real property interests, the Royalty Interests should be
unaffected in any material respect by such bankruptcy proceeding. If in such a
proceeding a determination were made that a Royalty Interest constitutes an
executory contract (a term used, but not defined, in the United States
Bankruptcy Code to refer to a contract under which the obligations of both the
debtor and the other party to such contract are so unsatisfied that the
failure of either to complete performance would constitute a material breach
excusing performance by the other) and not a real property interest under
applicable state law, and if such contract were not to be assumed in a
bankruptcy proceeding involving WPC, the Trust would be treated as an
unsecured creditor of WPC with respect to such Royalty Interest in the pending
bankruptcy. Although no assurance is given, Williams has advised the Trustee
that it does not believe that the Royalty Interests should be subject to
rejection in a bankruptcy proceeding as executory contracts.
Southern Ute Litigation. On December 31, 1991, the Southern Ute Indian Tribe
(the "Tribe") filed a lawsuit in the United States District Court for the
District of Colorado (the "Court") against WPC and other major gas producers
in the San Juan Basin area. In its complaint, the Tribe alleges that certain
coal strata and constituents within that strata were reserved by the United
States, then granted to the Tribe for the Tribe's perpetual benefit and
ownership. The Tribe alleges that the current extraction of coal seam gas and
other substances from the coal strata is and has been done without the Tribe's
permission. The Tribe is seeking a declaration that it owns a beneficial
interest in the coal seam gas and other constituents and their extraction
without Tribal consent is an unlawful trespass; and that the United States
Department of the Interior and its officials have breached their fiduciary
duty to the Tribe by failing to protect the Tribe from the unauthorized
extraction of substances found within the coal strata.
The Tribe seeks compensation from the producers and the oil and gas estate
owners (such as WPC or Amoco as owner of the Farmout Properties) for the value
of extracted substances allegedly wrongfully taken from the Tribe. The Tribe
seeks an order transferring to the Tribe ownership of all equipment and
facilities installed by, or on behalf of, those defendants and utilized in the
extraction of coalbed methane and other substances located within the coal
strata. Under certain circumstances, such as the willful disregard of the
Tribe's ownership interests, the Tribe requests that the extraction facilities
be transferred to the Tribe without deducting production revenue or other
compensation to the defendant. Additionally, the Tribe seeks to recover
severance taxes related to the production of the coal seam gas.
The pending litigation involves approximately 1,745 gross acres comprising a
portion of the Farmout Properties. Two Tribe leases covering approximately
3,600 gross acres included in the Farmout Properties are not covered by the
pending litigation, but could be the subject of future litigation.
WPC, together with the other defendants named in the lawsuit, is vigorously
defending the lawsuit. On September 13, 1994, the Court issued a memorandum
opinion and order in the litigation granting the motion for summary judgment
filed by the defendant class on the question of ownership of the coal seam
gas. The Court ruled that the U.S. Congress did not reserve the coal seam gas
in the Coal Lands Acts of 1909 and 1910, and denied the Tribe's claim of
equitable ownership of the coal seam gas. The Tribe has appealed the order to
the U.S. Court of Appeals for the Tenth Circuit. WPC has agreed to indemnify
the Trust from and against any loss, charge or liability as may arise in
respect of the Underlying Properties or the Royalty Interests, in connection
with the defense of such lawsuit and all legal costs the Trust might incur if
the Trust is named as a defendant in such
35
<PAGE>
litigation. WPC's indemnity with respect to the Farmout Properties is limited
to its retained interest share of any settlement costs that may reduce the
revenue stream it receives from its 35 percent net profits interest in the
Farmout Properties. If the Tribe is successful in showing that WPC has no
right to produce or receive proceeds from the Fruitland coal formation, WPC
has agreed to pay to the Trust, in addition to the indemnification described
above, for distribution to then current Unitholders as a return of a portion
of the original purchase price paid for the Units in the Public Offering, an
amount equal to (a) the product of (i) $1.47 per Mcf times (ii) the estimated
reserves in the October 1, 1992 Reserve Report attributable to the interest of
the Trust in the Farmout Properties subject to such dispute, less (b) the
aggregate cash distributions paid by the Trust prior to the date of such
determination and less (c) the tax benefits, if any, available to the
Unitholders and attributable to the portion of the interest of the Trust in
the Farmout Properties so purchased.
Southern Ute Proposed Mineral Assignment Ordinance. As currently proposed,
the 1992 Southern Ute Tribal Proposed Mineral Assignment Ordinance (the
"Proposed Ordinance") could apply to the conveyance to the Trust of the
Farmout Properties involving Tribal mineral interests. Although the Proposed
Ordinance does not specifically reference a net profits interest, it is
possible that the Tribe would consider the conveyance of the NPI to the extent
burdening Tribal mineral interests as being covered by the Proposed Ordinance
and requiring the approval of the Chairman of the Tribe. If the Proposed
Ordinance is applicable, the conveyance of the NPI would not be approved if
the Tribe determined that such creation would not be in the best interests of
the Tribe and, absent such Tribal approval, the NPI would be invalid. In
addition, a knowing violation could result in removal of the offending party
from the reservation and that party's forfeiture of any Tribal mineral
interests located on the reservation. Under the Proposed Ordinance, a mineral
interest owner is limited to seeking declaratory relief in Tribal Court.
Additionally, under the Proposed Ordinance, the Tribe would have a right of
first refusal to acquire the NPI associated with Tribal leases. The Tribe
would have 120 days after the submission of a completed assignment of a Tribal
Mineral Interest Form to exercise the right to acquire said interest for the
same terms and conditions as are disclosed by the filing.
It is unknown if the Proposed Ordinance will be enacted at all, enacted in
its current form or enacted in an altered form. Therefore, the potential
effect of the Proposed Ordinance cannot be assessed at this time.
METHANE CONTAMINATION LITIGATION
In January 1994, an amended class action complaint was filed in State
District Court in La Plata County, Colorado, seeking damages arising out of
alleged methane contamination of water, air and soil resources by the drilling
and production activities of seven operators, including an affiliate of WPC.
This class action complaint was thereafter dismissed, and approximately 40
separate complaints were filed by various plaintiffs in the U.S. District
Court in Colorado containing comparable allegations. The plaintiffs maintain
that drilling in the Fruitland coal formation has caused methane and other
substances to migrate through conventional gas wellbores and natural fractures
and faults to their water sources. The plaintiffs are seeking both
compensatory and punitive damages, injunctive relief, a remediation program
and an air and medical monitoring program.
The wells identified by the plaintiffs in the pending litigation do not
include any wells on the Underlying Properties. However, wells on the
Underlying Properties could be added to the pending litigation or made the
subject of future methane contamination litigation. The seven operators are
vigorously defending the pending litigation.
ITEM 3. LEGAL PROCEEDINGS.
See "Item 2--The Royalty Interests--Title to Properties--Southern Ute
Litigation" for a description of certain litigation to which WPC is a party.
Subject to the preceding sentence, there are no material pending proceedings
to which the Trust is a party or of which any of its property is the subject.
36
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Certain information with respect to the Units of the Trust and the market
therefor is set forth on the inside front cover of the Trust's Annual Report
to Unitholders for the year ended December 31, 1995 under the section entitled
"Units of Beneficial Interest" and is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA.
Selected financial data of the Trust is set forth on the inside front cover
of the Trust's Annual Report to Unitholders for the year ended December 31,
1995 under "Selected Financial Data" and is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The "Trustee's Discussion and Analysis" of financial condition and results
of operations appearing on pages 2 and 3 of the Trust's Annual Report to
Unitholders for the year ended December 31, 1995 is incorporated herein by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The financial statements of the Trust and the notes thereto, together with
the report thereon of Ernst & Young LLP, independent auditors, dated March 22,
1996, appearing on pages 4 through 12 of the Trust's Annual Report to
Unitholders for the year ended December 31, 1995 are incorporated herein by
reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Trust has no directors or executive officers. Each of the Trustee and
the Delaware Trustee is a corporate trustee that may be removed as trustee
under the Trust Agreement, with or without cause, at a meeting duly called and
held by the affirmative vote of Unitholders of not less than a majority of all
the Units then outstanding. Any such removal of the Delaware Trustee shall be
effective only at such time as a successor Delaware Trustee fulfilling the
requirements of Section 3807(a) of the Delaware Code has been appointed and
has accepted such appointment, and any such removal of the Trustee shall be
effective only at such time as a successor Trustee has been appointed and has
accepted such appointment.
ITEM 11. EXECUTIVE COMPENSATION.
The following is a description of certain fees and expenses anticipated to
be paid or borne by the Trust, including fees expected to be paid to Williams,
the Trustee, the Delaware Trustee, the Transfer Agent, or their affiliates.
37
<PAGE>
Ongoing Administrative Expenses. The Trust is responsible for paying all
legal, accounting, engineering and stock exchange fees, printing costs and
other administrative and out-of-pocket expenses incurred by or at the
direction of the Trustee or Delaware Trustee and the out-of-pocket expenses of
the Transfer Agent.
Compensation of the Trustee, Delaware Trustee and Transfer Agent. The Trust
Agreement provides for compensation to the Trustee and the Delaware Trustee
for administrative services, out of the Trust assets. The Trustee is paid a
1995 base amount of $34,608, plus an hourly charge for services in excess of a
combined total of 300 hours annually at the Trustee's then standard rate. The
Delaware Trustee is paid a fixed annual amount which was initially set at
$5,000. The Trustee and the Delaware Trustee received total compensation for
1995 of $35,646 and $5,344, respectively. The base amount of the Trustee's fee
and the amount of the Delaware Trustee's fee for administrative services
escalate at the rate of 3 percent per year. The Trustee and the Delaware
Trustee are each entitled to reimbursement for out-of-pocket expenses. Upon
termination of the Trust, the Trustee will receive, in addition to its out-of-
pocket expenses, a termination fee in the amount of $8,000.
The Transfer Agent receives a transfer agency fee of $5.50 annually per
account (minimum of $15,000 annually), subject to change each December, based
upon the change in the Producers' Price Index as published by the Department
of Labor, Bureau of Labor Statistics, plus $1.00 for each certificate issued
in excess of 10,000 annually. The total fees paid by the Trust to the Transfer
Agent in 1995 was $18,321.
Fees to Williams. Williams will receive, throughout the term of the Trust,
an administrative services fee for accounting, bookkeeping and informational
services relating to the Royalty Interests as described below in "Item 13--
Administrative Services Agreement."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners. The following table
sets forth as of February 14, 1996 information with respect to the only
Unitholder who was known to the Trustee to be a beneficial owner of more than
5 percent of the outstanding Units.
<TABLE>
<CAPTION>
NAME AND ADDRESS NUMBER OF UNITS PERCENT
OF BENEFICIAL OWNER BENEFICIALLY OWNED OF CLASS
------------------- ------------------ --------
<S> <C> <C>
Williams Holdings of Delaware, Inc............... 3,568,791 36.8%
One Williams Center
Tulsa, Oklahoma 74172
</TABLE>
WILLIAMS' OWNERSHIP OF UNITS
Except as noted below, Williams (or its affiliate) has the same voting
rights under the Trust Agreement as other Unitholders. Accordingly, so long as
Williams (or its affiliate) continues to own 36.8 percent of the Units, on any
matters brought to a vote of Unitholders requiring the approval of the holders
of a majority of Units present or represented at a meeting where a majority of
outstanding Units are represented, Williams will likely be able to control the
vote with respect to such matters if not less than 14 percent of additional
Units necessary for quorum purposes are represented at such meeting. With
respect to the vote on any amendment to the Gas Purchase Contract or the Gas
Gathering Contract, the Units held by Williams (or its affiliate) immediately
after the Public Offering may not be voted nor will such Units be counted for
purposes of determining if a quorum is present so long as such Units continue
to be held by Williams (or its affiliate). This voting limitation will not be
applicable to Units Williams (or its affiliate) may acquire, if any, after the
date of the Public Offering.
38
<PAGE>
In addition, as noted below, certain potential conflicts of interest exist
between Williams and its subsidiaries and the interests of the Trust and the
Unitholders (see "Item 13--Potential Conflicts of Interest"). To the extent
that any matters are brought to a vote of Unitholders where the interests of
Williams conflict, or potentially conflict, with the interests of the Trust or
Unitholders, Williams (or its affiliate) can be expected to vote in its own
self-interest and under certain circumstances as noted above, may have
sufficient votes to control the outcome.
(b) Security Ownership of Management. The Trust has no directors or
executive officers. As of March 3, 1996, NationsBank of Texas, N.A., the
Trustee, held an aggregate of 1,000 Units in various fiduciary capacities,
with no investment or voting powers. As of March 15, 1996, Chemical Bank
Delaware, the Delaware Trustee, did not beneficially own any Units.
(c) Changes in Control. Subject to the discussion above in this Item 12
under "Williams' Ownership of Units," the Trustee knows of no arrangements the
operation of which may at a subsequent date result in a change in control of
the Trust.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
ADMINISTRATIVE SERVICES AGREEMENT
Pursuant to the Trust Agreement, Williams and the Trust entered into an
Administrative Services Agreement effective December 1, 1992. A copy of the
Administrative Services Agreement is filed as an exhibit to this Form 10-K.
The Administrative Services Agreement obligates the Trust to pay to Williams
each quarter an administrative services fee for accounting, bookkeeping and
informational services relating to the Royalty Interests. The administrative
services fee is $53,045 per calendar quarter commencing October 1, 1994,
through and including the quarter ended September 30, 1995, and increases 3
percent each October 1. Accordingly, the total of the administrative services
fees paid by the Trust to Williams in 1995 was $213,771.
POTENTIAL CONFLICTS OF INTEREST
The interests of Williams and its subsidiaries and the interests of the
Trust and the Unitholders with respect to the Underlying Properties could at
times be different. As a working interest owner in the WI Properties, WPC
could have interests that conflict with the interests of the Trust and
Unitholders. For example, such conflicts could be due to a number of factors
including, but not limited to, future budgetary considerations and the absence
of any contractual obligation on the part of WPC to spend for development of
the WI Properties, except as noted herein. Such decisions may have the effect
of changing the amount or timing of future distributions to Unitholders. WPC's
interests may also conflict with those of the Trust and Unitholders in
situations involving the sale or abandonment of Underlying Properties. WPC has
the right at any time to sell any of the Underlying Properties subject to the
Royalty Interests and under certain circumstances may abandon any of the WI
Properties. Such sales or abandonment may not be in the best interest of the
Trust. In addition, WFS Resources has the right, exercisable in its sole
discretion, at any time after December 31, 1997 to terminate its Minimum
Purchase Price commitment under the Gas Purchase Contract. Williams' interests
could conflict with those of the Trust and Unitholders to the extent the
interests of WFS Resources, under the Gas Purchase Contract, or WFS and WFS
Resources, under the Gas Gathering Contract, differ from the interests of the
Trust and the Unitholders. Except for amendments to the Gas Gathering Contract
or Gas Purchase Contract that must be approved by the vote of a majority of
the Unitholders present at a meeting at which a quorum is present if such
amendment would materially adversely affect Trust revenues, no mechanism or
procedure has been included to resolve potential conflicts of interest between
the Trust and Williams, WPC or their affiliates.
39
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
1. Financial Statements (incorporated by reference in Item 8. of this report)
<TABLE>
<CAPTION>
PAGE IN 1995
ANNUAL REPORT
TO UNITHOLDERS
(INCORPORATED
BY REFERENCE)
--------------
<S> <C>
Report of Independent Auditors............................... 4
Statements of Assets, Liabilities and Trust Corpus as of
December 31,
1995 and 1994............................................... 5
Statements of Distributable Income for the years ended
December 31, 1995,
1994 and 1993............................................... 5
Statements of Changes in Trust Corpus (Deficit) for the years
ended
December 31, 1995, 1994 and 1993............................ 5
Notes to Financial Statements................................ 6
</TABLE>
2. 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 included in the financial statements and notes thereto.
3. Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <C> <S>
3.1 -- Certificate of Trust of Williams Coal Seam Gas Royalty Trust
(filed as Exhibit 3.1 to the Registrant's Form 10-K for the year
ended December 31, 1992 and incorporated herein by reference).
4.1 -- Trust Agreement of Williams Coal Seam Gas Royalty Trust effective
as of December 1, 1992, by and among Williams Production Company,
The Williams Companies, Inc. and Chemical Bank Delaware and
NationsBank of Texas, N.A., as trustees (filed as Exhibit 4.1 to
the Registrant's Form 10-K for the year ended December 31, 1992
and incorporated herein by reference).
4.2 -- First Amendment to the Trust Agreement of Williams Coal Seam Gas
Royalty Trust effective as of December 15, 1992, by and among
Williams Production Company, The Williams Companies, Inc.,
Chemical Bank Delaware and NationsBank of Texas, N.A. (filed as
Exhibit 4.2 to the Registrant's Form 10-K for the year ended
December 31, 1992 and incorporated herein by reference).
4.3 -- Second Amendment to the Trust Agreement of Williams Coal Seam Gas
Royalty Trust effective as of January 12, 1993, by and among
Williams Production Company, The Williams Companies, Inc.,
Chemical Bank Delaware and NationsBank of Texas, N.A. (filed as
Exhibit 4.3 to the Registrant's Form 10-K for the year ended
December 31, 1992 and incorporated herein by reference).
4.4 -- Net Profits Conveyance effective as of October 1, 1992, by and
among Williams Production Company, The Williams Companies, Inc.,
and NationsBank of Texas, N.A. and Chemical Bank Delaware (filed
as Exhibit 4.4 to the Registrant's Form 10-K for the year ended
December 31, 1992 and incorporated herein by reference).
</TABLE>
40
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<S> <C> <C>
10.1 -- Administrative Services Agreement effective December 1, 1992, by
and between The Williams Companies, Inc. and Williams Coal Seam
Gas Royalty Trust (filed as Exhibit 10.1 to the Registrant's Form
10-K for the year ended December 31, 1992 and incorporated herein
by reference).
10.2 -- Gas Purchase Agreement dated October 1, 1992, by and between
Williams Gas Marketing Company and Williams Production Company
(filed as Exhibit 10.2 to the Registrant's Form 10-K for the year
ended December 31, 1992 and incorporated herein by reference).
10.3 -- First Amendment to the Gas Purchase Agreement effective January
12, 1993, by and between Williams Gas Marketing Company and
Williams Production Company (filed as Exhibit 10.3 to the
Registrant's Form 10-K for the year ended December 31, 1992 and
incorporated herein by reference).
10.4 -- Gas Gathering and Treating Agreement effective October 1, 1992, by
and between Williams Field Services Company and Williams Gas
Marketing Company (filed as Exhibit 10.4 to the Registrant's Form
10-K for the year ended December 31, 1992 and incorporated herein
by reference).
10.5 -- First Amendment to the Gas Gathering and Treating Agreement
effective as of January 12, 1993, by and between Williams Field
Services Company and Williams Gas Marketing Company (filed as
Exhibit 10.5 to the Registrant's Form 10-K for the year ended
December 31, 1992 and incorporated herein by reference).
10.6 -- Amendment #2 to the Gas Gathering and Treating Agreement dated as
of October 1, 1993, by and between Williams Field Services Company
and Williams Gas Marketing Company (filed as Exhibit 10.6 to the
Registrant's Form 10-K for the year ended December 31, 1993 and
incorporated herein by reference).
10.7 -- Amendment #3 to the Gas Gathering and Treating Agreement dated as
of October 1, 1993, by and between Williams Field Services Company
and Williams Gas Marketing Company (filed as Exhibit 10.7 to the
Registrant's Form 10-K for the year ended December 31, 1993 and
incorporated herein by reference).
10.8 -- Confirmation Agreement effective as of May 1, 1995 by and among
Williams Production Company, The Williams Companies, Inc. and
Williams Coal Seam Gas Royalty Trust (filed as Exhibit 10.1 to the
Registrant's Form 10-Q for the quarter ended June 30, 1995 and
incorporated herein by reference).
13.1 -- 1995 Annual Report to Unitholders.
23.1 -- Consent of Miller and Lents, Ltd.
23.2 -- Consent of Ernst & Young LLP.
27.1 -- Financial Data Schedule.
99.1 -- The information under the section captioned "Tax Considerations"
on pages 20-21, and the information under the sections captioned
"Federal Income Tax Consequences" and "ERISA Considerations" on
pages 45-52 of the Prospectus dated January 13, 1993, which
constitutes a part of the Registration Statement on Form S-3 of
The Williams Companies, Inc. (Registration No. 33-53662) (filed as
Exhibit 28.1 to the Registrant's Form 10-K for the year ended
December 31, 1992 and incorporated herein by reference).
</TABLE>
41
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER EXHIBIT
------- -------
<C> <C> <S>
99.2 -- Reserve Report, dated November 21, 1992, on the estimated
reserves, estimated future net revenues and the discounted
estimated future net revenues attributable to the Royalty
Interests and the Underlying Properties as of October 1, 1992,
prepared by Miller and Lents, Ltd., independent petroleum
engineers, included as Exhibit A of the Prospectus dated January
13, 1993, which constitutes a part of the Registration Statement
on Form S-3 of The Williams Companies, Inc. (Registration No. 33-
53662) (filed as Exhibit 28.1 to the Registrant's Form 10-K for
the year ended December 31, 1992 and incorporated herein by
reference).
99.3 -- Reserve Report, dated March 10, 1993, on the estimated reserves,
estimated future net revenues and the discounted estimated future
net revenues attributable to the Royalty Interests and the
Underlying Properties as of December 31, 1992, prepared by Miller
and Lents, Ltd., independent petroleum engineers (filed as Exhibit
28.2 to the Registrant's Form 10-K for the year ended December 31,
1992 and incorporated herein by reference).
99.4 -- Reserve Report, dated February 23, 1994, on the estimated reserves
attributable to the Royalty Interests as of December 31, 1993 (but
using October 1, 1992 Reserve Report pricing), prepared by Miller
and Lents, Ltd., independent petroleum engineers (filed as Exhibit
99.4 to the Registrant's Form 10-K for the year ended December 31,
1993 and incorporated herein by reference).
99.5 -- Reserve Report, dated February 23, 1994, on the estimated
reserves, estimated future net revenues and the discounted
estimated future net revenues attributable to the Royalty
Interests and the Underlying Properties as of December 31, 1993,
prepared by Miller and Lents, Ltd., independent petroleum
engineers (filed as Exhibit 99.5 to the Registrant's Form 10-K for
the year ended December 31, 1993 and incorporated herein by
reference).
99.6 -- Reserve Report, dated February 28, 1995, on the estimated
reserves, estimated future net revenues and the discounted
estimated future net revenues attributable to the Royalty
Interests and the Underlying Properties as of December 31, 1994,
prepared by Miller and Lents, Ltd., independent petroleum
engineers (filed as Exhibit 99.6 to the Registrant's Form 10-K for
the year ended December 31, 1994 and incorporated herein by
reference).
99.7 -- Reserve Report, dated March 8, 1996, on the estimated reserves,
estimated future net revenues and the discounted estimated future
net revenues attributable to the Royalty Interests and the
Underlying Properties as of December 31, 1995, prepared by Miller
and Lents, Ltd., independent petroleum engineers.
</TABLE>
(b) Reports on Form 8-K. No report on Form 8-K was filed by the Registrant
during the last quarter of the period covered by this report.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]
42
<PAGE>
SIGNATURES
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.
WILLIAMS COAL SEAM GAS ROYALTY
TRUST
By: NATIONSBANK OF TEXAS, N.A.,
Trustee
/s/ RON E. HOOPER
By: _______________________________
RON E. HOOPER
Vice President and
Administrator
Date: March 29, 1996
(The Registrant has no directors or executive officers.)
43
<PAGE>
WILLIAMS COAL SEAM GAS ROYALTY TRUST
1995 Annual Report and Form 10-K
THE TRUST
Williams Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware
business trust pursuant to the Trust Agreement of Williams Coal Seam Gas Royalty
Trust entered into effective as of December 1, 1992 by and among Williams
Production Company ("WPC"), as trustor, The Williams Companies, Inc., the parent
company of WPC, and NationsBank of Texas, N.A. (the "Trustee") and Chemical Bank
Delaware, as trustees. The Trust owns net profits interests (the "Royalty
Interests") in proved coal seam gas properties located in the San Juan Basin of
New Mexico and Colorado (the "Underlying Properties"). These Royalty Interests
are the only assets of the Trust, other than cash and temporary investments
being held for the payment of expenses and liabilities and for distribution to
Unitholders.
The Trust makes quarterly cash distributions to Unitholders. The record date for
the quarterly cash distributions is the 45th day following the end of the
calendar quarter or the next business day. The quarterly cash distribution is
payable within 60 days after the end of the calendar quarter. Generally, the
quarterly distribution amount will be determined and announced by the Trustee in
the first week of February, May, August or November each year. Set forth below
are the scheduled record dates and approximate distribution payment dates for
each quarter of 1996 production attributable to the Trust.
<TABLE>
<CAPTION>
1996 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Record Dates May 15 August 14 November 14 February 14
Distribution
Payment Dates
(approximate) May 30 August 29 November 29 March 1
</TABLE>
UNITS OF BENEFICIAL INTEREST
The units of beneficial interest ("Units") in the Trust are listed and traded on
the New York Stock Exchange under the symbol "WTU." The following table sets
forth, for the periods indicated, the high and low sales prices per Unit and the
amount of quarterly cash distributions per Unit made by the Trust.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Sales Price
--------------------- Distributions
1995 High Low per Unit
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
First Quarter.................... $19-3/4 $16-1/8 $0.590825
Second Quarter................... $18-3/4 $16-7/8 $0.672417
Third Quarter.................... $19-1/2 $17-1/4 $0.733171
Fourth Quarter................... $20-7/8 $19-1/8 $0.695386
1994
- --------------------------------------------------------------------------------
First Quarter.................... $27-1/4 $22 $0.5847864
Second Quarter................... $26-1/8 $22-3/4 $0.5781011
Third Quarter.................... $24-3/8 $20-1/2 $0.6125781
Fourth Quarter................... $21-7/8 $15-3/4 $0.4610492
- --------------------------------------------------------------------------------
</TABLE>
At March 15, 1996, there were 9,700,000 Units outstanding and approximately
898 Unitholders of record.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Years Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Royalty Income..................... $26,524,115 $22,292,821 $ 19,449,173
Distributable Income............... $26,053,210 $21,753,943 $ 18,890,743
Distributable Income per Unit...... $ 2.69 $ 2.24 $ 1.95
Distributions per Unit............. $ 2.69 $ 2.24 $ 1.93
Total Assets at Year End........... $82,752,593 $99,948,540 $117,580,814
Trust Corpus at Year End........... $82,695,754 $99,881,511 $117,515,559
- --------------------------------------------------------------------------------
</TABLE>
1
<PAGE>
TO UNITHOLDERS:
We are pleased to present the 1995 Annual Report to Unitholders of Williams Coal
Seam Gas Royalty Trust (the "Trust"). The report includes a copy of the Trust's
annual report on Form 10-K for the year ended December 31, 1995. The Form 10-K
contains important information concerning the creation and administration of the
Trust, and the assets of the Trust, including coal seam gas reserves
attributable to the net profits interests owned by the Trust estimated as of
December 31, 1995.
The Trust was formed as a Delaware business trust under the Delaware Business
Trust Act pursuant to the Trust Agreement of Williams Coal Seam Gas Royalty
Trust (as amended, the "Trust Agreement") entered into effective as of December
1, 1992 by and among Williams Production Company ("WPC"), as trustor, The
Williams Companies, Inc. ("Williams"), the parent company of WPC, and
NationsBank of Texas, N.A. (the "Trustee") and Chemical Bank Delaware, as
trustees. The Trust was formed to acquire and hold certain net profits interests
(the "Royalty Interests") in proved coal seam gas properties located in the San
Juan Basin of New Mexico and Colorado. These Royalty Interests are the only
assets of the Trust, other than cash and temporary investments being held for
the payment of expenses and liabilities and for distribution to Unitholders.
On January 21, 1993, all 9,700,000 authorized units of beneficial interest in
the Trust ("Units") were issued to WPC upon the conveyance by WPC to the Trust
of the Royalty Interests. On that date, WPC transferred all 9,700,000 Units to
its parent, Williams, by dividend. Williams then sold an aggregate of 6,131,209
Units to the public in an underwritten public offering. During the second
quarter of 1995 Williams transferred its remaining Units to Williams Holding of
Delaware, Inc., a separate holding and finance company for Williams' non-
regulated business.
Under the Trust Agreement, the Trustee has the function of collecting proceeds
attributable to the Royalty Interests and making quarterly cash distributions to
Unitholders after deducting administrative expenses and any amounts necessary
for cash reserves.
Distributable income for the year ended December 31, 1995 was $26,053,210 or
$2.69 per Unit as compared to $21,753,943 or $2.24 per Unit for 1994. Royalty
income for the year totaled $26,524,115 as compared to $22,292,821 for 1994. The
Trust also earned interest of $90,476 from temporary investments of royalty
income prior to quarterly distribution dates as compared to $57,391 for 1994.
General and administrative expenses for the year were $561,381 as compared to
$596,269 for 1994.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the Royalty Interests consist of
producing properties. Accordingly, the proved reserves attributable to WPC's
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust.
Production from the Royalty Interests held by the Trust which is sold during the
year qualifies for the Federal income tax credit for producing nonconventional
fuels under Section 29 of the Internal Revenue Code. As a result, for a
Unitholder who owned the same Units of record on all four quarterly record dates
during 1995, the available Section 29 tax credit was approximately $2.600718 per
Unit, based on the first estimate of the GNP implicit price deflator published
by the Bureau of Economic Analysis. In contrast, a Unitholder who owned the same
Units of record on all four quarterly record dates during 1994, the available
Section 29 tax credit was $2.029127 per Unit.
Tax information for calendar year 1995 permitting each Unitholder to make all
calculations reasonably necessary for tax purposes was distributed by the
Trustee to Unitholders prior to March 15, 1996, in accordance with the Trust
Agreement. Such income tax information will be provided annually to Unitholders
by the Trustee not later than March 15th of each year.
WILLIAMS COAL SEAM GAS ROYALTY TRUST
By: NationsBank of Texas, N.A., Trustee
By: /sig/ Ron E. Hooper
Vice President
March 24, 1996
2
<PAGE>
TRUSTEE'S DISCUSSION AND ANALYSIS
The Trust makes quarterly cash distributions to Unitholders. The only assets of
the Trust, other than cash and cash equivalents being held for the payment of
expenses and liabilities and for distribution to Unitholders, are the Royalty
Interests. The Royalty Interests owned by the Trust burden the Underlying
Properties, which are owned by WPC and not the Trust.
Distributable income of the Trust consists of the excess of royalty income plus
interest income over the general and administrative expenses of the Trust. Upon
receipt by the Trust, royalty income is invested in short-term investments in
accordance with the Trust Agreement until its subsequent distribution to
Unitholders.
The amount of distributable income of the Trust for any calendar year may differ
from the amount of cash available for distribution to the Unitholders in such
year due to differences in the treatment of the expenses of the Trust in the
determination of those amounts. The financial statements of the Trust are
prepared on a modified cash basis pursuant to which the expenses of the Trust
are recognized when incurred. Consequently, the reported distributable income of
the Trust for any year is determined by deducting from the income received by
the Trust the amount of expenses incurred by the Trust during such year. The
amount of cash available for distribution to Unitholders, however, is determined
in accordance with the provisions of the Trust Agreement and reflects the
deduction from the income actually received by the Trust of the amount of
expenses actually paid by the Trust and adjustment for changes in reserves for
unpaid liabilities. See Note 5 to the financial statements of the Trust
appearing elsewhere in this Annual Report to Unitholders for additional
information regarding the determination of the amount of cash available for
distribution to Unitholders.
For 1995 royalty income received by the Trust amounted to $26,524,115 as
compared to $22,292,821 and $19,449,173 for 1994 and 1993, respectively. The
increases in royalty income are primarily due to higher production from the
Underlying Properties. Production related to the royalty income received by the
Trust in 1995 was 31,536,784 MMBtu as compared to 24,309,530 MMBtu and
19,755,103 MMBtu in 1994 and 1993, respectively. The higher volumes in 1995 and
1994 were due to higher production along with adjustments for unit expansion
than in 1993. Interest income for 1995 was $90,476 as compared to $57,391 and
$40,690 for 1994 and 1993, respectively, representing higher investment income
on higher royalty income.
Distributable income for 1995 was $26,053,210 or $2.69 per Unit compared to
$21,753,943 or $2.24 per Unit for 1994 and $18,890,743 or $1.95 per Unit for
1993. This increase resulted from higher production from the Underlying
Properties.
The upward revisions in the reserve values in 1995 and 1994 are due to stronger
production from the properties in both 1995 and 1994, and expansion of several
federal units in 1995. Reserve values in 1995 and 1994 were also impacted by
declines in natural gas prices used to value the reserves. The year end prices
required to be utilized in such valuations were $.81/mcf, $1.06/mcf and
$1.58/mcf at December 31, 1995, 1994 and 1993, respectively.
Production from the Royalty Interests held by the Trust which is sold during the
year qualifies for the Federal income tax credit for producing nonconventional
fuels under Section 29 of the Internal Revenue Code. As a result, for a
Unitholder who owned the same Units of record on all four quarterly record dates
during 1995, the available Section 29 tax credit is approximately $2.600718 per
Unit, based on the first estimate of the GNP implicit price deflator published
by the Bureau of Economic Analysis. In contrast, for a Unitholder who owned the
same Units of record on all four quarterly record dates during 1994, the
available Section 29 tax credit was $2.029127 per Unit. See Note 3 to the
financial statements of the Trust appearing elsewhere in this Annual Report to
Unitholders for additional information regarding the Section 29 tax credit.
Because the Trust incurs administrative expenses throughout a quarter but
receives its royalty income only once in a quarter, the Trustee established in
the first quarter of 1993 a cash reserve for the payment of expenses and
liabilities of the Trust. The Trustee thereafter has adjusted the amount of such
reserve in certain quarters as required for the payment of the Trust's expenses
and liabilities, in accordance with the provisions of the Trust Agreement. The
Trustee anticipates that it will maintain for the foreseeable future a cash
reserve which will fluctuate as expenses are paid and royalty income is
received.
Royalty income to the Trust is attributable to the sale of depleting assets. All
of the Underlying Properties burdened by the Royalty Interests consist of
producing properties. Accordingly, the proved reserves attributable to WPC's
interest in the Underlying Properties are expected to decline substantially
during the term of the Trust and a portion of each cash distribution made by the
Trust will, therefore, be analogous to a return of capital. Accordingly, cash
yields attributable to the Units are expected to decline over the term of the
Trust.
3
<PAGE>
Royalty income received by the Trust in a given calendar year will generally
reflect the sum of (i) proceeds from the sale of gas produced from the WI
Properties (as defined in Note 1 to the financial statements of the Trust
appearing elsewhere in this Annual Report to Unitholders ("Note 1")) during the
first three quarters of that year and the fourth quarter of the preceding
calendar year, plus (ii) cash received by WPC with respect to the Farmout
Properties (as defined in Note 1) during the first three quarters of that year
(or in the month immediately following the third quarter, if received by WPC in
sufficient time to be paid to the Trust) and the fourth quarter of the preceding
calendar year.
Accordingly, the royalty income included in distributable income for the years
ended December 31, 1995, 1994 and 1993, was based on production volumes and
natural gas prices for the twelve months ended in September 30, 1995, 1994 and
1993, respectively, as shown in the table below. The production volumes included
in the table are for production attributable to the Underlying Properties, and
not production attributable to the Royalty Interests owned by the Trust, and are
net of the amount of production attributable to WPC's royalty obligations to
third parties, which is determined by contractual arrangement with such parties.
<TABLE>
<CAPTION>
Twelve Months Ended
September 30,
- --------------------------------------------------------------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Production, Net (MMBtu)/(1)/
WI Properties........................ 24,556,075 18,177,999 15,801,117
Farmout Properties/(2)/.............. 6,980,709 6,131,531 3,953,986
Average Blanco Hub Spot Price
($/MMBtu)............................ $ 1.22 $ 1.75 $ 1.96
Average Net Wellhead Price
WI Properties ($/MMBtu).............. $ 1.20 $ 1.23 $ 1.34
- --------------------------------------------------------------------------------
</TABLE>
/(1) /Million British Thermal Units.
/(2) /Includes previously reported estimated amounts for certain months.
Production from the WI Properties is generally sold pursuant to a gas purchase
contract between WPC and WFS Gas Resources Company ("WFSGR") (as successor to
Williams Gas Marketing Company). The gas purchase contract provides certain
protections for WFSGR in the form of price credits (for production purchased by
WFSGR on or after January 1, 1994) and for Unitholders when the applicable
Blanco Hub Spot Price falls below $1.75 per MMBtu and provides certain benefits
for WFSGR when the Blanco Hub Spot Price exceeds $2.00 per MMBtu. The gas
purchase contract also provides that the price paid for gas by WFSGR is
reduced by the amount of gathering, processing and certain other costs paid by
WFSGR. For more detailed information regarding the terms and conditions of the
gas purchase contract, see "Item 2. Properties - Gas Purchase Contract" in the
Form 10-K of the Trust appearing elsewhere in this Annual Report to Unitholders.
The Blanco Hub Spot Price was below $1.75 per MMBtu in each month during the
year of 1995. However, pursuant to the terms of the gas purchase contract, WFSGR
continued to purchase gas produced from the WI Properties at the $1.70 minimum
purchase price, less certain gathering, processing and delivery costs paid by
WFSGR, established by the gas purchase contract; and WFSGR received a price
credit from WPC for each MMBtu of natural gas so purchased by WFSGR equal to the
difference between the $1.70 minimum purchase price and the applicable index
price (which price is equal to 97 percent of the applicable Blanco Hub Spot
Price). WPC estimates that, as of December 31, 1995, WFSGR had aggregate price
credits of approximately $19.6 million of which the Trust's 81 percent interest
was approximately $15.9 million. The Blanco Hub Spot Price was also below $1.75
per MMBtu in January and February 1996.
The entitlement of WFSGR to recoup the price credits means that if and when the
applicable Blanco Hub Spot Price rises above $1.75 per MMBtu, future royalty
income paid to the Trust would be reduced until such time as such price credits
have been fully recouped. Corresponding cash distributions to Unitholders would
also be reduced.
The information in this Annual Report to Unitholders concerning production and
prices relating to the Underlying Properties is based on information prepared
and furnished by WPC to the Trustee. The Trustee has no control over and no
responsibility relating to the operation of the Underlying Properties.
FINANCIAL STATEMENTS
Audited Statements of Assets, Liabilities and Trust Corpus of the Trust as of
December 31, 1995 and 1994, and the related Statements of Distributable Income
and Changes in Trust Corpus for the three years ended December 31, 1995, are
included in this Annual Report to Unitholders immediately following the Report
of Independent Auditors below.
The Royalty Interests owned by the Trust burden the Underlying Properties, which
are owned by WPC and not the Trust. For the information of Unitholders, an
audited Statement of Revenues and Direct Operating Expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1995 has
been prepared and furnished by WPC to the Trustee for inclusion in this Annual
Report to Unitholders. This financial statement of WPC appears immediately
preceding the Form 10-K of the Trust.
4
<PAGE>
REPORT OF INDEPENDENT AUDITORS
THE TRUSTEES
WILLIAMS COAL SEAM GAS ROYALTY TRUST
We have audited the accompanying statements of assets, liabilities and trust
corpus of Williams Coal Seam Gas Royalty Trust as of December 31, 1995 and 1994,
and the related statements of distributable income and changes in trust corpus
(deficit) for each of the three years in the period ended December 31, 1995.
These financial statements are the responsibility of the Trust's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 also includes assessing the accounting principles used
and significant estimates made by management, 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 2 to the financial statements, these financial statements
have been prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than 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 Williams Coal
Seam Gas Royalty Trust at December 31, 1995 and 1994, and its distributable
income and its changes in trust corpus (deficit) for each of the three years in
the period ended December 31, 1995, on the basis of accounting described in Note
2.
/sig/ ERNST & YOUNG LLP
Tulsa, Oklahoma
March 22, 1996
5
<PAGE>
FINANCIAL STATEMENTS
WILLIAMS COAL SEAM GAS ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
December 31 1995 1994
<S> <C> <C>
ASSETS
Current assets - cash and cash equivalents.......... $ 29,134 $ 96,582
Royalty interests in oil and gas properties
(less accumulated amortization of
$55,843,204 and $38,714,705 at
December 31, 1995 and 1994, respectively)
(Note 2)........................................... 82,723,459 99,851,958
- --------------------------------------------------------------------------------
Total.............................................. $82,752,593 $99,948,540
- --------------------------------------------------------------------------------
LIABILITIES AND TRUST CORPUS
Current liabilities:
Payable to The Williams Companies, Inc. (Note 4).... $ 53,045 $ 53,045
Other accounts payable.............................. 3,794 13,984
- --------------------------------------------------------------------------------
Current liabilities................................ 56,839 67,029
Trust corpus (9,700,000 units of beneficial interest
authorized and outstanding)(Note 2)................ 82,695,754 99,881,511
- --------------------------------------------------------------------------------
Total.............................................. $82,752,593 $99,948,540
- --------------------------------------------------------------------------------
</TABLE>
STATEMENTS OF DISTRIBUTABLE INCOME
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Year Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Royalty income................... $26,524,115 $ 22,292,821 $ 19,449,173
Interest income.................. 90,476 57,391 40,690
- --------------------------------------------------------------------------------
Total........................... 26,614,591 22,350,212 19,489,863
General and administrative
expenses (Note 4)................ 561,381 596,269 599,120
- --------------------------------------------------------------------------------
Distributable income............. $26,053,210 $ 21,753,943 $ 18,890,743
- --------------------------------------------------------------------------------
Distributable income per unit
(9,700,000 units)(Note 2)........ $ 2.69 $ 2.24 $ 1.95
- --------------------------------------------------------------------------------
Distributions per unit (Note 5).. $ 2.69 $ 2.24 $ 1.93
</TABLE>
STATEMENTS OF CHANGES IN TRUST CORPUS (DEFICIT)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Year Ended December 31 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Trust corpus (deficit),
beginning of year............... $99,881,511 $117,515,559 $ (178,188)
Conveyance of royalty interests
by Williams Production Company.. --- --- 135,686,000
Sale of additional units by
The Williams Companies, Inc..... --- --- 2,899,559
Amortization of
royalty interests............... (17,128,499) (17,693,798) (21,020,907)
Distributable income............. 26,053,210 21,753,943 18,890,743
Distributions to Unitholders
(Note 5).................. (26,110,468) (21,694,193) (18,761,648)
- --------------------------------------------------------------------------------
Trust corpus, end of year....... $82,695,754 $ 99,881,511 $117,515,559
- --------------------------------------------------------------------------------
See accompanying notes.
</TABLE>
6
<PAGE>
NOTES TO FINANCIAL STATEMENTS
1. TRUST ORGANIZATION AND PROVISIONS
Williams Coal Seam Gas Royalty Trust (the "Trust") was formed as a Delaware
business trust pursuant to the terms of the Trust Agreement of Williams Coal
Seam Gas Royalty Trust (as amended, the "Trust Agreement") entered into
effective as of December 1, 1992 by and among Williams Production Company, a
Delaware corporation ("WPC"), as trustor, The Williams Companies,Inc., a
Delaware corporation ("Williams"), and NationsBank of Texas, N.A., a national
banking association (the "Trustee"), and Chemical Bank Delaware, a Delaware
banking corporation (the "Delaware Trustee"), as trustees. The trustees are
independent financial institutions.
The Trust was formed to acquire and hold certain net profits interests (the
"Royalty Interests") in proved natural gas properties located in the San Juan
Basin of New Mexico and Colorado (the "Underlying Properties") owned by WPC. The
Trust was initially created effective as of December 1, 1992 with a $100
contribution by WPC. On January 21, 1993, the Royalty Interests were conveyed to
the Trust by WPC pursuant to the Net Profits Conveyance (the "Conveyance") dated
effective as of October 1, 1992 by and among WPC, Williams, the Trustee and the
Delaware Trustee, in consideration for all the 9,700,000 authorized units of
beneficial interest in the Trust ("Units"). WPC transferred its Units by
dividend to its parent, Williams, which sold an aggregate of 5,980,000 Units to
the public through various underwriters in January and February 1993 (the
"Public Offering"). During the second quarter of 1995 Williams transferred its
remaining Units to Williams Holdings of Delaware, Inc. ("WHD"), a separate
holding company for Williams' non-regulated businesses. Substantially all of the
production attributable to the Underlying Properties is from the Fruitland coal
formation and constitutes "coal seam" gas that entitles the owners of such
production, provided certain requirements are met, to tax credits for Federal
income tax purposes pursuant to Section 29 of the Internal Revenue Code of 1986,
as amended.
The Trustee has the power to collect and distribute the proceeds received by the
Trust and to pay Trust liabilities and expenses. The Delaware Trustee has only
such powers as are set forth in the Trust Agreement and is not empowered to
otherwise manage or take part in the business of the Trust. The Royalty
Interests are passive in nature and neither the Delaware Trustee nor the Trustee
has any control over or any responsibility relating to the operation of the
Underlying Properties.
The Trust will terminate no later than December 31, 2012, subject to earlier
termination under certain circumstances described in the Trust Agreement (the
"Termination Date"). Cancellation of the Trust will occur on or following the
Termination Date when all Trust assets have been sold and the net proceeds
thereof distributed to Unitholders.
7
<PAGE>
The only assets of the Trust, other than cash and cash equivalents being held
for the payment of expenses and liabilities and for distribution to Unitholders,
are the Royalty Interests. The Royalty Interests consist primarily of a net
profits interest (the"NPI") in the Underlying Properties. The NPI generally
entitles the Trust to receive 81 percent of the NPI Net Proceeds, as defined
below, attributable to (i) gas produced and sold from WPC's net revenue
interests (working interests less lease burdens) in the properties in which WPC
has a working interest (the "WI Properties") and (ii) the revenue stream
received by WPC attributable to its 35 percent net profits interest in 5,348
gross acres in La Plata County, Colorado (the "Farmout Properties"). The Royalty
Interests also include a 20 percent interest in WPC's Infill Net Proceeds, as
defined below, from the sale of production if well spacing rules are effectively
modified and additional wells are drilled on producing drilling blocks on the WI
Properties (the "Infill Wells") during the term of the Trust. No Infill Wells
have been drilled on the WI Properties to date. "NPI Net Proceeds" consists
generally of the revenue stream received by WPC from its 35 percent net profits
interest in the Farmout Properties, plus the aggregate proceeds attributable to
WPC's net revenue interest, based on the price paid at or in the vicinity of the
wellhead (the "Wellhead"), of gas produced from the WI Properties, less WPC's
share of certain taxes and costs. "Infill Net Proceeds" consists generally of
the aggregate proceeds, based on the price at the Wellhead, of gas produced from
WPC's net revenue interest in any Infill Wells less certain taxes and costs. The
NPI percentage is subject to certain future downward adjustments based on a rate
of return computation once cumulative aggregate production targets are met. The
complete definitions of NPI Net Proceeds and Infill Net Proceeds are set forth
in the Conveyance.
2. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on a modified cash basis and
are not intended to present financial position and results of operations in
conformity with generally accepted accounting principles ("GAAP"). Preparation
of the Trust's financial statements on such basis includes the following:
. Revenues are recognized in the period in which amounts are received by the
Trust. General and administrative expenses are recognized on an accrual
basis.
. Amortization of the Royalty Interests is calculated on a unit-of-production
basis and charged directly to trust corpus.
. Distributions to Unitholders are recorded when declared by the Trustee (see
Note 5).
The financial statements of the Trust differ from financial statements prepared
in accordance with GAAP because royalty income is not accrued in the period of
production and amortization of the Royalty Interests is not charged against
operating results.
Williams sold an aggregate of 5,980,000 Units of the Trust's authorized
9,700,000 Units in the Public Offering at the offering price of $20 per Unit,
retaining 3,720,000 Units. Subsequently, Williams sold an additional 151,209
Units for $23.50 per Unit. Accordingly, the statements of assets, liabilities
and trust corpus at December 31, 1995 and 1994 reflect the sale of these Units
at the respective sale prices thereof, as well as the remaining 3,568,791 Units
at Williams' historical cost. Also, the statement of changes in trust corpus
(deficit) for the year ended December 31, 1993 reflects an increase in trust
corpus during the period in the amount of the excess of the aggregate proceeds
of the sale of the 151,209 Units over Williams' historical cost basis in such
Units. During the second quarter of 1995 Williams transferred its Units to WHD,
a separate holding company for Williams' non-regulated businesses. If WHD, in
the future, should sell all or a portion of its retained Units, at that time,
the carrying value on the Trust's statements of assets, liabilities and trust
corpus would again be adjusted from WHD's historical cost to the subsequent sale
price with respect to the Units sold.
8
<PAGE>
3. FEDERAL INCOME TAXES
The Trust is a grantor trust for Federal income tax purposes. As a grantor
trust, the Trust will not be required to pay Federal or state income taxes.
Accordingly, no provision for income taxes has been made in these financial
statements.
Because the Trust will be treated as a grantor trust, and because a Unitholder
will be treated as directly owning an interest in the Royalty Interests, each
Unitholder will be taxed directly on his per Unit pro rata share of income
attributable to the Royalty Interests consistent with the Unitholder's method of
accounting and without regard to the taxable year or accounting method employed
by the Trust.
Production from the coal seam gas wells drilled after December 31, 1979 and
prior to January 1, 1993, qualifies for the Federal income tax credit for
producing nonconventional fuels under Section 29 of the Internal Revenue Code.
This tax credit is calculated annually based on each year's qualified production
through the year 2002. Such credit, based on the Unitholder's pro rata share of
qualifying production, may not reduce his regular tax liability (after the
foreign tax credit and certain other non-refundable credits) below his
alternative minimum tax. Any part of the Section 29 credit not allowed for the
tax year solely because of this limitation is subject to certain carryover
provisions. Each Unitholder should consult his tax advisor regarding Trust tax
compliance matters.
4. RELATED PARTY TRANSACTIONS
Williams provides accounting, bookkeeping and informational services to the
Trust in accordance with an Administrative Services Agreement effective December
1, 1992. The fee is $50,000 per quarter, escalating 3 percent each October 1
commencing October 1, 1993. Amounts payable by the Trust to Williams at December
31, 1995 and 1994 represent the fourth quarter fees. Aggregate fees incurred by
the Trust to Williams in 1995, 1994 and 1993 were $213,771, $207,545 and
$201,500, respectively.
Aggregate fees paid by the Trust to the trustees in 1995, 1994 and 1993 were
$40,990, $42,806 and $70,644, respectively. Aggregate expense reimbursements to
the Trustee in 1995, 1994 and 1993 were $-0-, $178 and $4,217, respectively.
5. DISTRIBUTIONS TO UNITHOLDERS
The Trustee determines for each quarter the amount of cash available for
distribution to Unitholders. Such amount (the "Quarterly Distribution Amount")
is an amount equal to the excess, if any, of the cash received by the Trust, on
or prior to the last day of the month following the end of each calendar quarter
from the Royalty Interests, plus, with certain exceptions, any other cash
receipts of the Trust during such quarter, over the liabilities of the Trust
paid during such quarter, subject to adjustments for changes made by the Trustee
during such quarter in any cash reserves established for the payment of
contingent or future obligations of the Trust.
The Quarterly Distribution Amount for each quarter is payable to Unitholders of
record on the 45th day following the end of such calendar quarter unless such
day is not a business day in which case the record date is the next business day
thereafter. The Trustee distributes the Quarterly Distribution Amount within 60
days after the end of each calendar quarter to each person who was a Unitholder
of record on the associated record date, together with interest estimated to be
earned on such amount from the date of receipt thereof by the Trustee to the
payment date.
In addition to the regular quarterly distributions, under certain circumstances
specified in the Trust Agreement (such as upon a purchase price adjustment, if
any, or pursuant to the sale of a Royalty Interest) the Trust would make a
special distribution (a "Special Distribution Amount"). A Special Distribution
Amount would be made when amounts received by the Trust under such circumstances
aggregated in excess of $9,000,000. The record date for a Special Distribution
Amount will be the 15th day following receipt of amounts aggregating a Special
Distribution Amount by the Trust (unless such day is not a business day in which
case the record date will be the next business day thereafter) unless such day
is within 10 days of the record date for a Quarterly Distribution Amount in
which case the record date will be the date as is established for the next
Quarterly Distribution Amount. Distribution to Unitholders of a Special
Distribution Amount will be made no later than 15 days after the Special
Distribution Amount record date.
9
<PAGE>
6. CONTINGENCIES
Under the terms of the gas purchase contract entered into by WPC and an
affiliate of WPC, as amended (the "Gas Purchase Contract"), additional revenues
may be paid to the Trust to meet the minimum gas price provision of 97 percent
of $1.75 per MMBtu (the "Minimum Purchase Price"). This additional revenue is
subject to recoupment by the purchaser from future revenues received from
production commencing after January 1, 1994 when the applicable index price
exceeds the Minimum Purchase Price as long as the Minimum Purchase Price
commitment is in effect. The primary term of the Gas Purchase Contract runs to
December 3, 1997 at which time the WPC affiliate may elect to discontinue paying
the Minimum Purchase Price by giving notice of its election to pay solely on an
index price.
The applicable index price was below the Minimum Purchase Price in each month
during the second, third and fourth quarters of 1995. Pursuant to the terms of
the Gas Purchase Contract, WPC established a price credit account. WPC estimates
that, as of December 31, 1995, WFSGR had aggregate price credits in the price
credit account of approximately $19.6 million of which the Trust's 81 percent
interest was approximately $15.9 million. The applicable index price was also
below the Minimum Purchase Price in January and February 1996.
The entitlement of WFSGR to recoup the price credits means that if and when the
applicable Blanco Hub Spot Price rises above $1.75 per MMBtu, future royalty
income paid to the Trust would be reduced until such time as such price credits
have been fully recouped. Corresponding cash distributions to the Unitholders
would also be reduced.
The majority of the production attributable to the Trust is within Federal
units. Unit participating areas are formed by pooling production from the
participating area. Entitlement to the pooled production is based on each
party's acreage in the participating area divided by the total participating
acreage. Wells drilled outside the participating area may create an enlargement
to the participating area and a revision of the unit ownership entitlement. The
Bureau of Land Management ("BLM") must approve unit participating area
expansions. The effective date for unit expansions is retroactive to the date
the well creating the expansion was tested. The revenues presented in the
accompanying statements of distributable income are on an entitlement basis and
reflect the most recent BLM participating area approvals at December 31, 1995,
1994 and 1993, respectively. There are pending or anticipated applications or
approvals for additional participating area enlargements. WPC has advised the
Trustee that it does not believe that final approval of these unit participating
area enlargements and the resulting retroactive adjustments, if any, will have a
material impact on the revenues as presented in these statements.
The Trustee has been advised by WPC that the Minerals Management Service
("MMS"), a subagency of the U.S. Department of the Interior, has from time to
time considered the inclusion of the value of the Section 29 tax credits
attributable to coal seam gas production in the calculation of gross proceeds
for purposes of calculating the royalty that is payable to the MMS. On August
30, 1993, the U.S. Office of the Inspector General (the "OIG") issued an audit
report stating that Section 29 tax credits should be included in the calculation
of gross proceeds and recommending that the MMS pursue collection of additional
royalties with respect to past and future production. On December 8, 1993,
however, the Office of the Solicitor of the U.S. Department of the Interior gave
its opinion to the MMS that the report of the OIG was incorrect and that Section
29 tax credits are not part of gross proceeds for the purpose of Federal royalty
calculations. WPC believes that any such inclusion of the value of Section 29
tax credits for the purposes of calculating royalty payments required to be made
on Federal and Indian lands would be inappropriate since all mineral interest
owners, including royalty owners, are entitled to Section 29 tax credits for
their proportionate share of qualifying coal seam gas production. WPC has
advised the Trustee that it would vigorously oppose any attempt by the MMS to
require the inclusion of the value of Section 29 tax credits in the calculation
of gross proceeds. However, if such regulations were adopted and upheld, royalty
payments would be increased which would decrease NPI Net Proceeds and,
therefore, the amounts payable to the Trust. The reduction in amounts payable to
the Trust would cause a corresponding reduction in associated Section 29 tax
credits available to Unitholders.
10
<PAGE>
The Southern Ute Indian Tribe (the "Tribe") filed a lawsuit on December 31,
1991, challenging the legal rights of WPC and others to extract coal seam gas
from certain properties within the Tribal boundaries. The Tribe is seeking
compensation from the producers and the oil and gas estate owners for the value
of the gas allegedly wrongfully taken from the Tribe. WPC, together with the
other defendants named in the lawsuit, is vigorously defending the lawsuit. On
September 13, 1994, the court issued a memorandum opinion and order in the
litigation granting the motion for summary judgement filed by the defendant
class on the question of ownership of the coal seam gas. The court
ruled that the U.S. Congress did not reserve the coal seam gas in the Coal Land
Acts of 1909 and 1910, and denied the Tribe's claim of equitable ownership of
the coal seam gas. The Tribe has appealed the order to the U.S. Court of Appeals
for the Tenth Circuit. WPC has agreed to indemnify the Trust from and against
any loss, charge or liability as may arise in respect of the Underlying
Properties or the Royalty Interests in connection with the defense of such
lawsuit and all legal costs the Trust might incur if the Trust is named as a
defendant in such litigation. WPC's indemnity with respect to the Farmout
Properties is limited to its retained interest share of any settlement costs
that may reduce the revenue stream it receives from its 35 percent net profits
interest in the Farmout Properties. If the Tribe is successful in showing that
WPC has no right to produce or receive proceeds from the Fruitland coal
formation, WPC has agreed to pay to the Trust, in addition to the
indemnification described above, for distribution to the then current
Unitholders as a return of a portion of the original purchase price paid for the
Units in the Public Offering, an amount equal to $1.47 per Mcf multiplied by the
estimated reserves in the October 1, 1992 Reserve Report (as defined)
attributable to the interest of the Trust in the Farmout Properties subject to
such dispute minus the aggregate cash distributions paid by the Trust prior to
the date of such redetermination and minus the tax benefits, if any, available
to the Unitholders and attributable to the portion of the interest of the Trust
in the Farmout Properties so purchased. Williams has agreed to pay the above
described obligations of WPC to the extent not paid by WPC when due and payable.
If an adverse decision were to be received, WPC has advised the Trustee of the
Trust that it believes the adjustment to the statements presented here would not
be significant for the periods presented.
Also, a Tribal Proposed Mineral Assignment Ordinance (the "Proposed Ordinance")
could apply to the conveyance to the Trust of the Farmout Properties involving
Tribal mineral interests. Although the Proposed Ordinance does not specifically
reference a net profits interest, it is possible that the Tribe would consider
the assignment of the net profits interest tied to Tribal mineral interests as
being covered by the Proposed Ordinance and requiring the approval of the
Chairman of the Tribe. If the Proposed Ordinance is applicable, the assignment
of the net profits interest would not be approved if the Tribe determined that
such creation would not be in the best interest of the Tribe and, absent such
Tribal approval, the net profits interest would be invalid. In addition, a
knowing violation could result in removal of the offending party from the
reservation and the party's forfeiture of any Tribal mineral interests located
on the reservation. Under the Proposed Ordinance, a mineral interest owner is
limited to seeking declaratory relief in Tribal Court. Additionally, under the
Proposed Ordinance, the Tribe would have a right of first refusal to acquire the
net profits interest associated with Tribal leases. The Tribe would have 120
days after the submission of a completed assignment of a Tribal Mineral Interest
Form to exercise the right to acquire said interest for the same terms and
conditions as are disclosed by the filing. It is unknown if the Proposed
Ordinance will be enacted at all, enacted in its current form or enacted in an
altered form. Therefore, the potential effect of the Proposed Ordinance cannot
be accessed at this time.
While no assurances can be given the Trustee of the Trust does not believe that
the ultimate resolution of the foregoing matters, taken as a whole, will have a
material adverse effect on the Trust Corpus or distributable income.
11
<PAGE>
7. SUBSEQUENT EVENT
Subsequent to December 31, 1995, the Trust declared the following distribution:
<TABLE>
<CAPTION>
Quarterly Payment Distribution
Record Date Date per Unit
- --------------------------------------------------------------------------------
<S> <C> <C>
February 14, 1996 February 29, 1996 $0.657528
</TABLE>
The Trustee has estimated the Section 29 tax credit associated with the February
29, 1996 quarterly distribution to be $0.67 per Unit.
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table sets forth the royalty income, distributable income and
distributable income per Unit of the Trust for each quarter in the years ended
December 31, 1995 and 1994 (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Calendar Royalty Distributable Distributable
Quarter Income Income Income per Unit
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
1995
- ----
First............. $5,899 $ 5,701 $.59
Second............ 6,681 6,563 .67
Third............. 7,088 7,020 .73
Fourth............ 6,856 6,769 .70
- --------------------------------------------------------------------------------
$26,524 $26,053 $2.69
- --------------------------------------------------------------------------------
1994
- ----
First............. $ 5,785 $ 5,553 $.57
Second............ 5,799 5,637 .58
Third............. 6,098 6,021 .62
Fourth............ 4,611 4,543 .47
- --------------------------------------------------------------------------------
$22,293 $21,754 $2.24
- --------------------------------------------------------------------------------
</TABLE>
Selected 1995 fourth quarter data are as follows (in thousands except per Unit
amounts):
<TABLE>
<S> <C>
Royalty income..................................................... $ 6,856
Interest income.................................................... 23
- --------------------------------------------------------------------------------
General and administrative expenses................................ (110)
Distributable income............................................... $ 6,769
- --------------------------------------------------------------------------------
Distributable income per unit (9,700,000 units).................... $ .70
- --------------------------------------------------------------------------------
Distribution per unit.............................................. $ .70
- --------------------------------------------------------------------------------
</TABLE>
9. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
The net proved reserves attributable to the Royalty Interests have been
estimated as of December 31, 1995, 1994, 1993 and 1992, by independent petroleum
engineers. A reserve estimate as of December 31, 1992 was prepared for the Trust
even though the conveyance of the Royalty Interests to the Trust did not occur
until January 21, 1993.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of future net revenues from proved reserves have been prepared using end-of-
period gas prices and related costs. The standardized measure of future net
revenues from the gas reserves is calculated based on discounting such future
net revenues at an annual rate of 10 percent. The Blanco Hub Spot Price for
December 1995 of $1.34 per MMBtu, after adjustments for certain costs and
provisions of the Gas Purchase Contract, resulted in a weighted average wellhead
price of $1.05 per Mcf. The standardized measure of discounted future net
revenues below has been reduced by operating and development costs which such
costs are paid by Williams and are included in computing the royalty income of
the Trust. The standardized measure has not been reduced for income taxes as no
income taxes are paid by the Trust (Note 3).
Numerous uncertainties are inherent in estimating volumes and value of proved
reserves and in projecting future production rates and timing of development
expenditures. Such reserve estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of
production may be substantially different from the original estimates.
12
<PAGE>
The reserve estimate as of December 31, 1992 assumed that the percentage share
of NPI Net Proceeds payable to the Trust would increase to 86.5 percent as of
January 1, 1994, in accordance with provisions of the Conveyance whereby such
percentage share would increase under certain conditions. Because the conditions
were not met, the reserve estimates as of December 31, 1995, 1994 and 1993 for
Royalty Interests are based on a percentage share of NPI Net Proceeds payable to
the Trust of 81 percent.
<TABLE>
<CAPTION>
Natural Gas (MMcf)
- --------------------------------------------------------------------------------
<S> <C>
Proved reserves at January 1, 1993...................... 140,563
Revisions of previous estimates........................ 13,416*
Production............................................. (20,077)
- --------------------------------------------------------------------------------
Proved reserves at December 31, 1993.................... 133,902
Revisions of previous estimates........................ 50,183**
Production............................................. (22,510)
- --------------------------------------------------------------------------------
Proved reserves at December 31, 1994.................... 161,575
Revisions of previous estimates........................ 30,299**
Production............................................. (29,050)
- --------------------------------------------------------------------------------
Proved reserves at December 31, 1995.................... 162,824
- --------------------------------------------------------------------------------
</TABLE>
*Includes the effect of normal net upward reserve revisions partially offset by
the downward adjustment of the percentage share of NPI Net Proceeds payable to
the Trust (for purposes of the reserve estimates) from 86.5 to 81 percent.
**Includes reserve increases resulting from well recompletions and other
factors.
All proved reserve estimates presented above at December 31, 1995, 1994 and 1993
and January 1, 1993 are proved developed.
Proved reserves are estimated quantities of natural gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from known reservoirs under existing economic and operating conditions.
Proved developed reserves are proved reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
The following table sets forth the standardized measure of discounted future net
revenues at December 31, 1995, 1994 and 1993 relating to proved reserves (in
thousands):
<TABLE>
<CAPTION>
Years Ended December 31
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Future cash inflows.......................... $131,819 $170,540 $190,690
Future production taxes...................... (8,897) (15,646) (17,374)
- --------------------------------------------------------------------------------
Future net cash flows........................ 122,922 154,894 173,316
10% discount factor.......................... (43,089) (55,734) (62,293)
- --------------------------------------------------------------------------------
Standardized measure of discounted future
net revenues................................. $ 79,833 $ 99,160 $111,023
- --------------------------------------------------------------------------------
</TABLE>
The following table sets forth the changes in the aggregate standardized measure
of discounted future net revenues from proved reserves during the years ended
December 31, 1995, 1994 and 1993 (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at January 1...................... $99,160 $111,023 $103,777
Increase (decrease) due to:
Net sales of coal seam gas............... (27,603) (23,443) (21,660)
Net changes in prices and costs.......... (17,547) (29,197) 8,310
Development costs incurred........... 449 1,196 ---
Net change in cost estimates......... (449) (1,196) ---
Change in estimated volumes.............. 14,856 30,798 11,124
Accretion of discount................ 9,916 11,102 10,378
Other................................ 1,051 (1,123) (906)
- --------------------------------------------------------------------------------
(19,737) (11,863) 7,246
- --------------------------------------------------------------------------------
Balance at December 31.................... $ 79,833 $ 99,160 $111,023
- --------------------------------------------------------------------------------
</TABLE>
13
<PAGE>
SUPPLEMENTAL INFORMATION
The Royalty Interests owned by the Trust burden the Underlying Properties, which
are owned by WPC and not the Trust. For the information of Unitholders, the
following Statement of Revenues and Direct Operating Expenses of the Underlying
Properties for each of the three years in the period ended December 31, 1995,
audited by Ernst & Young LLP, independent auditors, has been prepared and
furnished by WPC to the Trustee for inclusion herein.
14
<PAGE>
REPORT OF INDEPENDENT AUDITORS
THE BOARD OF DIRECTORS WILLIAMS PRODUCTION COMPANY:
We have audited the accompanying Statement of Revenues and Direct Operating
Expenses of certain coal seam gas producing properties (the "Underlying
Properties") of Williams Production Company (the "Company") for each of the
three years in the period ended December 31, 1995. This financial statement is
the responsibility of Company's management. Our responsibility is to express an
opinion on this financial statement based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statement is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statement. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the statement referred to previously presents fairly, in all
material respects, the revenues and direct operating expenses described in Note
2 of the Underlying Properties for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
/sig/ ERNST & YOUNG LLP
Tulsa, Oklahoma
March 22, 1996
15
<PAGE>
UNDERLYING PROPERTIES
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Revenues -- gas sales................................ $36,859 $32,145 $29,281
Direct operating expenses:
Taxes on production and property.................... 2,096 2,645 2,416
Production and other expenses....................... 1,882 1,905 1,654
- --------------------------------------------------------------------------------
Total.............................................. 3,978 4,550 4,070
- --------------------------------------------------------------------------------
Excess of revenues over direct
operating expenses................................... $32,881 $27,595 $25,211
- --------------------------------------------------------------------------------
</TABLE>
See accompanying notes.
16
<PAGE>
UNDERLYING PROPERTIES
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
1. UNDERLYING PROPERTIES
The Underlying Properties consist of certain coal seam gas interests currently
owned by Williams Production Company ("WPC"), a wholly owned indirect subsidiary
of The Williams Companies, Inc. ("Williams"). These properties, all of which are
located in the San Juan Basin of New Mexico and Colorado, are burdened by net
profits interests conveyed to Williams Coal Seam Gas Royalty Trust (the "Trust")
on January 21, 1993. All of the Underlying Properties were acquired by
predecessor entities of Williams prior to 1989. Significant development of the
Underlying Properties did not occur until 1989 and significant production did
not occur until 1990. During the periods presented, all of the production from
these properties was sold in the spot gas sales market to nonaffiliated entities
or Williams Gas Marketing Company ("WGM") or Williams Field Services Gas
Resources Company ("WFSGR"), wholly owned subsidiaries of Williams.
2. BASIS OF PRESENTATION
The Statement of Revenues and Direct Operating Expenses of the Underlying
Properties was derived from the historical accounting records of WPC and does
not give effect to the conveyance of interests in these properties to the Trust.
The statement does not include depreciation, depletion and amortization, general
and administrative expenses, interest expenses or income taxes. The revenues are
reflected net of existing royalties and overriding royalties and have been
reduced by gathering and processing expenses. The revenues are presented on a
production entitlement basis wherein WPC's revenue interest is applied to
volumes produced for revenue recognition. Actual cash receipts may vary due to
timing delays of actual cash receipts from the property operators or purchasers
and due to wellhead and pipeline volume balancing agreements or practices.
Expenses are presented on an accrual basis.
3. RELATED PARTY TRANSACTIONS
In late 1991, WPC began selling a significant portion of the production from
these properties to WGM at amounts approximating current spot market prices.
Effective October 1, 1992, WPC entered into a long term contract with WGM to
purchase substantially all of the production from these properties. Effective
May 1, 1995 WGM assigned to WFSGR all of its rights and obligations under such
contract. Gross revenues (before deductions for applicable royalties and
gathering and processing expenses) from WGM and WFSGR included in this statement
are $52,182,150, $43,002,000 and $38,775,000 for 1995, 1994 and 1993,
respectively.
In addition, gas produced from the Underlying Properties beginning in 1991 has
been gathered and processed by Northwest Pipeline Corporation ("Northwest") and
Williams Field Services Company ("WFS"), both of which are wholly owned
subsidiaries of Williams, at rates which Williams believes are consistent with
industry practice. The fees charged to WPC by Northwest and WFS applicable to
these properties for 1995, 1994 and 1993 were $14,408,168, $11,845,000 and
$11,072,000, respectively, and are accounted for as deductions from revenues by
WPC. WPC has also sold some of the gas at the wellhead to purchasers who then
contract with WFS and Northwest for gathering and processing services. Amounts
paid by these unrelated purchasers to WFS and Northwest are not included in the
fees disclosed above.
4. CONTINGENCIES
The majority of the production from the Underlying Properties is from Federal
units. Unit acreage is formed by pooling production from the participating area.
Entitlement to the pooled production is based on each party's acreage in the
participating area divided by the total unit acreage. Wells drilled outside the
participating area may create an enlargement to the participating area and a
revision of the unit ownership entitlement. The Bureau of Land Management
("BLM") must approve unit participating area expansions. The effective date for
unit expansions is retroactive to the date the well creating the expansion was
tested. The revenues presented in the accompanying statement are on a production
entitlement basis and reflect the most recent BLM participating area approvals
at December 31, 1995. There are pending or anticipated additional applications
which may be approved for participating area enlargements. WPC does not believe
that final approval of these unit participating area enlargements and any
resulting retroactive adjustments will have a significant impact on the revenues
as presented in this statement.
17
<PAGE>
WPC has been advised that the Minerals Management Service ("MMS") has from time
to time considered the inclusion of the value of the Section 29 tax credits
attributable to coal seam gas production in the calculation of gross proceeds
for royalty purposes. On August 30, 1993, the U.S. Office of the Inspector
General (the "OIG") issued an audit report stating that Section 29 tax credits
should be included in the calculation of gross proceeds and recommending that
the MMS pursue collection of additional royalties with respect to past and
future production. On December 8, 1993, however, the Office of the Solicitor of
the U.S. Department of the Interior gave its opinion to the MMS that the report
of the OIG was incorrect and that Section 29 tax credits are not part of gross
proceeds for the purpose of federal royalty calculations. WPC believes that any
such inclusion of the value of Section 29 tax credits for purposes of
calculating royalty payments required to be made on Federal and Indian lands
would be inappropriate since all mineral interest owners, including royalty
owners, are entitled to Section 29 tax credits for their proportionate share of
qualifying coal seam gas production. WPC would vigorously oppose any attempt by
the MMS to require the inclusion of the value of Section 29 tax credits in the
calculation of gross proceeds. However, if such regulations were adopted and
upheld, royalty payments would be increased which would decrease NPI Net
Proceeds and, therefore, the amounts payable to the Trust. The reduction in
amounts payable to the Trust would cause a corresponding reduction in associated
Section 29 tax credits available to Unitholders.
The Southern Ute Indian Tribe (the "Tribe") filed a lawsuit on December 31,
1991, challenging WPC's and others' legal right to extract coal seam gas from
certain properties within the Tribal boundaries. The Tribe is seeking
compensation from the producers for the value of the gas allegedly wrongfully
extracted from the properties. WPC is aggressively defending its title to the
gas. On September 13, 1994, the court issued a memorandum opinion and order in
the litigation granting the motion for summary judgement filed by the defendant
class on the question of ownership of the coal seam gas. The Tribe has appealed
the order to the U.S. Court of Appeals for the Tenth Circuit. If an adverse
decision were to be received, WPC believes the adjustment to the statement
presented would not be significant for the periods presented.
5. SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Proved reserves of the Underlying Properties have been estimated by independent
petroleum engineers.
In accordance with Statement of Financial Accounting Standards No. 69, estimates
of the standardized measure of future net revenues from proved reserves have
been prepared using end-of-period gas prices. The standardized measure of future
net revenues from the coal seam gas reserves is calculated based on discounting
such future net revenues at an annual rate of 10 percent. The standardized
measure has not been reduced for income tax consistent with the basis of
presentation described in Note 2. The wellhead spot market price for gas in the
San Juan Basin (a Blanco Hub Spot Price), adjusted for certain costs and the
provisions of a gas purchase contract with an affiliate, was $1.05, $1.07 and
$1.40 Mcf at December 31, 1995, 1994 and 1993, respectively.
The following table sets forth the Underlying Properties' proved coal seam gas
reserves and the related changes in such reserves:
<TABLE>
<CAPTION>
Natural Gas (MMcf)
- --------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31
-------------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Proved reserves at beginning of period.... 199,475 165,314 163,897
Increases (decreases) due to:
Revisions................................ 37,406 61,952 26,203
Production.............................. (35,864) (27,791) (24,786)
- --------------------------------------------------------------------------------
Proved reserves at end of period.......... 201,017 199,475 165,314
- --------------------------------------------------------------------------------
Proved developed reserves at end of period. 201,017 199,475 165,314
- --------------------------------------------------------------------------------
</TABLE>
Proved reserves are estimated quantities of coal seam gas which geological and
engineering data indicate with reasonable certainty to be recoverable in future
years from the Fruitland formation under existing economic and operating
conditions. Proved developed reserves are proved reserves which are expected to
be recovered through existing wells with existing equipment and operating
methods.
Numerous uncertainties are inherent in estimating volumes and value of proved
reserves and in projecting future production rates and timing of development
expenditures. Such reserve estimates are subject to change as additional
information becomes available. The reserves actually recovered and the timing of
production may be substantially different from the original estimates.
18
<PAGE>
The following table sets forth the standardized measure of discounted future net
revenues relating to proved reserves:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Future cash inflows.......................... $162,739 $210,577 $235,419
Future production and development costs...... (26,632) (35,223) (37,577)
- --------------------------------------------------------------------------------
Future net cash flows........................ 136,107 175,354 197,842
10% discount factor.......................... 45,256 (60,441) (68,550)
- --------------------------------------------------------------------------------
Standardized measure of discounted future
net revenues................................. $ 90,851 $114,913 $129,292
- --------------------------------------------------------------------------------
</TABLE>
The following table sets forth the changes in the present value of estimated
future net revenues from proved reserves:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------------
1995 1994 1993
- --------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Balance at beginning of period............... $114,913 $129,292 $114,492
Increase (decrease) due to:
Sales of coal seam gas...................... (32,881) (27,595) (25,211)
Net change in prices........................ (22,059) (34,376) 9,663
Development costs incurred.................. 105 1,966 6,873
Net change in cost estimates................ (105) (1,966) (6,873)
Change in estimated volumes................. 16,906 35,689 20,493
Accretion of discount....................... 11,491 12,929 11,449
Other....................................... 2,481 (1,026) (1,594)
- --------------------------------------------------------------------------------
(24,062) (14,379) 14,800
- --------------------------------------------------------------------------------
Balance at end of period..................... $90,851 $114,913 $129,292
- --------------------------------------------------------------------------------
</TABLE>
The information presented with respect to estimated future net revenues and the
present value thereof is not intended to represent the fair value of coal seam
gas reserves. This information is presented to allow a reasonable comparison of
reserve values prepared using standardized measurement criteria and should be
used only for that purpose. Actual future sales prices and production and
development costs may vary significantly from those in effect at December 31,
1995 and actual future production may not occur in the periods or amounts
projected.
19
<PAGE>
TRANSFER AGENT AND REGISTRAR
Chemical Shareholder Services Group, Inc.
Dallas, Texas and New York, New York
TRUST AUDITORS
Ernst & Young LLP
Tulsa, Oklahoma
TRUSTEE COUNSEL
Thompson & Knight,
A Professional Corporation
Dallas, Texas
FORM 10-K
A copy of the Form 10-K of the Trust for the year ended December 31, 1995 as
filed with the Securities and Exchange Commission has been provided with this
Annual Report to Unitholders. Additional copies of the Form 10-K will be
provided, without charge, upon written request to:
Williams Coal Seam Gas Royalty Trust
NationsBank of Texas, N.A.
901 Main Street, Suite 1200
Dallas, Texas 75202
Attention: Ron E. Hooper, Vice President
Trust Oil & Gas
Williams Coal Seam Gas Royalty Trust
NationsBank of Texas, N.A.
901 Main Street, Suite 1200
Dallas, Texas 75202
1-800-365-6548
20
<PAGE>
EXHIBIT 23.1
LETTERHEAD OF MILLER AND LENTS, LTD.
March 27,1996
NationsBank of Texas, N.A., Trustee
Williams Coal Seam Gas Royalty Trust
NationsBank Plaza
901 Main Street, Twelfth Floor
Dallas, Texas 75202
Re: Williams Coal Seam Gas Royalty Trust
Securities and Exchange Commission Form 10-K
Annual Report
Gentlemen:
The firm of Miller and Lents, Ltd. consents to the references to Miller and
Lents, Ltd. and to the use of its reports listed below regarding the Williams
Coal Seam Gas Royalty Trust Proved Reserves and Future Net Income in the Form
10-K Annual Report to be filed by the Williams Coal Seam Gas Royalty Trust with
the Securities and Exchange Commission.
1. Report dated November 21, 1992 for reserves as of October 1, 1992
2. Report dated March 10, 1993 for reserves as of December 31, 1992
3. Report dated February 23, 1994 for reserves as of December 31, 1993
(using October 1, 1992 prices)
4. Report dated February 23, 1994 for reserves as of December 31, 1993
(using December 31, 1993 prices)
5. Report dated February 28, 1995 for reserves as of December 31, 1994
6. Report dated March 8, 1996 for reserves as of December 31, 1995
Miller and Lents, Ltd. has no interests in the Williams Coal Seam Gas
Royalty Trust or in any of its affiliated companies or subsidiaries and does not
receive any such interest as payment for its report. No director, officer, or
employee of Miller and Lents, Ltd. is employed by or otherwise connected with
the Williams Coal Seam Gas Royalty Trust nor is Miller and Lents, Ltd. employed
by the Williams Coal Seam Gas Royalty Trust on a contingent basis.
Very truly yours,
MILLER AND LENTS, LTD.
/s/ S. John Stieber
By __________________________________
S. John Stieber
Senior Vice President
SIS/hsd
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-01-1995
<CASH> 29,134
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 29,134
<PP&E> 138,566,663
<DEPRECIATION> (55,843,204)
<TOTAL-ASSETS> 82,752,593
<CURRENT-LIABILITIES> 56,839
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 82,695,754
<TOTAL-LIABILITY-AND-EQUITY> 82,752,593
<SALES> 26,524,115
<TOTAL-REVENUES> 26,614,591
<CGS> 561,381
<TOTAL-COSTS> 561,381
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 26,053,210
<EPS-PRIMARY> 2.69
<EPS-DILUTED> 2.69
</TABLE>
<PAGE>
EXHIBIT 99.7
[LETTERHEAD OF MILLER AND LENTS, LTD]
March 8, 1996
NationsBank of Texas, N.A., Trustee
Williams Coal Seam Gas Royalty Trust
NationsBank Plaza
901 Main Street, Twelfth Floor
Dallas, Texas 75202
Re: Proved Reserves and Future Net Income
As of December 31, 1995
Gentlemen:
As your request, we estimated the Proved Reserves and projected the Future
Net Income from the gas reserves in the Fruitland Coal formation that are
attributable to the interests of Williams Coal Seam Gas Royalty Trust. These
interests consist of net profits interests in natural gas properties located
in the San Juan Basin in Colorado and New Mexico.
In order to estimate the reserves to the Williams Coal Seam Gas Royalty
Trust, it was necessary to estimate the reserves attributable to the "Underlying
Properties," the Williams Production Company working interests and net profits
interests from which the royalty trust was created. A portion of these
Underlying Properties was conveyed to the Williams Coal Seam Gas Royalty
Trust as the "Royalty Interests." The Williams Coal Seam Gas Royalty Trust
is assumed to receive 81 percent of the "Net Proceeds" (as defined) from
the gas produced and sold from the Underlying Properties which are working
interests and 81 percent of the revenue stream of the Underlying Properties
for the net profits interests in the Farmout Properties.
For the working interest of the Underlying Properties, overhead costs
(beyond the standard overhead charges for the non-operated properties), have
not been included, nor have the effects of depreciation, depletion, and Federal
Income Tax. The calculations of the Net Proceeds for the Royalty Interests
from the working interest properties are based on 81 percent of the gross income
to the net revenue interest of the Underlying Properties less 81 percent of the
severance and ad valorem taxes. The reserves to the Royalty Interests are based
on 81 percent of the net reserves to the Underlying Properties.
For the wells in the Colorado farmout area, we computed the income to
the net profits interests by considering a net revenue interest equivalent
to the net profits interest and deducting the working interests costs associated
therewith. This results in the revenue stream to the net profits interests.
The reserves for the Underlying Properties for the net profits interests
were computed by multiplying the ratio of the net profits income to the total
gross income by the gross gas reserves. The reserves to the Royalty Interests
are based on 81 percent of the reserves for the Underlying Properties for
these wells.
<PAGE>
MILLER AND LENTS, LTD.
NationsBank of Texas, N.A., Trustee March 8, 1996
Williams Coal Seam Gas Royalty Trust Page 2
A summary of the reserves for the Underlying Properties and the Royalty
Interests is as follows:
Proved Reserves as of December 31, 1995
---------------------------------------
<TABLE>
<CAPTION>
Reserves Future Present
MMcf Net Value at
at 14.73 Income, 10 Percent
M$ M$ Per Annum, M$
-------- ------ -------------
<S> <C> <C> <C>
The Underlying Properties
- -------------------------
Proved Developed Producing 200,988 136,084 90,833
Proved Developed Nonproducing 30 23 18
------- ------- ------
Total Proved Reserves 201,017 136,107 90,851
The Royalty Interests (Net to the Trust)
- ----------------------------------------
Proved Developed Producing 162,800 122,901 79,817
Proved Developed Nonproducing 24 21 16
------- ------- ------
Total Proved Reserves 162,824 122,921 79,833
</TABLE>
The Proved Reserves were estimated in accordance with the definitions
contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a).
Estimates of Future Net Income and discounted Future Net Income are not intended
and should not be interpreted to represent the fair market value of the
estimated reserves. There are no Proved Undeveloped Reserves.
The Section 29 tax credits attributable to the total Proved Reserves in
the Underlying Properties from 1996 through the year 2002, assuming no future
escalation of the estimated 1996 rate of $1.028 per MMBtu, are $139 million
with a 10 percent present worth of $106 million. The tax credits attributable
to the Royalty Interests are $112 million with a 10 percent present worth of
$86 million.
The production forecast for the Proved Reserves and future net revenues
as of December 31, 1995 attributable to the Underlying Properties and to
the Williams Coal Seam Gas Royalty Trust are shown on Table 1. The Proved
Reserves and future net revenues as of December 31, 1995 attributable to
the individual Underlying Properties, including summaries by reserve category
and areas, are shown on the attached one-line summary identified as Table
2.
The gas reserves for the Fruitland Coal were estimated by decline curve
analyses utilizing type curves for the various areas in the San Juan Basin.
These type curves were developed for each area and were based on production
histories and the initial reservoir pressures of the wells in the separate
areas.
<PAGE>
MILLER AND LENTS LTD.
NationsBank of Texas, N.A., Trustee March 8, 1996
Williams Coal Seam Gas Royalty Trust Page 3
The gas price used in these projections is the December 1995 wellhead
price, reported by Williams Production Company, of $0.8644 per MMBtu except
for the 30-6 Unit which is $0.7928 per MMBtu. These prices were held constant
and there were no escalations of operating costs.
We relied on production histories, accounting and cost data, engineering
and geological information supplied by Williams Production Company, data
existing in our files, and data from public records. The ownership interests
evaluated herein were provided by Williams Production Company and were employed
as presented. No independent verification of these interests was made by
Miller and Lents, Ltd.
Capital expenditures to plug and abandon wells are considered to be equal
to the salvage values of the wells at the time of abandonment. We did not
include any consideration for the future environmental restoration that might
be required as such was beyond the scope of our assignment. In our projection
of Future Net Income, no provisions are made for production prepayments or
for the consequences of future production balancing.
The evaluations presented in this report, with the exceptions of those
parameters specified by others, reflect our informed judgments based on accepted
standards of professional investigation, but are subject to those generally
recognized uncertainties associated with the interpretations of geological
and engineering information. Government policies and market conditions different
from those employed in this study may cause the total quantity of oil and
gas to be recovered, actual production rates, prices received, and operating
and capital costs to vary from those presented in this report.
Very truly yours,
MILLER AND LENTS, LTD.
By /s/ S. John Stieber
---------------------
S. John Stieber
Senior Vice President
SJS/hsd
