McGarvie v. Commissioner

JAMES B. McGARVIE AND CAROL B. McGARVIE, ET AL., 1 Petitioners v. COMMISSIONER OF INTERNAL REVENUE, Respondent McGarvie v. Commissioner Docket Nos. 19119-83; 20904-84; 25383-84; 29285-84. United States Tax Court T.C. Memo 1988-85; 1988 Tax Ct. Memo LEXIS 109; 55 T.C.M. (CCH) 264; T.C.M. (RIA) 88085; February 29, 1988; As amended March 1, 1988 *109 James B. McGarvie, pro se in docket No. 19119-83. John P. Barrie and William E. Cooper, for the petitioners in docket Nos. 20904-84, 25383-84, and 29285-84. Richard A. Witkowski, for the respondent. HAMBLEN MEMORANDUM FINDINGS OF FACT AND OPINION HAMBLEN, Judge: Respondent determined the following deficiencies in Federal income tax in these consolidated cases: Docket Petitioners No. Year Deficiency James B. McGarvie and 19119-83 [1979] $ 4,475.16 Carol B. McGarvie John T. Slattery and 20904-84 [1980] 1,254.28 Patricia A. Slattery Estate of Guy N. Magness, 25383-84 [1980] 1,721.61 Deceased, Ella Mae Magness, Personal Representative, and Ella Mae Magness James Crymes and 29285-84 [1980] 3,461.06 Barbara Crymes After concessions by petitioners and respondent, the issues for decision are (1) solely as to petitioners James B. McGarvie and Carol B. McGarvie, docket No. 19119-83: (a) whether the statutory notice of deficiency was timely mailed to them at their last known address and (b) whether the notice of deficiency was so vague as to be arbitrary and capricious; (2) as to all petitioners: whether the petitioners are entitled to deduct intangible drilling and development costs, depreciation, and investment tax credits *110 in the amounts claimed pertaining to their investments in certain oil and gas well programs for the years in issue. FINDINGS OF FACT Some of the facts have been stipulated and are found accordingly. The stipulations of facts and attached exhibits are incorporated herein by this reference. Petitioners John T. Slattery and Patricia A. Slattery (hereinafter jointly referred to as the Slatterys) resided in St. Louis, Missouri, at the time they filed their petition with the Court; petitioner Ella Mae Magness resided in St. Louis, Missouri, at the time she filed her petition with the Court; 2*111 petitioners James Crymes and Barbara Crymes (hereinafter jointly referred to as the Crymeses) resided in Saint Cloud, Florida, at the time they filed their petition with the Court; and petitioners James B. McGarvie and Carol B. McGarvie (hereinafter jointly referred to as the McGarvies) resided in Kirkwood, Missouri, at the time they filed their petition with the Court. Issue 1 For the 1979 tax year, the McGarvies timely filed a joint U.S. Individual Income Tax Return, Form 1040, showing thereon as their home address, 732 Coral Way #6, Coral Gables, Florida (the "Coral Gables address"). In form letter 1189 (DO) (Rev. 9-78) dated Feb. 25, 1983, and directed to the McGarvies at 1700 N. Woodlawn Avenue, St. Louis, Missouri (the "Woodlawn Avenue address"), the District Director, Internal Revenue Service, Jacksonville, Florida, stated that the IRS was examining the 1979 "Byron Oil Inc. Inc." partnership or trust return. This letter further stated that McGarvies were a member of the partnership or trust for 1979 and that, as a result of its examination, the IRS proposed adjustments to the partnership or trust return which, if determined to be valid, would affect the McGarvies' individual tax return. The form letter requested that the McGarvies sign and return all copies of an enclosed Consent Form 872-A to extend for 1979 the limitation period prescribed by law for refunding overpayments or determining additional tax. On March 3, 1983, McGarvie 3 purportedly mailed to the Internal Revenue Service an "offer" to extend the statute of limitations *112 on assessment for 1979. This purported "offer" consisted of a letter dated March 3, 1983, with enclosures, 4 directed to Mr. C. Arden, Internal Revenue Service Center, P.O. Box 35045, Jacksonville, Florida 32202. McGarvie's March 3rd letter stated that he had modified the attached consent Form 872-A(C) "so as to limit its operation to matters related to Byron Oil partnerships." The letter used as a return address 147 (or 177) Maple Hill, Kirkwood, Missouri 63122 ("the Maple Hill address"). The letter did not state that the Maple Hill address was the address to which respondent was to send all future communications to the McGarvies. The Form 872-A(C) attached to McGarvie's March 3rd letter was not modified to indicate that *113 the Woodlawn Avenue address was incorrect or that the Maple Hill address was the then proper address for the McGarvies. No evidence was adduced at trial regarding the address or addresses used by the McGarvies on any Federal income tax returns filed with the Internal Revenue Service after April 14, 1980, the date they signed their 1979 tax return, or, except as noted below, on any other correspondence sent by the McGarvies to the IRS or sent by the IRS to the McGarvies. The record does not show when the McGarvies moved from the Coral Gables address, nor when they moved to and from the Woodlawn Avenue address, nor when they moved to the Maple Hill address. The record also does not show when and under what circumstances the IRS learned of the Woodlawn Avenue address. Respondent submitted postal form 3877 certifying that on April 14, 1983, respondent mailed statutory notices of deficiency to the McGarvies pertaining to their 1979 tax year addressed to them at the Coral Gables address and the Woodlawn Avenue address. The U.S. Post Office initially attempted to deliver the notice of deficiency to the McGarvies at the Woodlawn Avenue address on April 20, 1983. The record does not show *114 whether this attempted delivery was of the notice mailed to the Coral Gables address, the Woodlawn Avenue address, or both. The McGarvies actually received the notice of deficiency no later than April 29, 1983. 5*115 The McGarvies' petition for a redetermination of the 1979 deficiency was filed timely with this Court on July 11, 1983. Attached to this petition was a copy of the notice of deficiency mailed to the McGarvies at the Woodlawn Avenue address. Issue 2 Petitioners participated in drilling oil and gas wells promoted by Byron Oil Industries, Inc. (hereinafter referred to as "Byron Oil") for the years in issue as indicated below: Percentage Purchase Investor Well Share Price Year James B. McGarvie (a) Jean Ehler #2 1.5 $ 6,300 [1979] DKT No. 19119-83 (b) Ernest P. 1.5 6,300 [1979] Zarlengo #3 John T. Slattery McElwain #12 1.5 6,575 [1980] DKT No. 20904-84 Guy N. & Ella Mae Wyman #1 1.5 6,300 [1980] Magness DKT No. 25383-84 Barbara J. Crymes (a) McElwain #13 .375 1,643.75 [1980] DKT No. 29285-84 (b) Jean Ehler #1 .375 1,643.75 [1980] (c) Jaccobucci #5 .375 1,643.75 [1980] (d) N. Colorado #5 .375 1,575.00 [1980] 1.5 $ 6,506.25 Byron Oil, solely owned by Alan J. Byron, is a Missouri corporation formed for the purpose of acquiring, developing, and operating oil and gas properties. It was experienced and skilled in selecting potential oil and gas properties for development, negotiating drilling contracts, completion *116 contracts, and contracts for related services, purchasing oil and gas field equipment, and supervising the drilling, completion, and operation of oil and gas wells. During the years in issue, Byron Oil conducted substantially all of its exploration and production activities through the offering of participative interests organized as tenancies-in-common. Alan J. Byron ("Byron") has been the president, sole shareholder, and a director of Byron Oil since its incorporation on February 19, 1974. Prior to incorporation, Alan J. Byron conducted business as "Alan J. Byron, d/b/a Byron Oil Industries." Starting in 1972, Byron Oil Industries, began to acquire various oil and gas leases in the Wattenberg Oil and Gas Field (the "Wattenberg Field") located in Adams and Weld Counties, near Denver, Colorado. Over the years, it acquired around 8,000 acres. With respect to the oil and gas leases obtained, Byron Oil incurred expenses for title searches and geological determinations. All of the wells in issue are located in the Wattenberg Field. The Wattenberg Field in the years in issue comprised approximately 978 square miles. Byron Oil drilled approximately 106 wells in the Wattenberg Field, *117 substantially all of which were drilled to the Sussex formation. The Sussex formation is sandstone with very low permeability that is partially filled with clays. It is a very tight, consolidated sand that will not produce without stimulation. The thickness and porosity and the other physical features of this sand vary substantially from location to location. The formation is approximately 5,000 to 5,500 feet deep. None of the wells drilled to the Sussex formation were dry wells; however, some wells were very marginal producing wells. Byron Oil completed all of the Sussex wells it offered to investors. All of the wells in issue were drilled to the Sussex formation. All of the Sussex wells were drilled to approximately the same depth and had the same geological formation. The drilling and completion risks were generally the same for all of the wells. The nonproducing participating interests sold by Byron Oil were the right to minerals in place in the Sussex formation in the Wattenberg Oil and Gas Field on property on which no development had occurred, and after development, the right to share in the minerals produced from the Sussex formation. Purchasers of interests did not obtain *118 any interest in the lease covering the property. These leases were owned by Byron Oil. The offer and sale of interests in each well in issue was made under an exemption from registration pursuant to a filing of a Regulation B, Schedule D offering sheet with the Securities and Exchange Commission pursuant to Section 3(b) of the securities Act of 1933, as amended. For the years in issue, a Regulation B offering could not exceed $ 250,000. Byron Oil made sales of interests to the public through offering documents (sometimes hereinafter referred to as the "prospectus") which contained, among other items, an outline of the terms of the offering, a copy of the Schedule D offering sheet, a geological report, an assignment of participating interest form, an operating agreement, an accounting procedure form, and a remittance receipt form. In addition to Federal filings, each of the offerings was registered with the Missouri Securities Division pursuant to Section 409.304 of the Missouri Uniform Securities Act. Each prospectus stated that the securities had not been approved or disapproved by the Commissioner of Securities of the State of Missouri nor had the division passed upon the accuracy *119 or adequacy of the prospectus. With respect to each of the wells, there was a landowners' royalty and/or overriding royalties of approximately 30 percent. Of the remaining 70 percent, if all the interests offered for sale were sold, Byron Oil retained approximately 43 percent and the investors purchased approximately 57 percent. The offering of interests with respect to each of the petitioners followed the same general pattern. Byron Oil offered to sell 38 interests in an oil and gas well to be drilled on a lease it owned. Each 1.5 percent interest offered was equal to 1/67th of a working interest which provided the investor with 1/67th of 70 percent (more or less) of the total production from the well. On occasion, as was the case with Barbara Crymes, an investor was permitted to purchase less than a 1.5 percent interest in a particular well. The 1.5 percent fractional interest entitled an investor to approximately one barrel out of every 96 barrels of oil and 1,00 cubic feet of gas out of every 96,000 cubic feet of gas produced from the well. The working interests in the oil and gas wells were sold through Alan J. Byron, Inc., a dealer-broker 100 percent of which was owned *120 by Alan J. Byron. Byron Oil paid commissions to third party sales representatives of 10 percent for the sales of the working interests in the oil and gas wells. Each offering by Byron Oil separately stated the cost of an interest with respect to the drilling of a well to the casing point and, if the well was deemed to be commercially producible, a separate cost to the investor for the completion of the well. The offering material made no specific allocation of the purchase price to the value of the working interest, or to intangible drilling costs, depreciable property to be provided, or other services to be performed by Byron Oil. Petitioners could not negotiate the total price to be paid for their investment, the manner in which their investment would be allocated, or any other terms of the agreement between themselves and Byron Oil, including the portion allocable to IDC, tangible equipment costs, and the value of the working interest. Petitioners paid no additional amount for the value of the working interest. Pursuant to the terms of the offering, to the extent that actual costs incurred by Byron Oil for the drilling and completion of an oil and gas well were less than the amounts *121 paid by the investors, the investors paid 100 percent of the drilling, completion, and tangible equipment costs. In the event the actual drilling or completion costs were less than the amounts paid by the investors, the excess became the property of Byron Oil. In the event that the actual drilling or completion costs were more than the amounts paid by the investors, the excess costs were the sole responsibility of Byron Oil. 6*122 *123 *124 *125 *126 *127 Byron Oil was compensated for its services as operator of the wells on a monthly, per-well basis. Any unusual costs of operation, such as reworking or recompleting *128 the well were directly chargeable to the working interests on a fixed cost basis. Byron Oil entered into "no-out completion through the tanks" turnkey contracts with the investors. For each well, the contract provided that Byron Oil would be responsible for all the drilling, completion, installation of the pipelines, valves, pit, meters, underground line, and heater treater, and the tanks, stairways, loft ways, landscaping, burning, painting, and all the cleanup work involved in exchange for a fixed price paid by the investors. Any costs over the fixed amounts paid by the investors were paid by Byron Oil. The estimated costs set forth in the prospectuses did not separately specify general and administrative costs, or a cost for the risks undertaken by Byron Oil in entering into the "no-out completion through the tanks" turnkey contract, or for a profit for Byron Oil as the drilling and completion contractor. The prospectuses informed the investors that the estimated costs set forth were substantially greater than the average industry costs in the area. The purchase price Byron Oil charged the investors was in excess of the total estimated costs itemized in the prospectuses. Byron *129 Oil hoped to make a profit from the sale of the nonproducing participating interests. It hoped to receive this anticipated profit from a combination of cash from the investors and production out of its 43 percent retained interest. Byron Oil hoped to make a profit on the drilling and completion itself, irrespective of its retained 43 percent interest. It was willing to take the risk of losing substantial amounts of money on the "no-out completion through the tanks" turnkey contracts with the hope that, by drilling a large number of wells, any losses would be recouped over the years through its retained interest in productive wells. It also hoped that production from the wells would compensate it for the large risks undertaken through entering into these no-out turnkey contracts. Byron Oil calculated a 75 percent risk factor in the drilling and completion of a well to the Sussex formation and approximately a 25 percent profit factor, for a total markup on each well of approximately 100 percent, which it hoped to receive out of the production of the wells. It takes approximately six months from the time a decision is made to drill a particular well to the time the rig is moved onto *130 the site for the drilling. During this period, among other things, Byron Oil would obtain expert opinions from attorneys as to title matters and geologists as to site location; determine the estimated third-party costs of drilling and completing the well; and prepare the prospectus on the proposed well. Byron Oil subcontracted most of the work in drilling and completing the wells. It entered into a turnkey contract with the drilling contractor selected for each well in issue which provided a specified price to drill the well to a specified depth. These contracts had some limitations which could result in Byron Oil's paying amounts in excess of the turnkey contract price. In drilling a well, Byron Oil would use anywhere from 10 to 20 different subcontractors. Byron Oil had its own production people on the site during drilling. There were usually one or two Byron Oil employees on the site most of the time. No direct charge was made to the investors for these employees' being on the site. The Exeter Drilling Company subcontracted the drilling of some of the wells Byron Oil drilled in 1980, including the Wyman #1 well, one of the wells in issue. The turnkey contract included the *131 drilling of the well, road location and dirt work (with an $ 800 limitation), drilling mud and chemicals (with some limitations), and rig time for testing and circulating. Mr. Donald Langer ("Langer"), controller for Exeter Drilling Co., testified that their bid contract price for the Wyman #1 well was $ 43,500, and the actual price, including cost overruns, was $ 45,100. The estimated costs included on the prospectus for these services were as follows: Services Estimate Road, location, and dirt work $ 1,000 Drilling to 5,300 feet 48,000 Drilling mud and chemicals 1,500 Rig time for testing, circulating, waiting, etc. * 1,000 Total $ 51,500 Oil and gas drilling ventures are highly speculative. There is no assurance that oil can be found or that, if found, it will be of sufficient quantity or quality so as to be economically recoverable and marketable. There also are various drilling and completion risks involved in oil and gas ventures, including weather uncertainties and potential problems with equipment availability, the "fracing" process, 7 the cementing process, and mechanical *132 problems. Andrew J. Pfaff ("Pfaff"), a senior petroleum engineer retained as an expert witness by petitioners, testified that, in his opinion, for 1980 as a risk factor he would add $ 50,000 to $ 60,000 to the estimated costs of a well being drilled to the Sussex formation. Pfaff did not testify as to the reasonableness of the estimated costs set forth in the Schedule D offering sheet for the wells in issue. The estimated cost of drilling and completing the wells in issue, actual costs incurred by Byron Oil in drilling and completing these wells, exclusive of any offering or sales cost to Byron Oil and any general and administrative expenses incurred in connection with the programs, and the total amount received from the investors for these wells were as follows: Total Estimated Total Actual Total Amount Drilling & Drilling and Received Completion Completion From Well Costs Costs Investors Jean Ehler #2 $ 196,500 $ 164,282 $ 239,400 Ernest P. 196,500 165,624 239,400 Zarlengo #3 McElwain #12 215,800 191,977 249,850 Wyman #1 196,500 205,345 239,400 McElwain #13 215,800 230,472 249,850 Jean Ehler #1 215,800 242,546 249,850 Jaccobucci #5 8*133 215,800 213,423 249,850 North Colorado #5 196,500 233,100 232,100 For the wells in issue, Byron Oil advised the investors for income tax purposes to treat their investments as follows: Intangible Drilling Tangible Investor Well Investment Costs Costs McGarvie Ehler #2 $ 6,300.00 $ 4,244.78 $ 2,075.22 Zarlengo #3 6,300.00 4,219.11 2,080.89 $ 12,600.00 $ 8,443.89 $ 4,156.11 Slattery McElwain #12 $ 6,575.00 4,439.44 2,135.56 Magness Wyman #1 $ 6,300.00 4,231.71 2,068.29 Crymes McElwain #13 $ 1,643.75 $ 1,068.44 $ 575.31 Ehler #1 1,643.75 1,068.44 575.31 Jaccobucci #5 1,643.75 1,068.44 575.31 N. Colorado #5 1,575.00 1,023.75 551.25 $ 6,506.25 $ 4,229.07 $ 2,277.18 For the wells in issue, each of the petitioners claimed the following deductions, credits, and losses from their investment: Intangible Drilling Investment Petitioners Costs Depreciation Tax Credit Loss McGarvie $ 8,433.89 $ 155.78 $ 415.61 $ 8,006.62 Slattery 9*134 1,839.44 597.96 213.56 2,437.40 Magness 4,231.71 103.41 206.83 4,004.36 Crymes 4,229.00 136.00 227.72 4,365.00 Each of the petitioners was on the cash receipts and disbursements method of accounting. Each of the petitioners elected to be excluded from Subchapter K pursuant to the provisions of section 761(a)(2) of the Internal Revenue Code. 10 Each of the petitioners made an election on their respective 1979 or 1980 income tax returns to deduct currently, as expenses, all expenditures for intangible drilling and development costs of oil and gas wells, as provided in section 263(c). Of the actual drilling and completion costs incurred by Byron Oil for each of the wells at issue, the parties have stipulated that 61.44 percent is attributable to intangible drilling costs and 38.56 percent is attributable *135 to tangible costs. In the notice of deficiency mailed to the McGarvies, respondent disallowed the loss of $ 8,006.62 and the investment tax credit of $ 415.61 claimed by the McGarvies pertaining to McGarvie's investment in the oil and gas wells in issue. In the notice of deficiency to the Slatterys, respondent disallowed a loss of $ 2,557.86 claimed by the Slatterys, pertaining to John Slattery's Byron Oil investment 11*136 but respondent did not disallow the investment tax credit of $ 213.56 also claimed for the oil and gas wells in issue. In the notice of deficiency to the Magnesses, respondent disallowed $ 2,339.25 of the $ 4,231.71 in intangible drilling costs, $ 53,92 of the $ 103.41 in depreciation, and $ 88.06 of the $ 206.83 in investment tax credit claimed for their investment in the oil and gas wells in issue. In the notice of deficiency to the Crymeses, respondent disallowed the loss of $ 4,365 and the investment tax credit of $ 227.50 claimed by the Crymeses pertaining to Barbara Crymes' investments in the oil and gas wells in issue. OPINION Issue 1 First we will address the issue raised by the McGarvies regarding the validity of the notice of deficiency mailed to them. The McGarvies contend that the notice of deficiency was not addressed to them at their "last known address" as required by section 6212(b)(1) and, hence, is not valid. They additionally maintain that the notice was mailed after the expiration of the statutory period for assessing the tax. Consequently, they contend, the Internal Revenue Service is precluded from assessing the amount of tax in issue as to them. Respondent contends that the notice of deficiency was mailed to the McGarvies at their last known address. Alternatively, respondent asserts that, inasmuch as the McGarvies actually received the notice of deficiency, they are not prejudiced even if the notice was misaddressed; consequently the notice of deficiency was effective to suspend he running of the statutory limitation for assessing the tax. We find that the McGarvies did not meet their burden of proving that the notice of deficiency was not mailed timely, or that they were prejudiced by any delay in receiving the notice of deficiency, *137 or that they provided respondent with clear and concise notification of any change of address. The McGarvies contest the validity of the notice of deficiency on a number of grounds. One argument they set forth is that respondent failed to mail the notice of deficiency within the period required by law. Section 6501(a) requires that a deficiency in income tax be assessed within three years after the return is filed. Section 6503(a), however, further provides that the running of this three-year period of limitations is suspended by the mailing of a notice under section 6212(a). Section 6212(a) authorizes the secretary or his delegate to send a notice of deficiency "to the taxpayer by certified mail or registered mail." Section 6212(b)(1) further provides that a notice of deficiency "shall be sufficient" if the notice is mailed to the taxpayer at his "last known address." Thus, a notice of deficiency properly addressed to the taxpayers at their last known address is sufficient to suspend the running of the statutory period for assessing a deficiency even if the taxpayers never receive that notice. Mollet v. Commissioner,82 T.C. 618, 623-624 (1984), affd. without published opinion *138 757 F.2d 286 (11th Cir. 1985). The McGarvies timely filed their 1979 tax return. Therefore, pursuant to section 6501, absent one of the enumerated exceptions, none of which apply here, unless respondent timely issued a statutory notice of deficiency pursuant to section 6503(a), the time for assessing the additional tax expired on April 16, 1983. Petitioners contend that respondent mailed the statutory notice to them on April 18, 1983.12 Respondent introduced into evidence postal form 3877, dated and signed on behalf of the postmaster, to establish that the statutory notice of deficiency was mailed on April 14, 1983. This evidence is sufficient to [Text Deleted by Court Emendation] establish that the notice was mailed timely absent contrary evidence. United States v. Zolla,724 F.2d 808, 810 (9th Cir. 1984), cert. denied 469 U.S. 830 (1984); Cataldo v. Commissioner,60 T.C. 522, 524 (1973), affd. 499 F.2d 550 (2d Cir. 1974). Petitioner submitted no evidence to establish a different date for the mailing of the notice of deficiency. Therefore, we find that the notices of deficiency mailed to the McGarvies at the Coral Gables address and the North Woodlawn Avenue address were mailed *139 on April 14, 1983. The McGarvies next contend that the statutory notice of deficiency is invalid, and hence not sufficient to suspend the running of the three-year period of limitations, because the notice was not mailed to them at their "last known address." There is no statutory definition of the "last known address." This Court, however, has defined, "last known address" as the taxpayer's "last permanent address or legal residence known by the Commissioner or the last known temporary address of a definite duration to which the taxpayer has directed the Commissioner *140 to send all communications." Tadros v. Commissioner,763 F.2d 89, 91 (2d Cir. 1985), affg. an unreported order of this Court, and quoting Alta Sierra Vista, Inc. v. Commissioner,62 T.C. 367, 374 (1974), affd. without published opinion 538 F.2d 334 (9th Cir. 1976). In other words, the "last known address" is "the address to which, in light of all the facts and circumstances, respondent reasonably believed the taxpayer wished the notice of deficiency to be sent." Frieling v. Commissioner,81 T.C. 42, 49 (1983). The relevant inquiry is to what respondent knew at the time of mailing the statutory notice rather than to what may in fact be the taxpayer's most current address. Mollet v. Commissioner,82 T.C. at 624. Normally, a taxpayer's "last known address" is the address used on this tax return. However, respondent is required to use a different address if he learns, or is advised by the taxpayer, that the taxpayer has changed his address. O'Brien v. Commissioner,62 T.C. 543, 549 (1974). In addition, respondent must exercise reasonable diligence in attempting to ascertain the taxpayer's correct address. The taxpayer has the burden of proving that respondent did not exercise this *141 reasonable diligence. Cyclone Drilling, Inc. v. Kelley,769 F.2d 662, 664 (10th Cir. 1985); Ramirez v. Commissioner,87 T.C. 643, 650 (1986). Furthermore, the taxpayer has the burden of providing respondent with clear and concise notification of his new address. Pyo v. Commissioner,83 T.C. 626, 636 (1984). "'Clear and concise' notice is notice by which the taxpayer indicates to the IRS that he wishes the new address to replace all old addresses in subsequent communication." Cyclone Drilling, Inc. v. Kelley,769 F.2d at 664 (emphasis in original). Nonetheless, even if the statutory notice of deficiency is not sent to the "last known address," the notice still is effective from the date of mailing where the taxpayer receives actual notice of the deficiency with sufficient time remaining to file a petition in this Court. Pugsley v. Commissioner,749 F.2d 691, 693 (11th Cir. 1985), affg. an unreported order of this Court; Frieling v. Commissioner,81 T.C. at 57. The question of whether a taxpayer has been prejudiced by an improperly addressed notice if factual in nature. Looper v. Commissioner,73 T.C. 690, 690 (1980). This Court found that a notice of deficiency actually received *142 16 days after mailing was effective when mailed, Mulvania v. Commissioner,81 T.C. 65 (1983), while a notice received with 16 days left within which a file a petition with this Court was prejudicial. Looper v. Commissioner, supra. Here, the McGarvies timely filed a petition with this Court of July 11, 1983 -- two days before the expiration of the time for its filing. We have found that the McGarvies actually received the statutory notice of deficiency no later than April 29, 1983. The McGarvies, thus, received actual notice of the deficiency within sufficient time to file a petition with this Court. Consequently, the delay in a delivery of the notice was not prejudicial. Since we have found that the McGarvies received actual notice of the deficiency without prejudicial delay, it is unnecessary to decide whether the statutory notice of deficiency was mailed to their "last known address." 13*143 The McGarvies further challenge the validity of the notice of deficiency on several grounds: that it was based on a nonexistent report; the subject of their tax liability was then being discussed with unauthorized persons; the notice was so garbled that they could not make heads or tails of it; and, the notice referred to a partnership in which they were not involved. Thus, the McGarvies assert, the statutory notice of deficiency was insufficient to properly apprise them as to the matters in issue and, hence, is arbitrary and capricious and should be invalidated. Respondent, on the other hand, argues that, although the supporting statements did contain some errors, these errors were inconsequential since the written explanation of the adjustments provided adequate information *144 to inform the McGarvies about the type of adjustments respondent intended to make. We agree with respondent on this matter. The McGarvies have the burden of proving that the notice of deficiency is arbitrary, excessive, or without foundation. Helvering v. Taylor,293 U.S. 507 (1935); Rule 142. No particular form is required for a notice of deficiency. All that is required is that the notice provide formal notification that a deficiency in tax has been determined. Stamm International Corp. v. Commissioner,84 T.C. 248, 252-253 (1985). The purpose of the notice is to advise a taxpayer that "the Commissioner means to assess him; anything that does this unequivocally is good enough." Olsen v. Helvering,88 F.2d 650, 651 (2d Cir. 1937). Here, the notice of deficiency advised the McGarvies that respondent intended to disallow the investment tax credit and loss reported on Schedule E of their 1979 tax return relating to Byron Oil Industries, Inc., in the amounts claimed on their return. Any errors contained in the notice of deficiency and its supporting schedules did not mislead the McGarvies as to the nature or amount of the respondent's adjustments. These errors do not make the statutory *145 notice arbitrary or capricious, or render the notice invalid. See Campbell v. Commissioner, 90 T.C. (January 25, 1988). The McGarvies' other assertions challenging the validity of the statutory notice ask us to look behind the notice. As a general rule, this Court will not look behind the notice of deficiency to examine the evidence used, the propriety of respondent's motives, the administrative policy, or the procedure followed by respondent in the determination of a notice of deficiency. Dellacroce v. Commissioner,83 T.C. 269, 280 (1984); Riland v. Commissioner,79 T.C. 185, 201 (1982); Llorente v. Commissioner,74 T.C. 260 (1980), affd. in part, revd. in part, and remanded in part 649 F.2d 152 (2d Cir. 1981); Jackson v. Commissioner,73 T.C. 394 (1979); Greenberg's Express, Inc. v. Commissioner,62 T.C. 324, 327 (1974). The underlying rationale for the foregoing is the fact that a trial before this Court is a proceeding de novo. Greenberg's Express Inc. v. Commissioner,62 T.C. at 328. We decline here to deviate from this general rule. Thus, we find that the statutory notice of deficiency was not arbitrary or capricious, and is valid. Issue 2 We now will address the substantive *146 issue involved in these consolidated cases, i.e., whether petitioners 14 are entitled to deduct intangible drilling and development costs, depreciation, and investment tax credits in the amounts claimed pertaining to their investments in certain Byron Oil oil and gas well programs. On their respective tax returns for the years in issue, petitioners claimed investment tax credits and losses on Schedule C, Profit or Loss From Business or Profession (Crymes), or on Schedule E, Part II, Rent and Royalty Income or Loss (McGarvie, Slattery, and Magness), with respect to their investments in the Byron Oil oil and gas well programs in issue. In the respective notices of deficiency issued to petitioners Crymes, McGarvie, and Slattery, respondent disallowed all of the losses claimed *147 relating to these programs. In addition, respondent disallowed the related investment tax credit claimed by petitioners Crymes and McGarvie. The explanation for the disallowance of these losses and investment tax credit was that petitioners had not established that they incurred a deductible loss for the applicable year. In the notice of deficiency issued to the Magnesses, respondent allowed the Magnesses to deduct a portion of the loss claimed relating to their investment in a Byron Oil oil and gas well program. Respondent also allowed a portion of the related investment tax credit claimed by the Magnesses related to this program. The explanation for the disallowance of a portion of the loss and investment tax credit was that the fractional share of the working interest in the program acquired by the Magnesses in exchange for a contribution to the drilling and development of the oil and gas well was less than the fractional share of the drilling and development costs (hereinafter referred to as "IDC") paid for by their contribution. Therefore, only the share of the IDC attributable to their fractional interest in the property was deductible. The remainder of their investment *148 had to be capitalized as the cost of acquiring their fractional interest in the property. In addition, respondent stated that the deductible IDC were limited to the reasonable costs of drilling and the IDC claimed by the Magnesses and based on Byron Oil's estimated costs of drilling and development of the well were not reasonable costs. Respondent computed the allowable deduction by multiplying the total amount incurred for IDC for the well, as determined by respondent, by one and one-half percent (the fractional interest held by the Magnesses). The amount of the allowable depreciation deduction similarly was reduced based on a corrected basis for tangible costs as determined by respondent. Petitioners now agree that the amount of the allowable intangible drilling cost deduction and the allocable amount of the tangible property basis is limited to an amount equal to each of the petitioner's percentage interest in the particular well. Sec. 1.612-4, Income Tax Regs. Respondent agrees that petitioners McGarvie, Slattery, and Crymes are entitled to deduct the portion of the losses and investment tax credit for the wells in issue which is attributable to their fractional interest in *149 the particular well. The parties do not agree, however, on the amount of the IDC and tangible equipment costs upon which the fractional interest is to be applied. Petitioners submit that the issue really is what is the amount of the intangible and tangible costs associated with this particular arrangement that would be charged by a third-party in a similar turnkey arrangement without the retention of the 43 percent interest. Petitioners contend that in computing the amounts allowable as deductions for intangible drilling costs and depreciation and investment tax credit, the computation should be based on the total of Byron Oil's estimated costs to drill and complete the particular well, as contained in the offering documents, plus an amount to reflect overhead and administration costs attributable to each well, plus an amount to reflect the risk factor inherent in a "no-out turnkey" contract, and plus an amount representing a reasonable profit factor to Byron Oil. Respondent on the other hand contends that the investors purchased more than just a "turnkey to the tanks" drilling contract from Byron Oil. He argues that petitioners also purchased a working interest in the oil and gas *150 wells and an operating agreement with Byron Oil. Respondent takes the position that the actual drilling and completion costs, as stipulated by the parties, are the amounts which are properly allocated, under the evidence, to the drilling and completion contract and that the remainder of the cash received from the investors, if any, is properly allocated to the working interest obtained, the sales commissions paid, and to the services to be performed by Byron Oil under the operating agreement, and, as such, are includible in each investor's basis of his or her working interest. Respondent further contends that since the investors held only 57 percent of the working interest in the subject wells, but paid 100 percent of the actual drilling and completion costs, the amount of IDC and depreciation to be claimed must be proportionately reduced. Thus, respondent would have this Court sustain the deficiency as determined for the Magnesses and hold the deficiencies in tax be determined under a similar formula for the remaining petitioners. We agree with petitioners that where the drilling and completion contract includes reasonable charges for general and administrative costs relating to *151 the drilling program, a risk factor, and a profit factor, these cost elements are allowable intangible drilling and completion costs. However, after carefully considering all the evidence, we are not persuaded that either petitioners' or respondent's suggested formula results in an amount for the drilling and completion costs which would have been charged by an unrelated third party contractor for a similar "no out completion through the tanks" turnkey contract. Since petitioners have demonstrated that they are entitled to a deduction for IDC but have not substantiated the exact amount to which they are entitled, we have determined an appropriate amount, weighing our judgment heavily against petitioners, however, as they have the burden of proof. See Cohan v. Commissioner,39 F.2d 540 (2d Cir. 1930); Durkin v. Commissioner,87 T.C. 1329, 1397 (1986). In the programs offered by Byron Oil, each investor in any offering agreed to pay a nonnegotiable, fixed price for the drilling of the well and a nonnegotiable, fixed price for its completion in exchange for a one and one half percent working interest in the well. Byron Oil retained a 43 percent working interest in each well. Pursuant *152 to the offering documents, if the total drilling and completion costs exceeded the total amount paid by the investors for that well, the excess costs became the sole obligation of Byron Oil. On the other hand, if the total amount paid by the investors exceeded the total drilling and completion costs, the excess receipts remained the sole property of Byron Oil. In order to participate in the oil and gas well program, each investor had to agree to the terms of the "no out completion through the tanks" turnkey contract with Byron Oil. 15*153 The investors paid no additional amount for their fractional interest in the wells. No part of the purchase price paid by the investors was specifically allocated to the cost of the fractional interest, and the offering document did not allocate the purchase price to intangible drilling costs, depreciable property, or otherwise. Section 263(c)*154 provides that: Intangible Drilling and Development Costs in the Case of Oil and Gas Wells. - Notwithstanding subsection (a), regulations shall be prescribed by the Secretary or his delegate under this subtitle corresponding to the regulations which granted the option to deduct as expenses intangible drilling and development costs in the case of oil and gas wells and which were recognized and approved by the Congress in House Concurrent Resolution 50, Seventy-ninth Congress. * * * Section 1.612-4(a), Income Tax Regs., which was promulgated pursuant to the above authority, provides, in part, as follows: (a) Option with respect to intangible drilling and development costs. In accordance with the provisions of section 263(c), intangible drilling and development costs incurred by an operator (one who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights) in the development of oil and gas properties may at his option be chargeable to capital or to expense. This option applies to all expenditures made by an operator for wages, fuel, repairs, hauling, supplies, etc., *155 incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas * * * includ[ing] the cost to operators of any drilling or development work * * * done for them by contractors under any form of contract, including turnkey contracts. * * * In general, this option applies only to expenditures for those drilling and developing items which in themselves do not have a salvage value. For the purpose of this option, labor, fuel, repairs, hauling, supplies, etc., are not considered as having a salvage value, even though used in connection with the installation of physical property which has a salvage value. Included in this option are all costs of drilling and development undertaken (directly or through a contract) by an operator of an oil and gas property whether incurred by him prior to subsequent to the formal grant or assignment to him of operating rights (a leasehold interest, or other form of operating rights, or working interest); except that in any case where any drilling or development project is undertaken for the grant or assignment of a fraction of the operating rights, only that part of the costs thereof which is attributable *156 to such fractional interest is within this option. In the excepted cases, costs of the project undertaken, including depreciable equipment furnished, to the extent allocable to fractions of the operating rights held by others, must be capitalized as the depletable capital cost of the fractional interest thus acquired. We have interpreted section 1.612-4(a), Income Tax Regs., to mean that the election under section 263(c) is available only respecting expenditures actually made for drilling and developing or completing a well on property in which the operator has a working or operating interest of the same sort as required for the depletion allowance deduction. Cottingham v. Commissioner,63 T.C. 695, 706 (1975). Furthermore, it is undisputed that where a well is drilled for the acquisition of a fractional working interest in the property, the deduction for IDC is allowed only for the cost attributable to the fractional interest acquired. Any IDC attributable to the portion of the working interest owned by another is a capital cost which must be added to the basis of the interest acquired. Sec. 1.612-4(a), Income Tax Regs.; Bernuth v. Commissioner,57 T.C. 225 (1971), affd. 470 F.2d 710 (2d Cir. 1972). *157 Where a taxpayer purchases a mixed aggregate of assets for a lump sum, the price must be allocated to the various elements of the aggregate purchases, based upon the relative values of each element to the value of the whole. F. & D. Rentals, Inc. v. Commissioner,365 F.2d 34, 40 (7th Cir. 1966), affg. 44 T.C. 335 (1965). 16 We have held that where an investor acquires an interest in an oil or gas well from a promoter who, as part of the "package," also undertakes or arranges for the drilling of the well on a turnkey basis, with no opportunity for the investor to separately negotiate the drilling contract, the deductible IDC is limited to the amount which would have been paid if the drilling contract had been negotiated at arms length. Bernuth v. Commissioner, supra. Neither party here, however, presented any evidence as to the fair market value of an independently negotiated "no out completion through the tanks" turnkey contract, such as is involved here; therefore, we must determine the reasonable value of a similar contract. Respondent takes the position that, under the facts and circumstances present here, Byron Oil's actual *158 direct drilling and completion costs are the proper measure of the reasonable value of this type of contract. We do not agree with respondent's position, however, because it ignores the realties of a "no out" turnkey contract. Under the terms of their contract with the investors, Byron Oil agreed to dill the wells to a specified depth regardless of cost but to charge the investors only a predetermined amount. Furthermore, Byron Oil agreed to complete any well which appeared commercially productive regardless of cost but, again, to charge the investors only a predetermined amount. The relevant inquiry is what did the contracting parties intend the contract price to include at the time they entered into the contract, not after the costs were incurred and the profit or loss determined. We believe that a prudent promoter offering the type of turnkey contract involved here would structure the purchase price in such a manner as to minimize to the best of his ability any risks he might encounter. Moreover, any investor entering into a similar turnkey contract with the operator of an oil well drilling program would expect to pay a high premium to the operator to compensate him for the *159 substantial risks he was undertaking. Therefore, it would be unreasonable here to conclude that, where the actual direct costs were less than the estimated costs, the cost to the investors in the Byron Oil gas and oil programs for the "no out completion through the tanks" turnkey contract was equal to only the direct costs paid by Byron Oil to third party contractors. It is irrelevant that for the wells involved here the possible risks never materialized. Hindsight is always better than foresight. The offering documents involved here leave no doubt that the purchase price was intended to cover more than the actual direct costs with Byron Oil would pay third party contractors. For example, the prospectus for the Jean Ehler #1 well required that each investor make an initial "drilling investment" of $ 2,600 for each one and one-half percent participating unit. Accordingly, if Byron Oil sold all 38 units, it would receive $ 98,800 for the drilling. Estimated drilling costs itemized in the prospectus, however, totaled only $ 59,800. The prospectus further informed the investor that if the well did not merit completion, Byron Oil would have an excess $ 39,000 which it would apply to *160 its general overhead, legal and administrative costs for the well. The prospectus also advised the investor that if there were any remaining funds, the excess would be retained by Byron Oil. 17 Moreover, the Schedule D filing information in bold face print advised the investors that the estimated drilling and completion costs listed in the offering were substantially greater than the average industry costs in the area. Thus, the investors were put on notice before becoming involved in the drilling program that they were paying for more than the direct costs Byron Oil expected to pay for drilling the well. We believe that the investors knew they were reimbursing Byron Oil for some of its indirect costs, *161 risks, and a profit. Petitioners suggest "deemed" drilling and completion costs be determined by this Court by adding to the estimated costs reflected in the prospectuses, specified amounts for overhead and administration costs, risks, and a reasonable profit. We are not persuaded, however, under the facts and circumstances present here that petitioners' formula is reasonable. There is no doubt that reasonable charges may be included in a turnkey contract for overhead, risks, and profit. Sec. 1.612-4(a), Income Tax Regs.; Brountas v. Commissioner,73 T.C. 491, 515 (1979), affd. and revd. on other grounds 692 F.2d 152 (1st Cir. 1982), affd. and revd. on other grounds sub nom. CRC Corp. v. Commissioner,693 F.2d 281 (3d Cir. 1982), cert. denied 462 U.S. 1106 (1983); Haass v. Commissioner,55 T.C. 43, 51 (1970); Hedges v. Commissioner,41 T.C. 695, 700-701 (1964). We are not convinced, however, despite disclaimers in the prospectuses and Byron's testimony to the contrary, that the estimated costs set forth in the prospectuses do not already include amounts for some of Byron Oil's indirect costs plus risk and profit factors. As noted above, the Schedule D filing clearly advised the *162 potential investor that the estimated drilling and completion costs listed in the offering, which costs purportedly were based upon figures that were representative of the costs bid by third party contractors, were substantially greater than the average industry costs in the area. Petitioners offered no evidence to explain why costs Byron Oil expected to incur for drilling and completing the wells were not within the range incurred by others in this area. Thus, we are left with the conclusion that had evidence on this matter been presented, such evidence would have been unfavorable to petitioners. McKay v. Commissioner,89 T.C. 1063 (1987); Wichita Terminal Elevator Co. v. Commissioner,6 T.C. 1158 (1946), affd. 162 F.2d 513 (10th Cir. 1947). Logic and knowledge of prudent business practice lead us to find that the estimated costs included in the Schedule D filings already included an amount for Byron Oil's risks, a profit, and some of its indirect costs. This finding is supported by the testimony of Donald Langer, controller for the drilling company which subcontracted the drilling of one of the wells involved in these consolidated cases. His testimony established that the drilling *163 company's turnkey contract price for drilling this well was substantially less than the estimated costs reflected in the prospectus for the services included in the contract. The record does not satisfactorily explain the difference in the drilling company's bid price and the estimated costs reflected in the prospectus. Langer's unrefuted testimony contradicts Byron's self-serving testimony and the unsupported statements in the prospectuses that the estimated costs did not include an allowance for Byron Oil's overhead, a risk factor, and a profit factor. We believe and consequently find as a fact that this difference includes the risk and profit factors added by Byron Oil for these services. Furthermore, the record does not establish how much overhead, or risk and/or profit factors Byron Oil included in the purchase price, or how much of these elements it hoped to recoup out of the production of the well. Byron testified that Byron Oil hoped to make a profit from the sale of the participating interests through a combination of cash from the investors and production from the wells. No evidence was presented as to the amount of profit or risk which Byron Oil hoped to obtain solely *164 from the cash received from the investors. The testimony of Byron, however, leaves no doubt that Byron Oil looked principally to the production of the wells for its profit and to recoup any losses sustained from the drilling and completion of the wells. None of the petitioners testified about their understanding as to what was included in the purchase price or as to whether they intended the purchase price so include risk and profit factors for Byron Oil. Although we considered the testimony of petitioners' expert witness, Andrew Pfaff, that he would add $ 50,000 to $ 60,000 to the estimated costs for the risk factors involved in these no out turnkey contracts, we found his testimony unreliable because we have found that an allowance for some of these risks already was included in the estimated costs and some of the risks were to be recoupled out of production. Thus, we are not persuaded that an additional amount should be added to the estimated costs for risks and/or profit factors. As for the overhead factor, the record does establish that Byron Oil incurred various overhead costs to drill and complete these wells. The record does not establish, however, how much of these overhead *165 costs Byron Oil and the investors intended to include in the contract price at the time the investors entered into the contract with Byron Oil. Petitioners would have us use the total actual administrative and overhead expenses reflected on the Report of Results of Offering (Form 3-G) filed with the SEC. However, this amount may include charges which are not attributable to drilling and completing the wells. Furthermore, as discussed above, we believe the estimated costs itemized on the Schedule D filing already included an allowance for Byron Oil's anticipated general and administrative expenses relating to this drilling and completion process. Thus, petitioners have failed in their burden of proving that they are entitled to any additional amount for general and administrative expenses. Consequently, we find that petitioners have failed to prove that their "deemed" drilling and completion costs represent an amount which would have been charged by an unrelated third party contractor. Having found neither party's suggested formula acceptable, we are left on our own to determine a reasonable amount for the drilling and completion costs involved in the subject wells. Based on the *166 record, we hold that a reasonable amount for IDC and tangible equipment costs is the greater of the estimated costs set out in the prospectuses or the actual direct costs for drilling and completing the wells as stipulated to by the parties. Thus, where he actual direct costs are less than the estimated costs, this method allows a reasonable amount for Byron Oil's risks and for a profit. We further hold that, in allocating the IDC and tangible equipment costs, 61.44 percent of these costs are deemed attributable to intangible drilling costs and 38.56 percent are deemed attributable to tangible equipment costs. The allowable deduction further is limited to each investor's fractional interest in the well. The excess of the investor's purchase price over these allowable expenditures must be capitalized as a cost of acquiring that interest. 18*167 Bernuth v. Commissioner, supra. Thus, the amount set forth below are the allowable amounts for IDC and tangible equipment costs: Attributable Costs to be Attributable to Tangible Well Considered to IDC Equipment Costs (Greater of (Costs X 61.44%) (Costs X 38.56%) Estimated Costs or Actual Costs) Jean Ehler #2 $ 196,500.00 $ 120,729.60 $ 75,770.40 Ernest P. Zarlengo #3 196,500.00 120,729.60 75,770.40 McElwain #12 215,800.00 132,587.52 83,212.48 Wyman #1 205,345.00 126,163.97 79,181.00 McElwain #13 230,472.00 141,602.00 88,870.00 Jean Ehler #1 242,546.00 149,020.26 93,525.74 Jaccobucci #5 215,800.00 132,587.53 83,212.48 North Colorado #5 233,100.00 143,216.00 89,888.36 Allowable intangible drilling costs, tangible equipment costs, and basis in working interest, by petitioner, are as follows: Tangible Basis in Equipment Working Investor Well Investment IDC Costs Interest McGarvie Jean $ 6,300.00 $ 1,810.95 $ 1,136.56 $ 3,352.49 Ehler #2 Zarlengo #3 6,300.00 1,810.95 1,136.56 3,352.49 $ 12,600.00 $ 3,621.90 $ 2,273.12 $ 6,704.48 Slattery McElwain $ 6,575.00 $ 1,988.22 $ 1,248.19 $ 3,171.16 #12 Magness Wyman #1 $ 6,300.00 $ 1,892.46 $ 1.187.72 $ 3,219.82 Crymes McElwain $ 1,643.75 $ 531.01 $ 333.27 $ 779.47 #13 Jean 1,643.75 558.83 350.73 734.19 Ehler #1 Jaccobucci 1,643.75 497.21 312.05 834.49 #5 N. Colorado #5 1,575.00 537.07 337.07 700.86 $ 6,506.25 $ 2,124.12 $ 1,333.12 $ 3,049.01 Decisions will be entered under Rule 155. Footnotes 1. Cases of the following petitioners are consolidated herewith for trial, briefing, and opinion: John T. Slattery and Patricia A. Slattery, docket No. 20904-84; Estate of Guy N. Magness, Deceased, Ella Mae Magness, Personal Representative, and Ella Mae Magness, docket No. 25383-84; James Crymes and Barbara Crymes, docket No. 29285-84. ↩ 2. Petitioner Ella Mae Magness is the personal representative of the Estate of Guy N. Magness, deceased, and she also is a petitioner in her individual capacity. Guy Magness and Ella Mae Magness hereinafter jointly are referred to as the Magnesses. 3. Hereinafter reference to "McGarvie" is solely to petitioner James B. McGarvie. ↩ 4. The enclosures consisted of copies of the form letter 1189 (DO) (Rev. 9-78), dated Feb. 25, 1983, discussed above; Form 872-A(C)(9-81), "Special Consent to Extend the Time to Assess Tax," reflecting thereon taxpayers James B. McGarvie and Carol B. McGarvie of 1700 N. Woodlawn Avenue, St. Louis, Mo. 63124; and IRS Publication 1035 (Rev. 9-81), "Extending the Tax Assessment Period." ↩ 5. No conclusive evidence was adduced establishing the date the McGarvies actually received the notice of deficiency. In their brief, in arguing that the delay in the delivery of the notice was prejudicial, the McGarvies stated that: "If 70 days or 75 days was sufficient notice then the Statute wouldn't provide for 90 days." In their petition, the McGarvies alleged that the U.S. Post Office initially attempted delivery of the notice of deficiency at their former address on April 20, 1983. In respondent's trial memorandum, respondent stated that the notice of deficiency was available for the McGarvies to pick up on April 20, 1983, and was actually delivered to the McGarvies on April 25, 1983. McGarvie stated at the hearing held on May 6, 1985, that he agreed with respondent's trial memorandum, but did not agree that the notice was mailed to the last address known to respondent. Consequently, we conclude that the McGarvies actually received the notice of deficiency within 15 days of its mailing. 6. Except for differences relevant to each well, such as drill site, lease data, etc., the text of the outline of the terms of the offering were substantially identical. Pertinent portions of the outline relating to Jean Ehler Well #1 provided as follows: RISK FACTORS * * * (2) The investor will have no diversification or spreading of his risk. The units offered will participate in only the one well to be located on the specific 40-acre tract described in the Prospectus. In the event that the said well is not commercially productive, the investor stands to lose his entire drilling investment of $ 2,600.00 for each 1-1/2% participating unit. * * * (4) The investor may be obligated not only for the $ 2,600.00 initial payment and the $ 3,975.00 mandatory assessment to pay completion costs, but if the well becomes a producing well, he will be liable for continuing operating costs in order to share in production. At the sole discretion of the operator, the investor may be obligated to pay the said $ 3,975.00 for completion of said well at any time prior to the drilling of the said well. (See Page 6, "Terms of the Offering" and the Operating Agreement, Exhibit "C".) (5) In the event the drilling or completion costs are not in excess of the amounts paid by the purchasers of units, any sums in excess of the actual costs become the property of the operator, and the offeror will not refund to the investors any portion of the savings he may effect in the drilling and completion. (See Page 6, "Terms of the Offering.") * * * TERMS OF THE OFFERING This offering consists of thirty-eight participating units in the proposed well at a total fixed price of $ 6,575.00 for each 1/67th unit, $ 2,600 is payable in advance for the drilling of said well, and the balance of $ 3,975 is payable when called for by the offeror who will be the operator of said well, if he believes the well merits an attempt at completion. The offeror will retain the remaining 28.66ths units. However, if any purchaser buys one or more 1-1/2% units in the said described well, the operator may, at his sole discretion, demand and receive from any one or more of said purchasers, at the time of said purchase, or at any time prior to the drilling of the said well, the completion money in full for said interest. The completion money demanded by the operator, if made, is binding and mandatory upon any said purchaser, and the said purchaser (whether one or more) hereby agrees to pay such completion monies on said demand. The failure to pay the balance of the $ 3,975 per unit completion cost will result in the forfeit by the purchaser of the $ 2,600 per unit drilling cost. If the operator elects not to make such demand prior to the drilling of the said well (and the operator shall have the sole discretion of making such demand on any one or more of said purchasers), then the operator, Byron Oil Industries, Inc., the operator of said well, shall make such binding and mandatory demand for completion monies as set out herein; that is, at the time it is determined that the well, in the opinion of the operator, Byron Oil Industries, Inc. is capable of oil and gas production, which the purchaser hereby agrees to pay. The offeror will retain the remaining 28.66ths units. The proposed well will be drilled and completed by the operator at a fixed cost to the investors. The investors will not be called upon to supply additional funds to drill and put the well on production, if the original amount is insufficient, nor will the said investors receive a refund if there is a surplus. Under the terms of the Operating Agreement set out in the Offering Sheet attached, each interest purchaser will be charged with their proportionate cost of operating the area, and applicable production taxes when on production. If the said well drilled is not capable of oil and gas production and no attempt is made to complete the well as a producing oil and gas well, then in that event the operator shall refund any completion monies demanded and received prior to the drilling of the said well, within 10 days from the date of the decision by the operator that the well is not capable of oil and gas production, and that no attempt will be made to put the well on production. Each unit will entitle the owner to 1/93rd of all the oil and gas produced, saved and sold from the proposed well, and a 1/67th unit in and to the equipment installed for the production of the well. The estimated cost of drilling the said well to approximately 5,300 feet to adequately test the Sussex formation is $ 59,800.00, and the estimated costs to complete said well ready for production is $ 156,000, for a total of $ 215,800.00. These estimated costs may vary widely from actual costs due to weather conditions, mechanical problems and type of completion operations. In the event that the well is drilled, completed and put on production, it is estimated that there will be excess funds. The said excess funds would result from the actual cost of drilling and completion being less than the funds received from the sale of units. * * * In the vent the well does not merit an attempt at completion, in the opinion of the offeror, and the said well is plugged and abandoned at the casing point, the offeror will have unexpended funds from sales to unit owners of $ 39,000.00 to be used by the offeror for general overhead, legal and administrative costs. In the event these unexpended funds are in excess of the estimated costs for general overhead, legal and administrative costs, the said excess will be retained by the offeror. * * * PARTICIPATING IN COSTS AND REVENUES COSTS PARTICIPANTS OFFEROR Drilling costs, to total depth 100% 0% Lease costs 0% 100% Legal and regulatory costs 0% 100% Overhead, sales, administrative costs 0% * 100% Completion and equipment costs 100% 0% Operating costs 57% 43% * These costs, although paid by the offeror, are derived from the proceeds of the sales of units. ROYALTY & OVERRIDE REVENUES OWNERS PARTICIPANTS OFFEROR Oil & Gas Revenues 28.0000% 40.8358% 31.1642% The Operating Agreement, Exhibit "C", provides for a monthly well charge by the Offeror of $ 300.00 per month for each producing well. The said $ 300.00 per month charge is attributable directly to the operations of the specific well located on the described 40-acre tract. These costs include only those which are directly attributable to the specific well. These charges will be in accordance with the Mid-Continent Committee Accounting Procedure and are standard in the industry. In addition, 43% of this $ 300.00 charge is paid by the offeror. This charge is not related to the general overhead, supervision and administrative costs which are borne 100% by the offeror. (See * above.) The thirty-eight units owners, if all units are sold, will pay 100% of the drilling and completion costs of the said well, as estimated on Page 14 of the attached Schedule D, and will receive 40.8358% of the total production. If the actual costs of drilling and completion are less than the estimated costs as wet out on Page 14, then the thirty-eight unit owners, if all units are sold, will pay 100% of the total drilling and completion costs of the said well, resulting in surplus funds to the offeror, which he will apply towards overhead, sales and administrative costs. The smallest unit offered by means of this Offering Sheet is a 1/67th participating interest, and is not divisible. If the drilling and completion costs are equal to or less than the estimated drilling and completion costs and less than $ 249,850.00, being the total drilling and completion costs called for by the offeror if all interests are sold, then the offeror will not pay for any of the drilling and completion costs, but will receive 31.1642% of the total production from this well. ↩ 7. "Fracing," or fracturing, is "any processes, chemicals or other materials used to enhance an oil and gas well recovery operation." Williams and Meyers, Manual of Oil and Gas Terms, p. 341 (th ed. 1984), quoting 17 Okla. Stat. Ann. sec. 54↩ (enacted in 1981). 8. In the section of the prospectus outlining the terms of the offering, the estimated total drilling and completion costs is given as $ 196,500. However, in the Schedule D section the estimated total drilling and completion costs is given as $ 215,800. We used the amount given in the Schedule D section since that section was prepared in conformance with the rules of the Securities and Exchange Commission and was filed with that agency. The parties, however, had stipulated to an amount of $ 196,500. 9. At trial respondent stated that the Slatterys claimed a portion of the 1980 drilling payment as a deductible drilling cost on their 1979 tax return and then claimed the balance of this investment on their 1980 tax return. No evidence was submitted on this issue. 10. All section references are to the Internal Revenue Code of 1954, as amended and in effect during the years in issue, unless otherwise indicated. All rule references are to the Tax Court Rules of Practice and Procedure unless otherwise provided. ↩ 11. The amount of $ 120.46 of the loss claimed pertains to investments in two oil and gas wells not at issue. Respondent has conceded that the Slatterys are entitled to claim this loss. 12. In their petition, the McGarvies assert that the notice was mailed on April 18, 1983, based on their unsupported and unadmitted allegations that: "The U.S. Post Office initially sought to deliver the Notice of Deficiency to taxpayers on April 20, 1983 at their former address. The taxpayers are informed and believe that it takes two days to deliver mail from Jacksonville, Florida to St. Louis, Missouri. As the envelope bears no cancellation date the Notice was not mailed on April 14, 1983 * * *." These assertions, of course, are not evidence and we have not relied on them as such for our decision. See Rule 143(b). ↩ 13. In order to foreclose any doubt on this matter, however, it should be noted that where this Court to address to question of whether the notice of deficiency was mailed to the McGarvies' "last known address," based on the record regarding this issue, we would find that the McGarvies did not provide clear and concise notification of their new address. Consequently, we would hold that the statutory notice was mailed to the McGarvies at their last known address. See Tadros v. Commissioner,763 F.2d 89, 92 (2d Cir. 1985); Alta Sierra Vista, Inc. v. Commissioner,62 T.C. 367, 375-376 (19974), affd. without published opinion 538 F.2d 334 (9th Cir. 1976); Marvin v. Commissioner,40 T.C. 982, 984↩ (1963). 14. For purposes of the remaining portion of the opinion, references to the petitioners as a group refers to James B. McGarvie, docket No. 19119-83, John T. Slattery, docket No. 20904-84, Guy and Ella Mae Magness, docket No. 25383-84, and Barbara Crymes, docket No. 29285-84. The remaining petitioners are parties to this proceeding because they filed joint returns for the years in issue with their respective spouses. ↩ 15. A turnkey contract is a contract under which a drilling contractor agrees to furnish all material and labor, and to perform all the work necessary to drill and complete a well in a workmanlike manner, place it on production, and turn it over to the operator for a specified price. Fass and Howard, Tax Sheltered Investments Handbook, sec. 5.03 [3][a][vii], p. 5-10 (1985). The contractor assumes all the risks attendant upon mishap. Therefore, the cost for a turnkey contract exceeds an ordinary drilling contract. Monacelli, "Sharing Risks and Costs in Mineral Development and Operation: Allocating the Tax Deduction," 196th Ann. N.Y.U. Tax Inst. 1079 (1961). See also Brountas v. Commissioner,73 T.C. 491, 499 (1979), affd. and revd. on other grounds 692 F.2d 152 (1st Cir. 1982), affd. and revd. on other grounds sub non. CRC Corp. v. Commissioner,693 F.2d 281 (3d Cir. 1982), cert. denied 462 U.S. 1106 (1983). A "no-out" turnkey contract does not have any of the "outs" found in standard turnkey contracts which allow the contractor to quit before reaching the agreed upon point should be encounter certain unfavorable conditions (such as high or low pressure, impenetrable subsurface formations, loss of circulation, and salt). See Brountas v. Commissioner, supra↩ at 497. In a "no-out completion through the tanks" turnkey contract, the contractor agrees to do everything needed to drill and complete the well to the point that it is ready for production regardless of cost to the contractor. 16. See also Roby v. Commissioner,T.C. Memo. 1983-688↩. 17. The prospectus also informed the investor that there was a mandatory assessment of $ 3,975 to pay completion costs (raising $ 151,050 if all 38 interests were sold) but further showed total estimated completion costs of $ 156,000. Thus, the prospectus advised the investors in the Jean Ehler #1 well that Byron Oil was charging them as a group $ 249,850 for drilling and completing the well but estimated its drilling and completion costs to be only $ 215,800, a difference to $ 34,050. ↩ 18. The record does not provide this Court with sufficient information to allocate the excess to the working interest, sales commissions, and the operating contract, as suggested by respondent. Footnotes [_fnote6] Only testing and circulating rig time were the obligation of Exeter Drilling Company.