-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, MYDwH/FwXEB2i8HGhH9olJdiiYGuT56Ipu8QNxHGDIlvk4NhhHymRXo9dh4DswXE /FgMEcfSitj8CF+0yoTbXA== 0000930661-96-000234.txt : 19960402 0000930661-96-000234.hdr.sgml : 19960402 ACCESSION NUMBER: 0000930661-96-000234 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960401 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: WILLIAMS COAL SEAM GAS ROYALTY TRUST CENTRAL INDEX KEY: 0000895007 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 756437433 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-11608 FILM NUMBER: 96542230 BUSINESS ADDRESS: STREET 1: NATIONSBANK OF TEXAS N A (TRUST DIV) STREET 2: 901 MAIN ST 12TH FLR CITY: DALLAS STATE: TX ZIP: 75202 BUSINESS PHONE: 2145082364 MAIL ADDRESS: STREET 1: NATIONSBANK PLAZA STREET 2: 901 MAIN STREET SUITE 1200 CITY: DALLAS STATE: TX ZIP: 75202 10-K 1 FORM 10-K =============================================================================== UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------- (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 ---------------- 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 ------------------- --------------------- 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. =============================================================================== TABLE OF CONTENTS
PAGE ---- 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
(i)
PAGE ---- 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
(ii) 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. 1 "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. 2 "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. 3 "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." 4 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 5 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 6 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 7 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. 8 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 9 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 10 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. 11 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. 12 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. 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.
13 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.
14 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)).
15 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.
16 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.
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. 17 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 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 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 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 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 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.
UNDERLYING PROPERTIES ------------------------- ESTIMATED DISCOUNTED FUTURE NET NET PROVED REVENUES RESERVES (DISCOUNTED FEDERAL UNIT FEDERAL UNIT OPERATOR (BCF) AT 10%) ------------ --------------------- ---------- -------------- (IN THOUSANDS) 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
Meridian Oil Inc. is a subsidiary of Burlington Resources Inc. and Blackwood & Nichols Co., Ltd. is a subsidiary of Devon Energy Corporation. 23 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.
NUMBER OF WELLS ACRES --------- -------------- GROSS NET GROSS NET ----- --- ------- ------ DECEMBER 31, - ------------ 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 === === ======= ======
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 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 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.
ROYALTY UNDERLYING INTERESTS PROPERTIES --------- ---------- 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
- -------- (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 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:
YEAR ENDED DECEMBER 31, ----------------------- 1993 1994 1995 ------- ------- ------- 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
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 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:
NPI WPC'S RETAINED PERCENTAGE OF PERCENTAGE OF NPI NET NPI NET PROCEEDS PROCEEDS ------------- -------------- Internal Rate of Return: Less than 12%................................ 81% 19% 12% to 14%................................... 60 40 More than 14%................................ 40 60
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 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 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 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 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 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 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 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 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 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 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.
NAME AND ADDRESS NUMBER OF UNITS PERCENT OF BENEFICIAL OWNER BENEFICIALLY OWNED OF CLASS ------------------- ------------------ -------- Williams Holdings of Delaware, Inc............... 3,568,791 36.8% One Williams Center Tulsa, Oklahoma 74172
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 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 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)
PAGE IN 1995 ANNUAL REPORT TO UNITHOLDERS (INCORPORATED BY REFERENCE) -------------- 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
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
EXHIBIT NUMBER EXHIBIT ------- ------- 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).
40
EXHIBIT NUMBER EXHIBIT ------- ------- 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).
41
EXHIBIT NUMBER EXHIBIT ------- ------- 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.
(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 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 EX-13 2 ANNUAL REPORT TO UNITHOLDERS 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.
1996 1997 - -------------------------------------------------------------------------------- Record Dates May 15 August 14 November 14 February 14 Distribution Payment Dates (approximate) May 30 August 29 November 29 March 1
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.
- -------------------------------------------------------------------------------- Sales Price --------------------- Distributions 1995 High Low per Unit - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
At March 15, 1996, there were 9,700,000 Units outstanding and approximately 898 Unitholders of record. SELECTED FINANCIAL DATA
- -------------------------------------------------------------------------------- Years Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
1 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 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 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.
Twelve Months Ended September 30, - -------------------------------------------------------------------------------- 1995 1994 1993 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
/(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 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 FINANCIAL STATEMENTS WILLIAMS COAL SEAM GAS ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
- -------------------------------------------------------------------------------- December 31 1995 1994 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 - --------------------------------------------------------------------------------
STATEMENTS OF DISTRIBUTABLE INCOME
- -------------------------------------------------------------------------------- Year Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------- 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
STATEMENTS OF CHANGES IN TRUST CORPUS (DEFICIT)
- -------------------------------------------------------------------------------- Year Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------- 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.
6 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 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 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 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 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 7. SUBSEQUENT EVENT Subsequent to December 31, 1995, the Trust declared the following distribution:
Quarterly Payment Distribution Record Date Date per Unit - -------------------------------------------------------------------------------- February 14, 1996 February 29, 1996 $0.657528
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):
- -------------------------------------------------------------------------------- Calendar Royalty Distributable Distributable Quarter Income Income Income per Unit - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
Selected 1995 fourth quarter data are as follows (in thousands except per Unit amounts): 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 - --------------------------------------------------------------------------------
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 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.
Natural Gas (MMcf) - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
*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):
Years Ended December 31 1995 1994 1993 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
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):
1995 1994 1993 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
13 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 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 UNDERLYING PROPERTIES STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES
YEAR ENDED DECEMBER 31 ------------------------ 1995 1994 1993 - -------------------------------------------------------------------------------- (In Thousands) 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 - --------------------------------------------------------------------------------
See accompanying notes. 16 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 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:
Natural Gas (MMcf) - -------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31 ------------------------------- 1995 1994 1993 - -------------------------------------------------------------------------------- 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 - --------------------------------------------------------------------------------
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 The following table sets forth the standardized measure of discounted future net revenues relating to proved reserves:
YEAR ENDED DECEMBER 31 ------------------------------------ 1995 1994 1993 - -------------------------------------------------------------------------------- (In Thousands) 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 - --------------------------------------------------------------------------------
The following table sets forth the changes in the present value of estimated future net revenues from proved reserves:
YEAR ENDED DECEMBER 31 ------------------------------------ 1995 1994 1993 - -------------------------------------------------------------------------------- (In Thousands) 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 - --------------------------------------------------------------------------------
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 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 EX-23.1 3 MILLER AND LENTS, LTD. CONSENT 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 EX-27 4 FINANCIAL DATA SCHEDULE
5 YEAR DEC-31-1995 JAN-01-1995 DEC-01-1995 29,134 0 0 0 0 29,134 138,566,663 (55,843,204) 82,752,593 56,839 0 0 0 0 82,695,754 82,752,593 26,524,115 26,614,591 561,381 561,381 0 0 0 0 0 0 0 0 0 26,053,210 2.69 2.69
EX-99.7 5 RESERVE REPORT 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. 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 ---------------------------------------
Reserves Future Present MMcf Net Value at at 14.73 Income, 10 Percent M$ M$ Per Annum, M$ -------- ------ ------------- 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
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. 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 -----END PRIVACY-ENHANCED MESSAGE-----