Court Opinion

ID: 4484609
Source: CourtListenerOpinion
Date Created: 2020-01-16 21:16:52.252962+00
Date Added: 2024-06-11T14:54:04.828042
License: Public Domain

Goffe, Judge. *  The Commissioner determined the following deficiencies in petitioners’ Federal income taxes: Petitioners Docket No. Year Deficiency Richard L. Burns and Joyce C. Burns.7139-79 1975 $17,473 1976 22,238 Stanley L. Ross and Phyliss Ross. 9564-79 1975 22,963 C. Hayden Atchison and Ruth Atchison.9914-79 1975 3,789 Harry L. Hawkinson, Jr., and Elizabeth G. Hawkinson.9915-79 1975 5,583 Raymond G. Larson and Lois S. Larson.9916-79 1975 5,738 William T. Stokes and Fiona D. Stokes.9917-79 1975 1,850 The sole issue remaining for decision2 is whether petitioners are entitled to deduct as intangible drilling and development costs the full amount of turnkey drilling and completion contracts when one-half of the turnkey prices was paid for with proceeds from bank loans which were fully secured by the promoters of the drilling program and were payable solely from the net proceeds from production or from the security pledged by the promoters. FINDINGS OF FACT Some of the facts have been stipulated and are found accordingly. Richard L. and Joyce C. Burns, Stanley L. and Phyliss Ross, C. Hayden and Ruth Atchison, and Harry L. Hawkinson, Jr., and Elizabeth G. Hawkinson, all of whom timely filed joint Federal income tax returns for the years in issue with the Office of the Internal Revenue Service in Fresno, Calif., resided in California when they filed their petitions. Raymond G. and Lois S. Larson and William T. and Fiona D. Stokes resided in Texas when they filed their petitions. The Larsons timely filed their 1975 joint Federal income tax return with the Office-of the Internal Revenue Service in Fresno, Calif., and the Stokes timely filed their 1975 joint Federal income tax return with the Office of the Internal Revenue Service in Austin, Tex.3  Our presentation of the facts will be organized in terms of the parties and the oil and gas properties because of the numerous and confusing details involved. I. The promoters. — R. L. Burns Corp. (RLBC) is a Delaware corporation which was engaged, during 1974 and 1975, in oil and gas exploration, development, and management activities in the western, southwestern, and southeastern parts of the United States. Burns organized RLBC in 1969 with an initial capitalization of $100,000. By 1977, RLBC’s stock was traded on the New York Stock Exchange and RLBC had a book value of $25 million. During 1974 and 1975, Burns served as chairman of the board of directors and chief executive officer of RLBC. Burns left RLBC in 1977. During the early years of its existence, RLBC’s "client drilling program” constituted its only business activity. RLBC later used the profits from its client drilling program to engage in oil and gas activities for its own account. By 1974, RLBC conducted oil and gas activities both for its own account as well as for its clients. In 1975, Callón Petroleum Co. (CPC) was a publicly traded oil and gas exploration company listed on the Pacific Stock Exchange.4 CPC’s business activities included acquiring and selling oil and gas properties as well as exploring for, and producing, oil and gas. In late 1974 or early 1975, CPC’s management consulted with RLBC’s management regarding RLBC’s client drilling program. Shortly thereafter, CPC established a "client energy plan” which is substantially identical to RLBC’s client drilling program. As explained in the prospectus for its client energy plan, CPC designed its plan to provide investors with the opportunity to engage in the oil and gas business utilizing funds "which are normally set aside to pay Federal and State income taxes.” RLBC’s client drilling program and CPC’s client energy plan5 offer to sell working interests in oil and gas leases located in known oil and/or gas producing areas,6 to drill and complete oil and/or gas wells on the purchased leases under the terms of turnkey drilling and completion contracts,7 and to arrange for third-party banks to finance 50 percent of the turnkey prices for the drilling and completion contracts, fully secured by certificates of deposit pledged by an RLBC subsidiary or by CPC. Clients who purchase working interests in leases are neither obligated to enter into drilling and completion contracts nor to use the arranged financing.8 However, clients who do enter into drilling and completion contracts and do utilize the financing must also enter into several additional agreements which provide that RLBC or CPC will manage and operate their wells, that 50 percent of the net proceeds derived from the sale of oil and gas attributable to their working interests will be used to make principal and interest payments on their loans, and that the management fees will be renegotiated when the loans are fully repaid. In the event a management fee cannot be renegotiated, these agreements provide that RLBC or CPC may arrange for the sale of the client’s working interest and that RLBC or CPC will receive, a commission thereon equal to 50 percent of the net proceeds from the sale. As an additional option, both RLBC and CPC offer to lease to their clients the tangible equipment necessary to operate their producing wells.9  In the event a client chooses to lease the necessary tangible equipment from RLBC or CPC and subsequent production attributable to the client’s working interest is insufficient to cover the rental payments, RLBC or CPC will make the rental payments on the client’s behalf and treat such payments as receivables on its books. Similarly, in the event 50 percent of the net proceeds from the sale of oil and/or gas attributable to a client’s working interest is insufficient to cover the interest payments on the loan arranged with the third-party banks, RLBC or CPC will make the interest payments and treat such payments as receivables on its books. No writing or other evidence of indebtedness was prepared at that time to reflect either of these types of payments by RLBC or CPC. Among other reasons, RLBC designed its client drilling program to permit it to take the full amount of a drilling contract price into income (both book and taxable) in the year a well is completed, and to reflect the certificate of deposit as an asset on its books for financial accounting purposes. RLBC’s independent auditors approved of this treatment, provided the oil and gas reserves of the mineral property in question were sufficient to provide for repayment of the client’s bank loan. Neither RLBC nor its independent auditors treated the financing arrangement as an oil and gas production payment or as a loan from RLBC to its client. CPC did not treat the financing arrangement of its client energy plan as an oil or gas production payment. II. The Morriss 5-1 well.10 — On May 22, 1974, RLBC, as lessee, acquired from W. L. Morriss, et al., as lessors, an oil, gas, and mineral lease (the Morriss lease) comprising approximately 877.9 acres of land located in Sutton County, Tex. As part of its 1974 client drilling program, RLBC sold its working interest11 in 160 acres covered under the Morriss lease to Barmet Industries, Inc., for $16,000. Barmet Industries, Inc., in turn, sold portions of this working interest to Jack Pollock and Burns. (This assignment will be referred to as the Morriss 5-1 lease.) The purchasers paid for, and acquired working interests in, the Morriss 5-1 lease in accordance with the following percentages: Purchaser12 Percentage Barmet Industries, Inc. 10 Jacob Pollock .60 Burns . 30 100 The Barmet group chose to have RLBC drill and complete an oil and/or gas well on the Morriss 5-1 lease, to have RLBC arrange financing for one-half of the turnkey price for RLBC’s services, and to lease the necessary tangible equipment from RLBC. Accordingly, the Barmet group entered into all the agreements generally used by RLBC in connection with its client drilling program. On December 1,1974, RLBC and the Barmet group executed a drilling contract pursuant to which RLBC agreed to drill and complete a development well on a turnkey basis on the Morriss 5-1 lease (the Morriss 5-1 well). In exchange for the $390,000 turnkey price, RLBC agreed to drill a well to the shallowest of the following depths: (1) 10,000 feet below the surface; (2) such lesser depth at which oil or gas in commercial quantities is discovered; or (3) such lesser depth at which heavy shale, excessive saltwater flow, cavity, or other impenetrable formation is encountered which cannot be penetrated or overcome after good-faith drilling efforts, and thus rendering further drilling impractical. Upon reaching the agreed depth, RLBC must test the well (including log and core analyses) and submit a report to the Barmet group at which time they will have the option to require RLBC to complete the well if it appears that completion will result in production of commercial quantities of oil and/or gas. The turnkey price covers both the drilling and completion of the well, and includes all labor, equipment, material, and supplies necessary for completion, and the cost of all special services such as logging, testing, core analysis, cementing, bracing, fracturing, and perforating. Although the Morriss 5-1 drilling contract calls for payment of the entire turnkey price at the time of execution, the Barmet group did not pay RLBC until December 31, 1974, on which date Petroleum Financial Corp. (PFC),13 a wholly owned subsidiary of RLBC, made arrangements with Wells Fargo Bank, N.A. (Wells Fargo), to finance one-half of the $390,000 turnkey price. On December 31, 1974, PFC delivered an agreement letter to Wells Fargo to induce it to make a loan to the Barmet group in the principal amount of $195,000 which would be evidenced by a promissory note dated December 31, 1974, and payable on or before December 31, 1979, bearing interest at the rate of 7 percent per annum, payable quarterly beginning on March 31, 1975. To induce Wells Fargo to make this loan, PFC made the following promises: (1) To deliver to you [Wells Fargo] a Collateral Pledge Agreement executed by the undersigned. (2) To deliver to you a Certificate of Deposit in favor of the undersigned on your usual form in the amount of $195,000.00 or more, bearing interest at the rate of Five percent (5.0%) per annum, endorsed in blank by the undersigned. (3) To deliver to you a Certified Copy of Corporate Resolution in form satisfactory to you, authorizing execution and delivery of said Collateral Pledge Agreement and endorsement, in blank, and delivery of said Certificate of Deposit. (4) While said Note of Barmet, et al., or any portion thereof remains unpaid, to timely renew and endorse, if necessary, and [sic] Certificate of Deposit issued in lieu thereof, it being understood that the required amount of such Certificate of Deposit may be reduced at its maturity date in direct ratio to the unpaid principal amount of said Note of Barmet, et al., so that the amount of any such Certificate so pledged shall be equal in amount to the unpaid balance of said Note. (5) The undersigned further agrees that the above described Certificate of Deposit shall not and will not be released as collateral for the aforementioned loan of Barmet, et al., without the written consent of Barmet, et al., or until such time as the loan of Barmet, et al., from Wells Fargo Bank, N.A. is paid in full. (6) In the event of any default in the above described note you are authorized and instructed without demand upon or notice to the undersigned to take the necessary steps to liquidate the collateral pledged as security for the above described note and apply the proceeds from such collateral for the repayment of the above described note. (7) Any violation of any of the provisions of the foregoing paragraphs one (1) through six (6) inclusive shall, at your option, make all sum [sic] of principal and interest then remaining unpaid on said Note immediately due and payable, without demand, presentment or notice, all of which are hereby expressly waived. [Underscoring omitted.] Each member of the Barmet group signed this letter indicating acceptance of the provisions contained therein. Wells Fargo agreed to lend the Barmet group $195,000 under the terms set forth in PFC’s letter, and on December 31, 1974, it delivered $58,500 to Burns as his share of the loan proceeds (30 percent of $195,000). Burns immediately deposited his share of the loan proceeds in his personal checking account on which he had written a check dated December 30, 1974, to RLBC in the amount of $117,000 for his share of the total turnkey price (30 percent of $390,000). On December 31, 1974, the Barmet group also executed a promissory note in favor of Wells Fargo in the amount of $195,000 and in accordance with the terms set forth in PFC’s letter. An additional provision contained in the promissory note permits Wells Fargo to accelerate the entire unpaid principal and interest due on the note in the event of default on the quarterly interest payments. At this time, PFC also delivered its certificate of deposit in the amount of $195,000 to Wells Fargo14 and it executed a collateral pledge agreement evidencing its transfer of the certificate of deposit as security for "the payment of all obligations provided for” in the Barmet group’s promissory note. On December 15,1974, the Barmet group and PFC executed an agreement (the December 15, 1974, agreement) containing the following covenants: 1. Barmet, et al. shall apply 50% of the net proceeds from the sale of oil and gas from the said properties [Morriss 5-1 well], after deducting operating expenses and equipment rentals to the payment of the notes which PFC has collaterally guaranteed until such notes have been paid in full. 2. PFC agrees that in the event there is a default in the notes or any of them which it has collaterally secured, that it will apply said Certificates of Deposit to pay said notes and will look only to the 50% of net proceeds from oil and gas production as above set forth, to satisfy Barmet, et al.’s obligations arising out of said promissory notes. It being the intention of PFC to guarantee and it does hereby guarantee Barmet, et al. that there shall be no personal liability under said notes either to Wells Fargo Bank, n.a., PFC or any third person. [[Image here]] 4. Barmet, et al. agrees to execute such further documentation as may be required to place production loans on the property listed, as listed on Schedule "A” [Morriss 5-1 well], providing that Barmet, et al. will not be required to execute any promissory notes with respect to the production loans, and said production loan refinancing shall be used to retire the loans guaranteed by PFC’s cash collateral. RLBC and the Barmet group executed an undated management agreement pursuant to which RLBC agreed to operate and manage15 the Morriss 5-1 well in exchange for a fee equal to 12 percent of the monthly gross gas revenues received by the Barmet group from its working interest. The Barmet group has the right to terminate the management agreement on 30 days’ written notice.16  The final document executed in 1974 was a listing agreement between RLBC, PFC, and the Barmet group dated December 15, 1974.17 The listing agreement provides that if the management agreement is in effect when the promissory note is completely satisfied, then the management fees charged by RLBC thereunder shall be renegotiated. In the event the parties cannot reach a mutually acceptable management fee, then the Barmet group agrees to sell the well immediately or the unitized equivalent interest and to engage RLBC as its exclusive agent for that purpose. In this case, RLBC is to arrange for the sale to an unrelated party and RLBC is to receive a fee of 50 percent of the net sales proceeds as a sales commission. The listing agreement also provides that the Barmet group shall have the right of first refusal on the sale by paying RLBC a "commission” in an amount equal to the commission it would otherwise receive. If the management agreement is not in effect when the promissory note is completely satisfied, then the Barmet group agrees to sell its interest immediately under the same terms as above. Drilling on the Morriss 5-1 well began on December 18, 1974. On December 28, 1974, the Barmet group decided to make a completion attempt. Accordingly, on December 29, 1974, drilling on the Morriss 5-1 well ceased at a total depth of 7,575 feet. On March 23,1975, the completion unit moved onto the well site, and by May 20, 1975, the well had been completed as a gas well. RLBC incurred total actual intangible expenses of $156,005 for third-party costs and services in connection with drilling and completing the Morriss 5-1 well. This figure does not include direct and overhead costs of RLBC, a factor to compensate RLBC for the risks it assumed under the contract, nor any profit to RLBC. On June 30,1975, the Barmet group, as lessees, and PFC, as lessor, entered into an equipment lease agreement with respect to tangible equipment to be used on the Morriss 5-1 lease. Under the 84-month lease, the Barmet group agreed to pay a total rental of $182,091.84, payable in monthly installments of $2,167.76. On August 28,1975, the Morriss 5-1 well was unitized18 with eight other wells drilled and completed by RLBC for Barmet Industries, Inc. Following the unitization, Burns held a unitized interest of 3.3 percent in the nine wells. The Morriss 5-1 well began producing in October 1975. On or about July 31, 1976, RLBC and the Barmet group agreed to certain amendments to the various agreements between them. First, RLBC agreed to a $1,045 reduction in its management fee with respect to the Morriss 5-1 well for the fiscal year ending July 31, 1976; second, RLBC agreed to forgive interest paid by RLBC on the Barmet group’s behalf on the promissory note to Wells Fargo in the amount of $11,640; and third, RLBC agreed to bear primary liability for all future interest due on the note.19  III. The Cantleberry B-l well, the Robinson-Daini B-2 well, the Cantleberry B-A well, and the Robinson-Daini B-3 well.— In 1974, CPC merged with Pacific Oil & Gas Development Corp., and in the process, acquired several mineral leases in an area located in Kern County, Calif., known as Jasmin Field. In 1975, the Jasmin Field was a known oil and gas producing area. As part of its 1975 client energy plan, CPC sold its 100-percent working interest in four separate 10-acre tracts located in the Jasmin Field to clients for $4,000 ($1,000 per tract). (These assignments will be referred to as the Cantleber-ry B-l lease, the Robinson-Daini B-2 lease, the Cantleberry B-4 lease, and the Robinson-Daini B-3 lease.) Petitioners acquired all or part of the working interests in these leases as shown on page 196. [[Image here]] Burns and the Larson group elected to have CPC drill and complete an oil and/or gas well on each of these leases, to arrange financing for one-half of the turnkey prices for CPC’s services, and to lease the necessary tangible equipment from CPC. Accordingly, Burns and the Larson group entered into all of the agreements generally used by CPC in connection with its client energy plan.20  On August 26, 1975, CPC and Burns executed a turnkey completion contract pursuant to which CPC agreed to drill and complete a development well on a turnkey basis on the Cantleberry B-l lease (the Cantleberry B-l well). The rights and obligations of CPC and Burns under the Cantleberry B-l turnkey completion contract parallel the rights and obligations of RLBC and Barmet group under the Morriss 5-1 drilling contract, with three notable exceptions. First, under the Cantleberry B-l turnkey completion contract, CPC agreed to drill a well to the shallowest of the following depths: (1) 4,500 feet below the surface or to a depth sufficient to adequately test the Cantleberry sand of the Lower Miocene formation (which is estimated to be 2,500 feet below the surface); (2) such lesser depth at which oil or gas in commercial quantities is discovered; or (3) such lesser depth at which heavy shale, excessive saltwater flow, cavity, or other impenetrable formation is encountered which cannot be penetrated or overcome after good-faith drilling efforts, and thus rendering further drilling impractical. Second, the $160,000 turnkey price is payable as follows: (1) $40,000 at the time of execution of the turnkey completion contract; (2) $40,000 within 15 days after the well is spudded; and (3) $80,000 at the time Burns directs completion. And third, in the event Burns elects not to -have the well completed, the turnkey price is abated by $80,000. On October 15,1975, CPC and Burns executed the Robinson-Daini B-2 turnkey completion contract. On November 24, 1975, and December 8, 1975, CPC and the Larson group executed the Cantleberry B-4 and Robinson-Daini B-3 turnkey completion contracts, respectively. On October 31, 1975, and November 7, 1975, Burns paid the first two installments required by the Cantleberry B-l turnkey completion contract. On November 7,1975, and November 28, 1975, Burns paid the first two installments required by the Robinson-Daini B-2 turnkey completion contract. These payments were made from Burns’ personal funds. The individual members of the Larson group also paid the first two installments required by the Cantleberry B-4 and Robinson-Daini B-3 turnkey completion contracts from their personal funds.21  CPC began drilling the Cantleberry B-l well on November 1,1975, reached total depth of 2,833 feet on November 5,1975, and placed the well "on pump” on December 9, 1975. Drilling on the Robinson-Daini B-2 well began on November 8, 1975, total depth of 2,887 feet was reached on November 12, 1975, and the well went on pump December 3, 1975. CPC began drilling the Cantleberry B-4 well on November 26, 1975, reached total depth of 2,929 feet on December 6,1975, placed a cement plug from 2,929 feet to 2,890 feet, and placed the well on pump on December 11, 1975. Drilling on the Robinson-Daini B-3 well began on December 9,1975, total depth of 2,775 feet was reached on December 12, 1975, and the well went on pump on December 20, 1975. All four wells are oil wells. CPC incurred total actual intangible expenses of $52,080.27, $84,109.44, $118,383.88, and $42,941.31 for third-party costs and services in connection with drilling and completing the Cantleberry B-l well, the Robinson-Daini B-2 well, the Cantleberry B-4 well, and the Robinson-Daini B-3 well (the CPC wells), respectively. These figures do not include direct and overhead costs of CPC, a factor to compensate CPC for the risks it assumed under the contract, nor any profit to CPC. On November 6, 1975, CPC and Burns executed a management agreement pursuant to which CPC agreed to operate and manage the Cantleberry B-l well in exchange for a fee equal to 15 percent of the gross proceeds from the sale of the production from the well attributable to Burns’ working interest. Both CPC and Burns have the right to terminate this management agreement on written notice to the other. On November 14, 1975, CPC and Burns executed the Robinson-Daini B-2 management agreement. CPC and the Larson group executed the Cantleberry B-4 and Robinson-Daini B-3 management agreements on December 17,1975: On December 17, 1975, CPC made arrangements with Security Pacific National Bank (SPNB) to finance one-half of the $160,000 turnkey price of the Cantleberry B-l, the Robinson-Daini B-2, the Cantleberry B-4, and the Robinson-Daini B-3 turnkey completion contracts. On this date, CPC delivered four bank agreement letters to SPNB to induce it to make two loans to Burns and two loans to the Larson group, each in the principal amount of $80,000. According to the letters, each of these loans would be evidenced by a promissory note dated December 17, 1975, and payable in full on December 17, 1980, bearing interest at the rate of 7 percent per annum, payable quarterly beginning April 1, 1976. To induce SPNB to make the loans, CPC made the same promises to SPNB as RLBC made to Wells Fargo to secure the loan to the Barmet group (see pp. 191-192 supra). Burns and the Larson group also signed these letters indicating their acceptance of the provisions contained therein. SPNB agreed to make the loans under the terms set forth in CPC’s letters, and on December 17, 1975, SPNB transferred $160,000 to Burns and $160,000 to the Larson group.22 Burns and the Larson group used these funds to make the remaining payments due under the Cantleberry B-l, Robinson-Daini B-2, Cantleberry B-4, and Robinson-Daini B-3 turnkey completion contracts. On December 17, 1975, Burns and the Larson group each executed two promissory notes in favor of SPNB in the amount of $80,000, each, and in accordance with the terms set forth in CPC’s letters. At this time, CPC delivered four certificates of deposit in the amount of $80,000, each, to SPNB, and it executed four collateral pledge agreements evidencing its transfer of the certificates of deposit as security for "the payment of all obligations provided for” in Burns’ and the Larson group’s promissory notes.23  On December 17, 1975, CPC executed two collateral agreements with Burns and two collateral agreements with the Larson group. These agreements were designed to serve the same basic purpose as did the December 15, 1974, agreement between RLBC and the Barmet group. The collateral agreements contained the following covenants: 1. OWNER shall apply fifty percent (50%) of the net proceeds (as hereafter defined) from the sale of oil and gas from the leasehold described in Exhibit "A”, and from all other interests in producing leaseholds owned by OWNER and managed by CALLON to the extent that the net proceeds from such other interests are not pledged to secure other loans collateralized by CALLON, to the payment of the loan which CALLON has collateralized until the loan has been paid in full. For the purpose of this agreement only, "net proceeds” means the gross proceeds received from the sale of oil and gas, less taxes levied against the oil or gas, transportation costs, management expenses and equipment rentals. 2. CALLON agrees that in the event of default on the loan LENDER will apply the pledged Certificates of Deposit to retire the loan. OWNER agrees that in the event of default on the loan, other than default resulting from CALLON’s failure to maintain collateral adequate to fully secure the loan at all times, OWNER will transfer and convey to CALLON its entire interest in the leasehold. ***** * * 4. OWNER agrees to execute such further documentation as may be required to place production loans on the property listed in Exhibit "A”, and in all other leaseholds owned by OWNER and managed by CALLON from which fifty percent (50%) of the net proceeds were, are being or are to be applied to the payment of a loan collateralized by CALLON, providing that OWNER will not be required to execute any promissory notes with respect to the production loans, and said production loan refinancing shall be used to retire the loans guaranteed by CALLON’s cash collateral. On December 17, 1975, CPC and the Larson group executed listing agreements pertaining to the Cantleberry B-4 and Robinson-Daini B-3 wells. On December 19, 1975, CPC and Burns executed listing agreements pertaining to the Cantle-berry B-l and Robinson-Daini B-2 wells. The provisions of these listing agreements parallel the provisions of the listing agreement between RLBC and the Barmet group with respect to the Morriss 5-1 well and contain no significant differences. On February 1, 1976, Burns, the Larson group, and others, as lessees, and CPC, as lessor, entered into an equipment lease agreement with respect to tangible equipment to be used on various wells drilled by CPC, including all of the CPC wells. The terms of the lease and the rental payment varied, depending on the specific item of equipment. The parties executed an amendment to the lease on September 1, 1976, to be effective as of February 1, 1976, which provides for an 84-month term and a total rental of $770,792.50, payable in monthly installments of $9,176.10. In addition, each lessee’s share of the rent is listed and each lessee’s liability is limited to his pro rata share. This amendment lists petitioners’ pro rata shares of the total rental payments as follows: Petitioner Percentage Burns . 28.571 Atchison . 3.571 Hawkinson . 2.679 Petitioner Percentage Larson ... . 4.464 Ross . . 10.714 Stokes .. . 0.893 From the time the CPC wells began producing through October 31, 1976, the total net proceeds from the sale of production attributable to petitioners’ working interests were insufficient to pay the total equipment lease rentals. Similarly, 50 percent of the net proceeds during this time was insufficient to pay any interest or principal on the promissory notes. Subsequent to the time the CPC wells were completed and began producing oil, CPC decided to utilize a method of secondary recovery known as steam stimulation to increase production which had thus far been below expectations. Petitioners did not wish to incur the additional expenses involved. Consequently, on November 1, 1976, petitioners sold their respective working interests back to CPC. CPC paid a purchase price for each petitioner’s working interests equal to the total of the turnkey prices of the turnkey completion contracts allocated to each petitioner. CPC transferred cash to each petitioner in an amount equal to the purchase price less the "net loss”24 attributable to each petitioner’s working interests and less the outstanding SPNB indebtedness attributable to each petitioner’s working interests. IV. Treatment by petitioners and the Commissioner. — On his 1974 joint Federal income tax return, Burns deducted $117,000 as intangible drilling costs incurred in connection with the drilling and completion of the Morriss 5-1 well. On his 1975 joint Federal income tax return, Burns deducted $320,000 as intangible drilling costs incurred in connection with the drilling and completion of the Cantleberry B-l and Robinson-Daini B-2 wells. Burns had a net operating loss partially as a result of these deductions. On their 1975 joint Federal income tax returns, the following petitioners deducted the following amounts as intangible drilling costs incurred in connection with the drilling and completion of the Cantleberry B-4 and Robinson-Daini B-3 wells: Petitioner Deduction Atchison ...$40,045 Hawkison ... 30,000 Larson ... ... 50,000 Petitioner Deduction Ross .. . $120,000 Stokes .., . 10,000 In his statutory notices of deficiency, the Commissioner disallowed one-half of each petitioner’s claimed intangible drilling costs on the ground that the bank loans which provided for that portion of the deductions had no economic substance. On February 5, 1981, the Commissioner filed a motion for leave to file amendment to answer, which was granted on February 17, 1981. In his amendment to answer, the Commissioner asserted for the first time two new grounds in support of his position. First, the Commissioner contended that Burns did not own a working interest in the Morriss 5-1 lease in 1974. Second, the Commissioner contended that the portion of the turnkey prices paid for the drilling and completion of the wells was unreasonable to the extent the prices exceeded the actual amounts of cash paid by petitioners. At the conclusion of the trial in this case on February 25, 1981, the Commissioner filed a motion for leave to file amended answers to conform the pleadings to the proof. In this motion, the Commissioner indicated his intention to assert that the transactions between the promoters (RLBC and CPC) and the petitioners constituted joint ventures. Upon due consideration, this Court decided to deny the Commissioner’s. motion to avoid prejudicing petitioners who, although they[ were made aware of the Commissioner’s intention to file this* motion approximately halfway through the trial of this case, would have been unfairly surprised by this new theory. On brief, the Commissioner abandoned the two theories raised in his amendment to answer. ULTIMATE FINDINGS OF FACT The totality of the agreements among the petitioners, the banks, and the promoters resulted in 50 percent of the costs being returned to petitioners and the creation of net profits interests in favor of the promoters. In economic reality, petitioners incurred only one-half of the intangible drilling and development costs of the wells in which they owned working interests. OPINION The sole issue for decision is whether the petitioners’ payments of the full amounts of turnkey oil and gas drilling and completion contracts, under the circumstances of the financing arrangements before us, entitled them to deduct these amounts in full as intangible drilling and development costs (IDCs) under section 263(c)25 and sections 1.263(c)-l and 1.612-4(a), Income Tax Regs. Section 263(c) requires that such costs be incurred by owners of the working interests in order to be deductible. It is undisputed that the petitioners are the owners of the working interests in question. Respondent contends that the agreements between petitioners and the promoters do not reflect the economic substance of what occurred. He maintains that the economic reality resulting from the agreements is that the promoters received 50 percent of the amounts specified in the turnkey drilling and completion contracts in cash and the remaining 50 percent in the form of production payments or net profits interests. Thus, respondent maintains, the petitioners may not deduct IDC expenses in excess of the 50 percent which they paid in cash because (1) they have not actually "paid” any more than this amount for their expenses, and (2) the IDC expenses in excess of those paid for by petitioners were actually incurred by the promoters. Petitioners, on the other hand, assert that the economic substance of the agreements among the petitioners, the banks, and the promoters comports with the form used by the parties to reflect their agreements. They maintain that the loans from the banks should be treated as bona fide and valid debt obligations, that the various agreements among the parties were based upon substantial and legitimate business purposes, and that the transactions were not, as contended by respondent, "tax avoidance schemes.” Therefore, usé of the proceeds of the loans by the promoters entitled petitioners to deductions of 100 percent of the intangible drilling and development costs. Petitioners purchased working interests in oil and gas leases from the promoters. In addition, petitioners entered into drilling and completion contracts (the drilling contracts) with the promoters pursuant to which the promoters agreed to drill, and complete on a turnkey basis, an oil and/or gas well on each lease. As an additional service, the promoters arranged "financing packages” whereby either Wells Fargo Bank, N.A., or Security Pacific National Bank would lend petitioners one-half of the amounts stated in the drilling contracts. To induce the banks to provide this financing, the promoters pledged as collateral for each loan a certificate of deposit equal to the principal amount of such loan. The financing packages arranged by the promoters obligated petitioners to enter into several additional agreements (the term "financing packages” shall refer collectively to the agreements entered into among the parties, which include petitioners, the banks, and the promoters). Petitioners executed promissory notes agreeing to pay the banks the principal amounts of the loans 5 years from the date thereof, plus interest at the rate of 7 percent per annum payable quarterly. Collateral pledge agreements between the promoters and the banks provide that certificates of deposit are pledged as security for all of petitioners’ obligations under the notes. Because the notes specifically require the payment of both principal and interest, the certificates of deposit are security for both the principal and interest obligations on the notes.26 Bank agreement letters provide that when the certificates of deposit mature, they need be renewed only for the amount of the outstanding loan balances. In addition, agreements between petitioners and the promoters provide for repayment of the loans out of 50 percent of the "net proceeds” from the sale of oil and gas from the leasehold.27 Furthermore, the agreements between petitioners and the promoters in the CPC financing packages provide for repayment from all other interests in producing leaseholds owned by the borrowers and managed by CPC to the extent that the net proceeds from such other interests are not pledged to secure other loans collateral-ized by CPC. Under management agreements, the promoters managed the wells for a fee equal to 12 or 15 percent of the gross proceeds from the sale of production attributable to the managed interests. Listing agreements were entered into which provide that, if the management agreement with respect to a given well is in effect when the promissory note with respect to that well is paid in full, then the management fees charged by the promoter will be renegotiated. In the event the management fee cannot be renegotiated or if the management agreement is no longer in effect, these agreements empower the promoters to sell the working interests to unrelated third parties and to receive sales commissions equal to 50 percent of the net sales proceeds. Petitioners rely only upon Frank Lyon Co. v. United States, 435 U.S. 561 (1978). That case involved a sale and leaseback, and not the issue involved herein. Considerable discussion has arisen as to the implications of the language used in the Lyon opinion. It has been quoted widely for its broad language as to substance versus form. Even in the sale-leaseback cases, however, some doubts have been expressed as to whether the Supreme Court was analyzing the facts peculiar to that case or was laying down specific tests to be applied to the facts in other cases. "Thus, it is difficult to pinpoint a general legal proposition for which the case [Lyon\ stands.” Belz Investment Co. v. Commissioner, 72 T.C. 1209, 1226 (1979). Fn. ref. omitted. In approaching the analysis of the facts in this case in light of Lyon, it is appropriate to look to the law of the Courts of Appeals to which the individual cases in the instant consolidated case are appealable. The Burns, Ross, Atchison, and Hawkinson cases are appealable to the Ninth Circuit, and the Larson and Stokes cases are appealable to the Fifth Circuit. The Ninth Circuit, in passing upon the applicability of Lyon to a type "D” reorganization case, commented as follows in Rose v. United States, 640 F.2d 1030, 1035 (9th Cir. 1981), at note 10: In addition, appellants rely heavily on Frank Lyon Co. v. United States, 435 U.S. 561, 98 S.Ct. 1291, 55 L.Ed.2d 550 (1978), in which the Supreme Court, over the objection of the IRS, held that there was a valid sale-and-leaseback transaction for tax purposes where business exigencies, legal relationships, legal obligations, and the competitive environment in addition to tax factors shaped the business transaction. Appellants read Frank Lyon to say a valid business purpose should be considered in determining whether the reorganization or the liquidation rules should apply to a particular transaction. The Government sees Frank Lyon as holding that taxation should be determined on the basis of all the transactions involved. They distinguish Frank Lyon by contending that in that case the Government wanted to disregard the sale-and-leaseback formation while in this case the Government is not avoiding the sale and liquidation structure, but simply treating it as what it is, a Section D reorganization as a matter of law. Frank Lyon concerns an entirely different factual situation and is hardly "dispositive” of this case as appellants claim. Although it considers a valid business purpose to be important, we find that the Government’s interpretation of its application to this case to be correct. Accord Gray v. Commissioner, 642 F.2d 320 (9th Cir. 1981), affg. 71 T.C. 95 (1978). The Court of Appeals for the Fifth Circuit in Gibson Products Co. v. United States, 637 F.2d 1041 (5th Cir. 1981), criticized portions of our holding in Brountas v. Commisioner, 73 T.C. 491 (1979), on appeal (1st Cir., Nov. 23, 1981) and (3d Cir., Nov. 23, 1981). In Brountas, we analyzed a factual situtation virtually identical to that involved in Gibson Products. Petitioners herein do not rely upon Brountas, and respondent does not rely upon Gibson Products. In Brountas, however, we relied upon Lyon as if it set forth specific tests which we then applied, although Brountas was not a sale-leaseback case. In view of the case law existing in the circuits to which the appeals in the instant consolidated cases lie, we will, therefore, first examine the agreements involved herein under the broad approach of substance versus form, an area in which Lyon is but the most recent pronouncement. Lyon is helpful for guidance. Swift Dodge v. Commissioner, 76 T.C. 547, 572 (1981). In 1921, the Supreme Court stated: We recognize the importance of regarding matters of substance and disregarding forms in applying the provisions of the Sixteenth Amendment and income tax laws enacted thereunder. In a number of cases * * * we have under varying conditions followed the rule. [United States v. Phellis, 257 U.S. 156, 168 (1921).] The substance-versus-form rule has been described as "the cornerstone of sound taxation.” Weinert’s Estate v. Commissioner, 294 F.2d 750, 755 (5th Cir. 1961). The doctrine is so well settled and has been so widely applied that no useful purpose would be served by restating again the oft-quoted language of the numerous cases in which the courts have compared the substance of a given transaction with its form. We, therefore, turn to the facts in the instant case to see whether, in substance, the parties created the legal relationships which, in form, they purported to create. Respondent, after conceding a position taken earlier, makes no contention that the sale of the leasehold interests from the promoters to petitioners was in any way unusual or deceptive. Instead, he focuses on the series of agreements which we have, for convenience, referred to as the "financing packages.” Although the dates on which the various agreements were executed would lead almost anyone to believe that the promoters and petitioners were not even concerned about the form of the transactions, we will examine their legal effect as if they had been executed at the appropriate times. (See note 10 in our findings of fact.) In examining the facts before us, we must now decide whether, in economic reality, petitioners incurred intangible drilling and development costs in excess of those allowed by the Commissioner or whether, in economic reality, the promoters and petitioners created net profits interests in favor of the promoters. If we find that net profits interests were created in favor of the promoters, petitioners advance no arguments as to why the claimed deductions for intangible drilling and development costs should be allowed. Numerous Supreme Court cases deal with net profits interests but the tax implications in those cases were not whether a given interest was a net profits interest, but rather whether a given net profits interest was an economic interest entitling its holder to a deduction for depletion. Commissioner v. Southwest Exploration Co., 350 U.S. 308 (1956); Burton-Sutton Oil Co. v. Commissioner, 328 U.S. 25 (1946); Kirby Petroleum Co. v. Commissioner, 326 U.S. 599 (1946); Helvering v. Elbe Oil Land Development Co., 303 U.S. 372 (1938); O’Donnell v. Helvering, 303 U.S. 370 (1938).28 Nevertheless, these cases and others provide sufficient examples which have been used to derive a general definition for the term "net profits interest.” A net profits interest is, for Federal tax purposes, an interest in minerals in place that is defined as a share of gross production measured by net profits from operation of the property. Like the overriding royalty, a net profits interest is created out of the working interest and has a similar duration. Unlike the overriding royalty, the income accruing to the net profits interest is reduced by specified development and operating costs, but the interest bears such expenses only to the extent of its share of the income, and is not required to pay out, advance or become liable for such costs, as is the working interest. If there is no net profit from the operation of the property, the net profits interest owner receives nothing. If there is a net loss from operations, he receives nothing, but is not liable for any share of the loss. Until any accumulated net losses are offset by future net profits from operation of the property, the owner of the net profits interest will receive no income. The interest is regarded as a nonoperating interest in the minerals in place similar to an overriding royalty. [F. Burke & R. Bowhay, Income Taxation of Natural Resources, par. 2.06, at 204-205 (1981).] A share of gross production from a property, measured by net profits from operation of the property. It is carved out of the working interest. A net profits interest is an economic interest in oil and gas and is accordingly entitled to the depletion allowance. [H. Williams & C. Meyers, Oil and Gas Terms 362 (4th ed. 1976).] A net profit agreement is a contract providing that the beneficiary thereof shall receive a stated percentage of the net profits from the operation of the oil and gas property to which the contract refers. As a part of the contract, an accounting arrangement is described in detail which informs the reader of those expenditures deemed expenses for purposes of subtraction from production revenue to arrive at "net profit.” [J. Houghton, Miller’s Oil and Gas Federal Income Taxation, par. 17-1, at 277.] In summary, a mineral net profits interest is exactly what it says it is — an interest in the net profits derived from the extraction and sale of the minerals.29  At first blush, it appears that petitioners paid the promoters 100 percent of the turnkey prices in cash. To facilitate this cash transaction, however, the promoters arranged for the banks to lend petitioners 50 percent of the funds. To induce the banks to make these loans, the promoters pledged certificates of deposit with the banks which were equal to the face amounts of the loans. From the promoters’ standpoint, they received cash equal to 100 percent of the turnkey prices of the drilling contracts and they transferred cash equal to 50 percent of the turnkey prices to the banks. Thus, the promoters received a net increase in their cash position equal only to 50 percent of the turnkey prices. The promoters also received two additional benefits: first, the right to reduce their pledged certificates of deposit as they mature, to coincide with the principal amounts of petitioners’ loans as they are being reduced by payments from 50 percent of the "net proceeds” from the sale of oil and/or gas from petitioners’ wells; second, when the loans are fully repaid, the promoters are entitled to either (1) 50 percent of the net proceeds from the sale of the oil and/or gas from petitioners’ wells, or (2) 50 percent of the net proceeds from the sale of petitioners’ working interests. The first of these additional benefits provides that 50 percent of the net proceeds from the wells will be used to repay the loans until they are repaid in full. This portion of the net proceeds will be used to pay the principal amount of the loans plus 7-percent interest. During the time these payments are being made, the promoters will gain access to the principal amount of the certificates of deposit to the extent the payments reduce the principal amount of the loans, and the promoters will receive interest of 5 percent on the principal amount of the certificates of deposit. The second of these additional benefits provides that when the loans are fully repaid, the management fees between the promoters and petitioners will be renegotiated. Alternatively, if the management agreements are not in effect at this time or if a management fee cannot be renegotiated, the working interests will be sold and the promoters will be entitled to receive 50 percent of the net sales proceeds as commissions. This arrangement demonstrates the fact that even after the loans are repaid, the promoters continue to possess a net profits interest regardless of whether it is measured by the net proceeds from production of oil and gas or the net proceeds from sale of the working interests. The agreements place the promoters in the position of demanding 50 percent of the net profits after the loans have been repaid. The 50-percent net profits interest which entitles the promoters to receive that portion of the proceeds from the sale of oil and gas is the same 50-percent net profits interest which has been used to pay the loan covering 50 percent of the intangible drilling and development costs against which the promoters pledged 100 percent of the collateral. The only purpose served by renegotiation of the management fee or sale of the leasehold at the time of repayment of the loans is to recognize that the promoters continue to have a 50-percent net profits interest and that that interest bears 50 percent of the IDCs. It was that 50-percent interest of the promoters that secured the indebtedness at the banks and that 50-percent interest which was placed at the risk of drilling the wells. If production was inadequate to pay the loans, the certificates of deposit were the assets which would be used to satisfy the loans. If, upon full repayment of the loans, petitioners regained the interests they had in proceeds from the sale of oil and gas prior to the loans, we would not be so inclined to question the substance of the transaction. But this is not what happens. The promoters are in a position to demand and receive the share of production formerly committed to repayment of the loans. This demonstrates that the promoters held a 50-percent net profits interest when the package of agreements was entered into and that the interest continues in them until the sale of the leaseholds. Even then, the promoters receive 50 percent of the net proceeds of the sale of the leaseholds in the guise of a 50-percent commission. As to the 50-percent portion of the IDCs which were disallowed, petitioners, in substance, only lent their names to be used on the promissory notes, except in the case of CPC where other wells were pledged as collateral for the losses. This additional security was merely "window dressing” as to the loans because the banks, at all times, held certificates of deposit equal to the unpaid balances on the loans. When the loans were repaid, petitioners continued to receive only 50 percent of the proceeds from the sale of oil and gas. We hold, in view of the foregoing and under the general principles of form versus substance, that petitioners are entitled to deduct only 50 percent of the amounts prescribed in the turnkey drilling and completion contracts, because net profits interests were created in favor of the promoters and would not constitute payment of IDCs for net profits interests. Having concluded that the agreements result in the creation of net profits interests, we necessarily do not find them to create production payments. It is unnecessary to consider respondent’s alternative theory that, in substance, the transactions constituted sharing arrangements. Our holding is consistent with the avowed purpose of the option to deduct IDCs, i.e., to cover risk, as we stated in Standard Oil Co. (Indiana) v. Commissioner, 77 T.C. 349, 400 (1981), because petitioners had virtually nothing at risk for the financed portion of the IDCs. In Brountas v. Commissioner, 73 T.C. 491 (1979), we tested the transactions by applying the following language from Frank Lyon Co. v. United States, 435 U.S. 561 (1978), and because Brountas is factually similar to the instant case, we feel compelled to similarly do so here. [Where] there is a genuine multiple-party transaction with economic substance which is compelled or encouraged by business or regulatory realities, is imbued with tax-independent considerations, and is not shaped solely by tax-avoidance features that have meaningless labels attached, the Government should honor the allocation of rights and duties effectuated by the parties. [435 U.S. at 583, 584.] First, we inquire as to whether this is a genuine multiple-party transaction. Hilton v. Commissioner, 74 T.C. 305 (1980). The use of a third party in a given transaction may be made in such a way as to give the appearance of importing substance to the transaction but, in reality, the interjection of the third party may be no more than "window dressing.” To examine the role of the banks in the financial package, we turn to the record and find only the testimony of one bank official, a vice president of SPNB, called as a witness by respondent, not by petitioners. She testified that she handled the loans made by SPNB involved here and was familiar with them. The bank made no credit checks on the borrowers (petitioners) nor did they request that the borrowers submit financial statements. She testified, further, that a bank customer in addition to CPC borrowed money under similar circumstances. This additional bank customer was RLBC (the same corporation involved here). She described the collateral as "cash equivalency.” We recognize that by having the promoters fully collateralize the loans, the petitioners borrowed the funds from the banks at a lower rate of interest, another inducement to sell the financial package to prospective investors. The promoters could have lent petitioners 50 percent of the IDCs directly at a lower interest rate and had the loans payable out of 50-percent production, but such a form would have created more suspicion than the manner in which it was carried out. We conclude that the promoters used the banks to conceal the true economic substance of the transaction, that petitioners paid only 50 percent of the IDCs. Therefore, we hold that the agreements among the parties were not genuine multiple-party transactions under the rationale of Frank Lyon, Co. v. Commissioner, supra. We now examine the business purposes upon which petitioners rely. First, they contend that the financing package enabled RLBC to take into income the entire turnkey drilling contract amounts, thus reflecting a large income on its profit and loss statements. This is true, but it would also be true if petitioners had paid cash for the entire amount and arranged their own financing. Petitioners argue that if the promoters had lent part of the drilling funds to petitioners and had taken back a long-term promissory note or production payment, the income figures of the promoters would not be so inflated. That may be true, but as we explained above, in casting the transactions as they did, the parties merely used the banks as a guise for making loans, and in effect (perhaps even unwittingly), created net profits interests. The only testimony as to business purpose was offered through Mr. Burns, one of the petitioners and perhaps the designer of the scheme. He testified about how the entire package had led to the dramatic growth and success of RLBC. That is understandable. When a promoter can offer a deduction against ordinary income in the taxable year of the investment, which is almost twice the amount of the investment, the promoter will undoubtedly be successful. To uphold such a ploy as a justifiable business reason would be foolhardy. We would be compelled to approve all tax shelters, provided they were successful financially to the promoters. In addition to the primary business purpose of enhancing the depiction of profits, petitioners also suggest that a number of other business purposes existed. On brief, petitioners emphasize the fact that the accountants for the promoters advised the promoters that the certificates of deposit securing petitioners’ bank notes could be reflected as assets on the balance sheets with accompanying footnotes to reflect the risk of foreclosure on the collateral. The record supports no finding of fact that this was significant to the success of the promoters’ business. Burns’ testimony focused almost entirely upon the beneficial effect on earnings instead of the effect on net assets. Petitioners also suggest that because the bank loans were nonrecourse loans, unsophisticated investors would consider this as showing that RLBC had confidence in the prospect of successful oil and gas exploration on the properties. Petitioners presented no evidence from investors, except that of petitioner R. L. Burns, who can hardly be called an independent witness. Instead, it is apparent to us that the nonrecourse feature of the bank loans enhanced marketing the tax-avoidance packages to prospective investors because it permitted deductions of almost twice the amounts invested. Petitioners argue that other business purposes applicable to CPC were (1) encouragement of additional management contracts, because such contracts could be required as a condition of the financing packages, and (2) incentives for drilling additional wells. If CPC had financed petitioners’ 50 percent of intangible costs, they could have demanded the management contracts and, in any event, they could have done so without obtaining 50 percent of the net proceeds from the sales of the leaseholds. As to the incentive to drill additional wells, it would be immaterial to the investors whether the nonrecourse loans were financed by the promoters or the banks. And, lastly, petitioner Burns, now cast in the role of an investor, urges that he entered into the group of transactions primarily to obtain an economic return on his investment, rather than to obtain a tax benefit. This argument is specious. How could financing by the bank and collateralizing the loans by the promoters (of which Burns was the prime mover), as distinguished from financing directly by the promoters, affect Burns’ investment objectives? They could not. We find the business purposes to be insufficient and, therefore, insufficient to "encourage” the form of the transaction under Frank Lyon, Co. v. Commissioner, supra. Accordingly, we hold that, in substance, the agreements created 50-percent net profits interests in the promoters, and, therefore, petitioners incurred only 50 percent of the IDCs, and they are entitled to deduct no more than 50 percent of the IDCs provided for in the drilling and completion contracts. In view of other issues which have been settled by the parties, Decisions will be entered under Rule 155.  This case was tried before Judge Cynthia Holcomb Hall. She subsequently resigned from the Court and the case was reassigned to Judge Goffe. None of the parties moved for a retrial in whole or in part.   In amendments to his answer, the Commissioner raised two new issues and determined an additional deficiency of $38,026 in Richard L. Burns and Joyce C. Burns’ 1976 Federal income tax. On brief, however, the Commissioner abandoned these new issues and the increased deficiency.   Joyce C. Burns, Phyliss Ross, Ruth Atchison, Elizabeth G. Hawkinson, Lois S. Larson, and Fiona D. Stokes are petitioners solely by virtue of having filed joint returns with their husbands. Hereafter, references to Burns, Ross, Atchison, Hawkinson, Larson, and Stokes will be to petitioner-husbands.   Prior to a merger with Pacific Oil & Gas Development Corp. in 1974, CPC was a privately held corporation.   The description of RLBC’s client drilling program and of CPC’s client energy plan is based on the program and plan as they were operated in 1974 and 1975, respectively.   A11 wells drilled as a part of RLBC’s program and CPC’s plan were development wells as opposed to wildcat or exploratory wells. That is, the wells were drilled in areas where other producing wells had already been drilled. From its inception in 1969 until the time Burns left RLBC in 1977, RLBC’s client drilling program enjoyed a successful drilling average of approximately 95 percent. A similar average is not available for CPC’s client energy plans.   A turnkey contract is a "contract in which an independent drilling contractor undertakes to furnish all materials and labor and to do all the work required to complete a well in a workmanlike manner, place it on production, and turn it over, ready to 'turn the key’ and start oil [or gas] running into the tanks [or pipelines] for an amount stipulated in the contract.” H. Williams & C. Meyers, Oil and Gas Terms 616 (4th ed. 1976). RLBC did not own or directly operate any drilling or completion equipment. Rather, RLBC hired subcontractors to perform the actual drilling and completion tasks, and RLBC assumed the turnkey risks of the contracts and provided the necessary overhead and supervisory services. The same is apparently also true for CPC.   During Burns’ tenure with RLBC, 100 percent of RLBC’s clients did choose to have RLBC drill and complete the wells and did utilize the financing arranged by RLBC. A similar figure is not available with respect to CPC’s clients.   Clients were not required to lease the tangible equipment from RLBC or CPC, although 75-85 percent of RLBC’s clients did so. Similar figures are not available with respect to CPC’s clients.   Presentation of the facts surrounding the Morriss 5-1 well was made especially difficult by the apparent disregard for accuracy on the part of the involved parties. A brief recitation of some of the conflicting statements contained in various agreements will provide a mere sampling of the parties’ carelessness which resulted in numerous unexplained inconsistencies. For example, the drilling contract is dated Dec. 1,1974, and states that Burns owned 30 percent of the Morriss 5-1 lease and that the turnkey price for the drilling contract was paid on execution. The check with which Burns paid for his 30-percent working interest, however, is dated Dec. 18, 1974, and the only document introduced which evidences an assignment of the Morriss 5-1 lease to the investors is dated May 7,1976, to be effective as of Dec. 15, 1974. In addition, since Wells Fargo did not loan the investors the $195,000 needed to pay the contract price until Dec. 13,1974, it is highly unlikely that the contract price was paid on Dec. 1, 1974. In fact, Burns’ check made payable to RLBC for his share of the contract price is dated Dec. 30, 1974. Moreover, an agreement dated Dec. 15, 1974, between the investors and PFC (a wholly owned subsidiary of RLBC) recites that PFC had already pledged certificates of deposit collateralizing the investors’ promissory note. However, on Dec. 15,1974, the investors had yet to execute a promissory note and PFC had yet to pledge a certificate of deposit as collateral. The confusion continues with the management agreement which, according to the listing agreement, was executed on or before Dec. 15, 1974. The management agreement recites that it was executed at a time after the Morriss 5-1 well had been drilled. The Morriss 5-1 well, however, was not even spudded* until Dec. 18, 1974. In short, the apparent disregard for accuracy on the part of all the parties to the various agreements pertaining to the Morriss 5-1 well rendered a chronological recitation of the facts a virtual impossibility. ‘"Spudding” a well is a term of art in the oil and gas industry which indicates the commencement of drilling operations and is derived from the fact that special equipment is used to begin the drilling of the well.   RLBC did not transfer to the purchasers the entire interest it acquired in these 160 acres under the Morriss lease because it had already assigned a 1 percent overriding royalty interest in the lease to its president, namely, petitioner C. Hayden Atchison. The document reflecting this transfer was not executed, however, until Dec. 30,1974.   Barmet Industries, Inc., and Jacob Pollock were clients of RLBC and are otherwise unrelated to this case. Barmet Industries, Inc., Jacob Pollock, and Burns will be referred to as the Barmet Group.   PFC acted as the financial division of RLBC during 1974 and 1975.   The funds used by PFC to purchase the certificate of deposit were derived from general corporate funds.   The services RLBC promised to render included daily gauging of all production, daily inspection, making necessary repairs, pulling, cleaning, acidizing, treating with chemicals, and disposing of saltwater.   There was an unwritten agreement between RLBC and the Barmet group that the management agreement could not be terminated as long as RLBC was providing financing (i.e., as long as PFC’s certificate of deposit was pledged as collateral). However, as far as the written agreements indicate, there is nothing preventing the Barmet group from terminating the management agreement at any time.   The listing agreement recites that the Barmet group and RLBC had already negotiated for the management of the Morriss 5-1 well and that execution of the listing agreement constituted part of the consideration which induced RLBC to enter into the management agreement. From this recitation, a reasonable person might infer that the parties executed the management agreement sometime prior to the execution of the listing agreement on Dec. 15,1974.   Mr. Burns’ testimony used the term "communitization” rather than unitization. The documents, however, reflect the term "unitization.”   Barmet Industries, Inc., and RLBC also agreed to several other amendments to the agreements.   CPC used standardized forms in its client energy plan. The basic forms used included turnkey completion contracts, promissory notes, bank letter agreements, collateral pledge agreements, collateral agreements, management agreements, and listing agreements. For brevity purposes, we will describe each standardized agreement once, and all future references to such agreements used in connection with CPC’s client energy plan will necessarily be to agreements identical in all material respects to the previously described standardized agreement unless noted otherwise. In addition, reference to a standardized agreement preceded by the name of a specific well (e.g., the Cantleberry B-l bank letter agreement) will be a reference to the specific agreement dealing with that well.   The Larson-group petitioners paid the following amounts as their shares of the first two installments on each turnkey completion contract: Amount Petitioner Cantleberry B — 4 Robinson-Daini B-3 Atchison . $10,000 $10,000 Hawkinson . 7,500 7,500 Larson . 12,500 12,500 Ross . 30,000 30,000 Stokes . 2,500 2,500   The Larson-group petitioners received the following amounts as their shares of the proceeds of each $80,000 loan: Amount Petitioner Cantleberry B-4 Robinson-Daini B-3 Atchison .. $10,000 $10,000 Hawkinson 7.500 7.500 Larson 12,500 12,500 Ross . 30,000 30,000 Stokes .... 2.500 2.500   As required under the bank letter agreements, CPC renewed each pledged certificate of deposit until the corresponding loan was fully paid.   The "net loss” was the total net proceeds from the sales of oil and gas, less management fees, equipment rentals, and interest. These purchase arrangements resulted in CPC’s offsetting the purchase price by (1) the amount of equipment rentals and interest it had previously paid on each petitioner’s behalf, and (2) the outstanding indebtedness to SPNB.   All statutory references are to the Internal Revenue Code of 1954 as in effect during the years in issue.   Petitioners ardently maintain that the certificates of deposit secured only the principal amounts of the notes. Petitioners’ contention in this regard is contrary to the explicit provisions of the collateral pledge agreements and must be rejected.   "Net proceeds” in the financing packages is variously defined as (1) net sales proceeds from the sale of oil and gas, less operating expenses and equipment rentals, or (2) the gross proceeds received from the sale of oil and gas, less taxes levied against such proceeds, transportation costs, management expenses, and equipment rentals.   Net profits interests are not unique to the field of natural resources taxation. See Proesel v. Commissioner, 77 T.C. 992 (1981); Helliwell v. Commissioner, 77 T.C. 964 (1981).   The parties did not raise the question of whether the net profits interests, if any were created, constituted economic interests in the minerals. In order to decide whether the agreements in the instant case resulted in the creation of net profits interests, it is not necessary for us to decide whether the holders of the net profits interests hold economic interests in the minerals. Accordingly, nothing in this opinion should be construed as deciding whether economic interests were created.