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- 188.8.131.52 Types of Organizations
- 188.8.131.52 Petroleum Refining
The typical oil and gas joint venture between working interest owners is technically a partnership for federal tax purposes. Refer to IRC 761 for definition of "partnerships" .
IRC 761(a) and Treas. Reg. section 1.761–2(a)(3) and (b) permit participants in the joint production, extraction, or use of property to be excluded from the partnership code sections in Subchapter K if all other requirements are met. This election is made by attaching a statement to a partnership return. The election can be made in any year in the life of a partnership, including the first year. However, until the election is made, a partnership return must be filed and the joint venture will be subject to the partnership provisions in the Code. Once the election is filed, the joint venture ceases to file a partnership return, and the joint interest owners or working interest owners may not consider themselves to be partners.
If the partnership elects to be excluded from the provisions of Subchapter K, each partner will make the election to capitalize or deduct IDC. If the partners have made a previous election, they will be required to follow it.
If a partnership does not elect to be excluded from Subchapter K, the partnership itself must make all elections affecting taxable income of the partnership, except for any election under:
IRC 108 (regarding income from discharge of indebtedness);
IRC 617 (regarding deduction and recapture of certain mining expenses); and
IRC 901 (regarding taxes of foreign countries and U.S. possessions).
IRC 703 and Treas. Reg. section 1.703–1(b) provide for elections that are made by the partnership instead of by individual partners. The most important election made by an oil and gas partnership is the election to capitalize or deduct IDC. The election to deduct currently or capitalize must be indicated on the first partnership return claiming such expenses. Failure to elect to deduct IDC on a partnership return will sometimes preclude the passthrough of lDC to the individual partners. Frequently, taxpayers fail to realize that a partnership return must be filed, and they fail to elect to be excluded from the provision of Subchapter K. When this happens, the election to deduct IDC currently cannot be made by the partnership; therefore, IDC may be capitalized at the partnership level. Moreover, in cases where a partnership does elect to expense IDC and passes through the IDC deduction to its partners, the partners may elect to capitalize and amortize IDC as provided in IRC 59(e) for alternative minimum tax purposes.
Certain elections are important and should be made at the partnership level, including the following expenditures:
Intangible drilling and development costs—to deduct or capitalize. Refer to IRC 263(c).
Property unit—to treat as one property or separate properties. Refer to IRC 614.
Subchapter K—election to not be treated as a partnership. See Treas. Reg. 1.761–2.
With partnerships, it is important to remember that a partner's share of income and deductions will be determined from the partnership agreement. Enterprising oil and gas promoters use IRC 704 to allocate current deductions to investors who furnish money for drilling wells.
Generally, the pure economics of drilling a wildcat well do not offer sufficient benefits to entice outside investors to furnish money for drilling. However, if the general partner or promoter can allocate all of the current tax deductions to certain investors, often the tax benefits are sufficient to justify the investment. IRC 704(b) permits unequal allocations of deductions among partners, which is called special allocations, as long as the allocation has substantial economic effect. For an illustration of the substantial economic effect rules, see Orrisch v. Commissioner, 55 T.C. 395 (1970); aff'd, 31 AFTR. 2d 1069 (9th Cir. 1973).
Where an allocation does not affect the partner's capital upon liquidation, it will not usually be considered to have substantial economic effect. In such a situation, if the allocation is determined to lack substantial economic effect, the item will be reallocated in accordance with the partners' interest in the partnership. Generally, this means the item will be shared among the partners on a per capita basis. An easily understood discussion on partnership allocations can be found in Cunningham and Cunningham, The Logic of Subchapter K, A Conceptual Guide to the Taxation of Partnerships, 2d (West Group, 2000).
The Tax Reform Act of 1975 added IRC 703(a)(2)(F) to provide that the deduction for depletion under IRC 611 is not allowable as a deduction to a partnership. After January 1,1975, the depletion deduction must be deducted on a partner's return, not the partnership return. Due to IRC 613A, each partner must now compute the limitations for their depletion deduction on their own return. Each partner treats an allocable portion of the partnership's basis in the property as its basis for cost depletion computation purposes. Treas. Reg. section 1.613A-3(I) provides that the partnership is responsible for providing each partner with the information necessary to compute depletion deductions.
All partnerships incur certain formation costs such as legal fees, officers' salaries, administrative expenses, and broker's fees for selling partnership units or shares. Sometimes these expenses are paid by the general partner, promoter, or sponsor and sometimes they are paid by the partnership. After October 22, 2004, if the partnership elects, the partnership can deduct the lesser of (i) the organizational expenses with respect to the partnership or (ii) $5,000 reduced (but no below zero) by the amount that organizational expenses exceed $50,000. Any remaining organizational expense is deducted pro rata over 180 months.
On or before October 22, 2004 costs of forming a partnership are capital in nature and are not allowable as a current deduction. Refer to IRC 709(a). IRC 709(b) does, however, permit amortization of organization fees over a 60-month period.
Formation costs may not be evident in the partnership return or in the books and records of the partnerships. When this is the case, such costs can be found on the return of the partnership sponsor or promoter. Therefore, the agent should review and, if necessary, examine the sponsor, promoter, or general partner concurrently with the examination of the partnership so that the proper treatment of these costs can be ascertained.
In large limited partnerships, it is a usual practice to sell partnership units through a stock brokerage firm. These firms usually charge a commission ranging from 5 percent to 10 percent of the entire partnership capital. These costs are syndication costs (rather than organization costs) which cannot be deducted or amortized. This can be a rather sizeable adjustment and can usually be found by a careful reading of the partnership prospectus.
Large management fees paid in the first year of the partnership can be an indication that the partnership is reimbursing the sponsor for formation costs. A careful reading of the prospectus and inquiries to the managing partner can uncover this issue. However, in some cases, an examination of the sponsor's books and records is the only way to accurately determine the actual amount and nature of the formation costs.
While the agent can usually speculate that a certain percentage of the first year management fee is for formation costs, this determination may not be sustained if a taxpayer later purports to show the actual formation costs to an appeals officer or to the court. Therefore, it is advisable to determine the actual amount and nature of the organization costs instead of relying upon an arbitrary percentage adjustment. Refer to IRC 709.
Special partnership allocations such as losses and depreciation are equally valid in oil and gas partnerships.
Common practice in oil and gas partnerships is for currently deductible costs to be allocated to certain partners. For instance, intangible drilling costs, well completion costs, and operating costs may be allocated entirely to limited partners. Special allocations are permitted under IRC 704, but they must have substantial economic effect. A review of IRC 704(b) and Treas. Reg. section 1.704-1(b) will provide guidance in this area. In addition, http://www.irs.gov/Businesses/Partnerships/Partnership---Audit-Techniques-Guide-(ATG) provides understandable examples.
Examiners should not accept a canceled check as proof of the amount of the deduction for intangible drilling and development costs without additional supporting documents. Frequently, promoters and sponsors of oil and gas ventures inflate the actual drilling costs to include an excessive profit for themselves. In some cases, examiners have found that the lDC are inflated several times over the actual costs. The amount in excess of the actual cost plus a reasonable profit should be considered to be paid for leasehold cost and capitalized by the partnership. Refer to Rev. Rul. 73–211, 1973–1 CB 303. When the reasonableness of drilling costs are in question, the examiner should consult a petroleum engineer.
Oil and gas wells vary in depth according to the area, drill site location, and formation to be tested. It is much more expensive to drill a deep well than a shallow well. The drilling cost per foot of hole is much greater for a well drilled to a depth of 15,000 ft. than for a well drilled to 1,000 ft. There are several reasons why the drilling costs per foot are not constant. The area of country, environment, rock formations, and other factors contribute to the ease or difficulty of drilling a hole. Other factors are the size and quality of the equipment. At deep depths, greater pressure and drill stem weight require larger drilling rigs, pumps, drill stem, surface casing, mud, etc.
a well drilled to a depth of 5,000 ft. in West Central Texas will differ substantially from the cost of a well of the same depth in Louisiana. The difference in the price per foot of well drilled might be five times greater for offshore Louisiana. In 1999, the average cost in the U.S. was $139 per foot for onshore wells and $514 per foot for offshore wells. As stated above, the cost of a well will vary according to area, depth, location, and other factors. Therefore, the costs above represent estimates only and should not be relied upon as more than that. An agent should consult an IRS petroleum engineer if there is doubt over the validity of actual drilling costs.
Frequently, a general partner or sponsor of a partnership will acquire an oil and gas lease from a landowner or by taking a "farm-in," and transfer the lease to a partnership as a capital contribution.
Usually the lease cost is nominal, and the limited partners never pay for any lease cost. The limited partners do actually pay for the leasehold interest indirectly by paying more than their share of the lDC. However, this is permitted under present law if the special allocation has substantial economic effect. On the other hand, if the leasehold cost is substantial and the amount paid by the limited partners for IDC appears to be excessive, the agent should determine if the general partner has made an excessive profit on IDC from the drilling contract. If this is the case, the excessive amount of IDC should be considered to have been paid for the leasehold interest and capitalized accordingly. Refer to Rev. Rul. 73–211, 1973–1 CB 303.
A partner's share of losses incurred by a partnership in a trade or business should be deducted on Form 1040, Schedule E as an ordinary loss. However, IRC 704(d) limits the loss deduction to the partner's basis in his partnership interest, computed at the close of the year. The loss disallowed is suspended and can be deducted in later years if the partner's basis in the partnership interest increases above zero. See also IRC sections 465 and 469 for additional loss limitations.
Losses from the sale of capital assets retain their character and pass through separately to the partners. Normally, the sale of oil and gas leases and of equipment on oil and gas leases are considered to be sales of assets used in a trade or business and, thus, are treated as IRC 1231 property.
Prior to the Tax Reform Act of 1976, promoters of oil and gas drilling ventures often utilized nonrecourse loans to provide deductions for limited partners in excess of their economic investment. This practice was questionable at best and generally lacked economic substance. IRC 465(b)(6) now provides that the deduction for losses incurred in oil and gas ventures (among other activities) cannot exceed the amount "at-risk." . Therefore, normally a limited partner's loss deduction cannot exceed the money invested. Agents should closely scrutinize promoter financing for these ventures. Usually the loans in most contemporary drilling ventures will be guaranteed by the partners and backed up with solid collateral. If this is the case, the loan is recourse and will increase the basis of the party who provides the collateral and guarantee. Refer to IRC 752. If a limited partner does not guarantee the loan, he will not be considered at risk since he is protected from recourse on the loan due to his status as a limited partner. His deductions would be limited accordingly. Note that the at risk rules are generally applicable to individuals and only in very limited circumstances to closely held corporations.
A productive well has value and will increase the value of all the leased acreage surrounding the drill site. At this stage, a lending institution would likely make a legitimate loan on the property assuming the well is a good one and the partners obtained an appraisal from an independent geologist. In such a situation, the partners' at-risk basis would be increased if the loan were a recourse loan – that is, if the partners were personally liable for repayment of the loan. Where situations of this kind exist, a careful reading of the underlying documents and IRC 465 is in order. In cases where a partnership loss is involved, loans that increase a partner's basis and amount at risk must be looked at carefully to determine if the loans are legitimate.
IRC 721 states that no gains or losses shall be recognized to a partnership or any of its partners when property is contributed to a partnership in return for an interest in the partnership. IRC 722 provides that the basis of an interest in a partnership acquired by a contribution of property shall be the amount of such money and the adjusted basis of the contributed property other than money. Generally, no recapture of investment credit, or amounts under IRC sections 1245 (b)(3), 1254 and Treas. Reg. 1.1254–2(c) will be triggered by a contribution of property by a partner to a partnership.
However, the nonrecognition provisions of IRC 721, et. al., do not apply to a transfer of property where a party is not acting in the capacity as a partner. See Treas. Reg. section 1.721–1(a). The substance of a partner-partnership transaction should govern instead of the form. If a partner sells property to a partnership for money and notes, the transaction should be treated as a sale in accordance with IRC 707.
A frequent occurrence in oil and gas partnerships is for limited partners to supply funds for IDC and receive an interest in the partnership of 50 to 60 percent. The sponsor or general partner will furnish services, a lease, and depreciable equipment, if needed, in return for a 40 to 50 percent interest in the partnership. Treas. Reg. 1.721–1(b)1 provides that, if one partner gives up the right to be repaid contributions of capital in favor of another partner who renders services, IRC 721 will not apply. The Regulations further provide that the "value of interest in such capital so transferred to a partner as compensation for services constitutes income to the partner under IRC 61. The amount of such income is the fair market value of the interest in capital so transferred." In all cases where a partner receives a transfer of capital from another partner for rendering services, agents should carefully scrutinize the transaction -- examples are if the capital contributed by a partner will not be returned upon liquidation of the partnership or if the partner receives income for providing services. On the other hand, if the partner receives a profits interest rather than a capital interest in the partnership, the receipt of such an interest is not ordinarily a taxable event for either the partner or the partnership unless: 1) the profits interest has a fairly certain income stream; 2) the interest is in a publicly traded partnership (within the meaning of IRC 7704(b)); or 3) the service partner disposes of the interest within two years of receipt. Additional sources of information on this issue include:
Treas. Reg. 1.61–1 (a) and 1.721–1(b)
Diamond v. Commissioner , 56 T.C. 530 (1971); aff'd, 492 F.2d 286 (7th Cir. 1974); 33 A.F.T.R. 2d 852; 74–1 USTC 9306
United States v. Frazell , 335 F.2d 487 (5th Cir. 1964); 14 AFTR 2d 5378; 64–2 USTC 9684; cert. denied, 380 U.S. 961 (1965)
Campbell v. Commissioner , TC memo 1990–162 (1990), aff'd in part and rev'd in part, 943 F.2d 815 (8th Cir. 1991).
Rev. Proc. 93-27, 1993-2 CB 343, clarified by Rev. Proc. 2001-43, 2001-2 C.B. 191.
It is not uncommon where a partner contributes property to a partnership that it has a tax basis different from its fair market value. If so, IRC 704(c) requires that a partnership must use a reasonable method to allocate deductions attributable to the contributed property to the non-contributing partners (to the extent possible) based on its book value. Furthermore, if the contributed property is sold by the partnership, the pre-contribution gain or loss must be allocated to the contributed partner.
"Disguised Sales" are transactions in which taxpayers may attempt to use partnership structures to avoid sale treatment (i.e. realization of gain) on the exchange or other disposition of their highly appreciated oil and gas properties. These properties typically have high "built-in" gain due to the current deductions of IDC and/or accelerated depreciation of installed equipment. As a result, disguised sale transactions can pose material issues for examination.
The basic fact pattern and tax treatment of a disguised sale is described as one where a partner directly or indirectly contributes money or other property to a partnership and there is a related direct or indirect distribution of money or other property by the partnership to the partner (or another partner). The contribution and distribution can occur in any order. Taking into consideration all facts and circumstances and viewing the transactions together, if such contribution and distribution are more properly characterized as a sale, then both transactions are treated as a taxable sale. Refer to IRC 707(a)(2)(B).
For more detailed information, refer to Pub 541, Partnerships http://www.irs.gov/publications/p541/ar02.html and the Partnership Audit Technique Guide http://www.irs.gov/Businesses/Partnerships/Partnership---Audit-Techniques-Guide-(ATG).
Disguised Sales pose complex, factually intensive, and time-consuming issue examination. A partnership technical specialist, subject matter expert and local Counsel can help.
Suggested audit techniques include:
Schedule M-2 for large distributions with corresponding reductions to specific assets on Schedule L
Prior, current, and subsequent year Form K-1s, searching for large contributions and distributions
Schedule M-3 for book-to-tax differences for the transaction in question
SEC filings such as Forms 10-Q, 10-K and 8-K. Company and industry press releases reveal transactions not otherwise disclosed in financial statements. Also, determine how the transaction was treated for both financial and tax purposes.
Structured disguised sale transactions often span multiple tax years. For example in early years, a taxpayer may reorganize its assets or entities in order to group oil and gas properties that it intends to include in a future transaction. Similarly, a taxpayer could enter into a financial arrangement, such as a production payment or loan, with the other party to the disguised sale several years before the other steps of the transaction occur.
Copies of the contribution agreement, original and amended partnership agreements, any line of credit and/or other loan agreement, any indemnity agreement (or other similar side agreements between partners) as well as a written explanation of the business purpose of these documents. Also, consider requesting any internal financial and tax structuring document and any outside legal or tax advice.
Publicly traded partnerships (PTP) are fairly common in the oil and gas industry especially for midstream companies. IRC 7704 allows qualifying publicly traded partnerships to be taxed as a corporation. A partnership whose interests are traded on established securities exchanges or readily tradeable on secondary markets are considered to be publicly traded partnerships.
IRC 7704(c) allows the PTP to maintain its classification as a partnership if 90 percent or more of its gross income is derived from qualifying passive-type income. In general, a taxpayer must continue to meet the gross income requirements on an annual basis to qualify for the exception. Examiners should consider verifying that a taxpayer's income qualifies and that it exceeds 90 percent of gross income.
IRC 7704(d) refers to several types of qualifying income. Qualifying income related to the oil and gas industry includes income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including geothermal energy and timber). Examiners need to inquire if the taxpayer has previously requested a Private Letter Ruling on whether their income qualifies under IRC 7704(d).
IRC 469(k) requires that losses from passive activities of a PTP can only be applied to income or gain from passive activities of the same PTP. Likewise, credits from passive activities of a PTP can only be applied against the tax on the net passive income from the same PTP.
The corporate form of organization is often used by investors in oil and gas exploration, particularly if an unusual amount of risk is involved, notwithstanding some unfavorable tax features.
During the exploration and drilling stage, the adoption of Subchapter S status will enable the stockholders to deduct the losses from operations due to drilling costs being incurred because S corporations are flow-through entities. However, once the properties become profitable, the S corporation shareholder will pay tax on its pro rata share of the corporation's income. In addition, the shareholder of an S corporation having accumulated earnings and profits (generally from a former C-corporation) will pay tax on dividends distributed out of accumulated earnings and profits. Refer to IRC 1368. The percentage depletion deduction does not decrease earnings and profits and has the effect of increasing the taxability of dividends. Earnings and profits are only reduced by cost depletion. Treas. Reg. 1.316–2(e) provides, in part, "the amount by which a corporation's percentage depletion allowance for any year exceeds depletion sustained on cost or other basis, that is, determined without regard to discovery or percentage depletion allowances for the year of distribution or prior years, constitutes a part of the corporation's earnings and profits accumulated after February 28, 1913, within the meaning of IRC 316, and, upon distribution to shareholders, is taxable to them as a dividend." This rule is applicable to certain Subchapter S corporations as well as regular corporations. Distributions from corporations, including S-corporations with accumulated earning and profits, that are considered to be nontaxable should be considered as to the source of distribution. The corporation may be paying a dividend out of a percentage depletion reserve, which will be taxable.
Oil and gas companies often have minimal regular taxable income and therefore the determination of Alternative Minimum Tax (AMT) liability is a very important consideration. The tax preference amount for IDC can significantly affect Alternative Minimum Taxable Income (AMTI). Since other deductions, such as accelerated depreciation, also give rise to a tax preference, examiners should perform a risk analysis prior to proceeding with the examination of any or all tax preference items.
When the taxpayer is an independent producer (i.e., the taxpayer is not an integrated oil company) examiners should be aware that IRC 57(a)(2)(E) provides a general exception to the tax preference for IDC. However, that exception is limited and should be reviewed for correctness. Refer to IRM 188.8.131.52.4.1.2, Exception for Independent Producers and Its Limitation.
Another aspect of AMTI to consider is LIFO inventory. Refer to IRM 126.96.36.199.1.5.
AMT income and AMT are recorded on Form 4626, Alternative Minimum Tax - Corporations and Form 6251, Alternative Minimum Tax - Individuals. The below focuses on the computation by corporations.
IRC 57(a)(2) states that IDC deducted with respect to oil, gas, and geothermal properties is a tax preference to the extent "excess" IDC exceeds 65 percent of the net income from the properties. The preference amount for all geothermal deposits is computed separately from the preference amount for all oil and gas properties that are not geothermal deposits.
Not all IDC expenditures are taken into account in computing excess IDC. IDC incurred during the year in which the corporation elected to amortize over 60 months pursuant to IRC 59(e) is not taken into account. Similarly, IDC incurred with respect to wells drilled outside the U.S. is not taken into account since that IDC must be capitalized. Lastly, IDC incurred with respect to a nonproductive well (sometimes referred to as a "dry hole" ) is not taken into account. Whether a newly drilled well is nonproductive can be an examination item. Examiners should obtain a list of expenditures for IDC that were classified as nonproductive and then review IRM 188.8.131.52.4.4, Distinction Between IDC and Nonproductive Well Costs.
Excess IDC is determined annually. Computation steps follow:
First, determine how much IDC was paid or incurred during the taxable year in connection with oil, gas, and geothermal wells (other than costs incurred in drilling a nonproductive well) and was deducted under IRC 263(c) or IRC 291(b) for integrated oil companies.
Subtract the amount which would have been allowed as a deduction in the taxable year if such costs had been capitalized and straight line recovery of intangibles had been used with respect to such costs. Refer to IRC 57(b)
Under IRC 57(b) the taxpayer can choose for each well to compute "straight line recovery" by one of two methods, either straight line amortization over 120 months or by a permitted cost depletion method.
Straight line recovery begins with the month when production from the well commences, and is not tied to when IDC was incurred. Refer to IRC 59(e) and IRC 291(b). This could be very significant for high-cost wells that are drilled near the end of the year, especially if the taxpayer made a simplifying assumption that all its IDC was incurred exactly at mid-year and computed six months of amortization.
The following example is based on a Joint Committee on Taxation staff report, General Explanation of the Tax Reform Act of 1986, p. 442.
Assume an integrated oil company incurred $1,000,000 of IDC in January 2011. It currently deducts 70 percent of that total ($700,000) under IRC 263(c). IRC 291(b) requires that $300,000 must be amortized over 60 months, yielding a deduction of $60,000 in 2011. The sum of those two amounts ($760,000) is compared to how much of the $1,000,000 IDC would have been allowed in 2011 under straight line recovery. Assume that amount is $50,000 because production started in July (6 months divided by 120 months and multiplied by $1,000,000). For 2011 the amount of excess IDC is $710,000 ($760,000 minus $50,000). The remaining IDC to be deducted under 291(b) in subsequent years is disregarded for computing excess IDC in those years ($300,000−$60,000=$240,000).
To determine the IDC preference amount , excess IDC must then be compared to 65 percent of "net income from oil, gas, and geothermal properties" . Net income is the gross income the corporation received or accrued from all oil, gas, and geothermal wells minus the deductions allocable to these properties. When calculating net income, only income and deductions allowed for the AMT are considered. The IDC deduction is reduced by the amount of excess IDC. Only deductions incurred with respect to properties that generated gross income during the taxable year are included. Refer to Technical Advice Memorandum 8002016 (PLR 8002016). However, Rev. Rul. 84-128, 1984-2 CB 15 clarifies that properties which have wells that are capable of production, but which are shut-in, are included in the calculation. Presumably the computation is done at the consolidated return level and includes both domestic and foreign properties. However, there is no authority to include activities that occurred within a controlled foreign corporation.
The following is an extension of the previous example in 22.214.171.124.4.1.1(4) and is intended to show how the tax preference amount is determined.
Assume the facts of the example above. Further assume the company has gross income from oil and gas properties of $850,000. For simplicity there are no expenses or deductions to consider other than IDC. To determine the AMT net income of the properties, the taxpayer's regular IDC deduction of $760,000 must be reduced by the excess IDC of $710,000, yielding a $50,000 deduction. Therefore AMT net income of the properties is $800,000 ($850,000 gross income minus $50,000 AMT expenditures). Sixty-five percent of the AMT net income of the properties is $520,000 ($800,000 × 65 percent). Finally, the IDC tax preference amount for the company is $190,000 ($710,000 − $520,000).
The tax preference amount for IDCs from oil and gas wells generally does not apply to corporations that are independent producers (as distinct from integrated oil companies as defined in IRC 291(b)(4)). However, the benefit of this exception may be limited. The amount by which the preference amount can be reduced cannot exceed 40 percent of AMTI when AMTI is computed as if the exception did not apply. Refer to IRC 57(a)(2)(E). This rule is illustrated with two examples.
Assume regular taxable income of an independent producer is $80 and the IDC tax preference amount is $20 (determined as if exception did not apply). For simplicity there are no other AMT preference amounts or adjustments to consider. Therefore "tentative" AMTI equals $100 ($80 plus $20). Forty percent of this tentative AMTI is $40. Therefore the entire IDC tax preference can be eliminated because a $20 reduction in the preference amount does not cause a reduction in AMTI that exceeds $40. AMTI is $80 ($80 regular taxable income plus $0 IDC tax preference amount).
Assume regular taxable income of an independent producer is $40 and the IDC tax preference amount is $60 (determined as if exception did not apply). For simplicity there are no other AMT preference amounts or adjustments to consider. Therefore tentative AMTI equals $100 ($40 plus $60). Forty percent of this tentative AMTI is $40 ($100 × 40 percent). If the exception were to apply in full, AMTI would be reduced by $60 ($100 − $40) so the benefit of the exception is limited to $40. The IDC preference is $20 ($60 − $40) and AMTI equals $60 ($40 regular taxable income plus $20 IDC tax preference amount).
Chief Counsel Advice Memorandum 201235010 explains that when AMTI for an independent producer is negative, the IDC preference exception in IRC 57(a)(2)(E) does not apply. In other words, the IDC tax preference amount should not be reduced at all. Examiners have determined that some independent producers improperly reduced their IDC preference amount, and consequently their AMTI, when their AMTI was negative. The purpose was to increase AMT net operating loss.
IRC 907 provides a limitation on the amount of foreign taxes available as a credit under IRC 901 that were paid or accrued on foreign oil and gas extraction income (FOGEI) and foreign oil related income (FORI). Prior to 2009 tax years, these limitations were computed separately from each other and the limitations for taxes on other foreign income. Effective for 2009 tax years and beyond, the Energy Improvement and Extension Act of 2008 amended IRC 907 to extend the IRC 907(a) foreign tax credit limitation for taxes attributable to FOGEI to taxes attributable to FORI. The combination of FOGEI and FORI is termed "combined foreign oil and gas income" per IRC 907(b).
For computing the separate adjusted AMT of a consolidated return member entity, annual reconciliation of FOGEI and FORI carryovers is necessary. See Prop. Treas, Reg. 1.1502-55(h)(6)(iv)(B).
This provision of the law can be quite complex and consideration should be given to consulting with an international foreign tax credit subject matter expert or an international examiner when combined foreign oil and gas income generates foreign oil and gas taxes. when FOGEI or FORI generates foreign tax credits.
IRC 954(g), Foreign Base Company Oil Related Income, is one type of Subpart F income that could be an issue. A referral of the case to an International Examiner should be considered. Refer to IRM 220.127.116.11 for referral criteria and procedures.
Many companies in the oil and gas industry have scientists, engineers, mathematicians and other highly educated and experienced employees working in the United States in part for the benefit of controlled foreign corporations. Income from these intercompany services should be reported on the associated U.S. tax returns. Issues arise when taxpayers and examiners disagree on the amount of such income and the methodology to determine it.
Some taxpayers argue that requiring these intercompany services to be reported on a basis other than cost violates the arm's length standard of Treas. Reg. 1.482-1. Most oil and gas projects are conducted as joint ventures with one party designated to be the operator. Most companies are involved in numerous ventures, acting as operator in some and solely as joint venture members ("JVM" ) in others. Historically, the operators have agreed not to add any profit element to their internal charges to the JVMs for exploration, development and/or production activities (there are a few minor exceptions to this policy). Taxpayers claim that these JVMs are unrelated parties, acting at arm's length, and, since they do not add a profit element onto similar services rendered to the joint venture, there is no need to add a profit element to similar on services rendered to the JVMs by related entities.
However, examiners have generally determined that intercompany service transactions between the U.S. company and its Controlled Foreign Corporations (CFCs), and the service transactions between the JOA operators and its JVMs, are not comparable and do not satisfy the comparability provisions of Treas. Reg. 1.482-1(d)(1). The relationship between the operators and JVMs is unique and distinguishable from the relationship between U.S. companies and their CFCs. Indeed, a U.S. company has no participating interest in the CFCs' projects, and is generally compensated solely by service fees. In transactions with the JVMs, however, the JOA operator has a more expansive role than just providing services: it is developing an oil and gas project together with its JVMs, and is sharing that project's profits with the JVMs via the production from hydrocarbon extraction. The provision of services by the JOA operator to the JVMs is, in the overall picture, merely an ancillary transaction to the main endeavor, which is to develop the hydrocarbon asset in a manner that maximizes the profit for the operator and the JVMs. Thus, since the operator and the JVMs are co-venturers that jointly benefit from the profits of the project's development and the services-at-cost agreement, it is not the most reliable measure of an arm's length transaction for services provided by a U.S. company to its CFCs. This is only one example to distinguish the relationships and transactions between the US company and its CFCs, and those between JOA operators and the JVMs. Many more may exist depending on the specific facts and circumstances. If this issue or a similar issue is identified during an oil and gas examination, examiners should consider involving a Section 482 international subject matter expert, an international examiner, and Local Counsel.
IRC 199 provides a Domestic Production Deduction (DPD) for tax years beginning in 2005. It is a deduction allowed for U.S. taxpayers who have domestic production activities. The DPD is a percentage of the lesser of the taxpayer's taxable income or qualified production activities income (QPAI) for the taxable year, subject to wage limitations.
Expanded Affiliated Group. For a taxpayer that is a member of an Expanded Affiliated Group (EAG), all members are treated as a single corporation and the deduction is allocated among them based on each member's QPAI, regardless of whether the member has taxable income or loss or W-2 wages for the taxable year. Within an EAG, the activities of its members are attributed to each other. For example, where an integrated EAG extracts natural gas or crude oil, processes or refines that natural gas or crude oil, and sells the resulting items, the EAG is treated as a single corporation whose DPGR are attributable to both extraction and manufacturing. However, when a member of an EAG participates in a joint venture or partnership, the separate pass-through rules generally apply to that member's activities. Refer to Treas. Reg. 1.199-5 for application of IRC 199 to pass-through entities. Since joint ventures are common in the oil and gas industry, this could be an area of non-compliance.
Qualifying vs. Non-qualifying for Purposes of DPD. Generally, the gross receipts generated for the following types of oil and gas activities in the United States qualify as Domestic Production Gross Receipts (DPGR):
Exploration and production companies engaged in the extraction and production of oil and gas. Gross receipts must be attributable to their working interest in leaseholds and should include only their portion of gross revenues.
Refining and/or petrochemical companies engaged in the refining of oil or manufacturing of petrochemicals.
Manufacturing companies engaged in the manufacturing of tangible personal property such as oil field equipment but only if they properly have the "benefits and burdens" of the manufacturing process per Treas. Reg. 1.199-3(f)(1).
Construction companies engaged in the construction of US real property. Construction activity means an activity under the two-digit NAICS code of 23 and any other NAICS code that relates to the construction of real property such as NAICS code 213111 (drilling oil and gas wells) and NAICS code 213112 (support activities for oil and gas operations). Treas. Reg. 1.199-3(m)(4) provides that oil and gas platforms are explicitly included in the definition of infrastructure, which is a qualifying type of real property. Thus, the construction of oil and gas platforms in the U.S. qualify as construction activity DPGR.
Generally, the gross receipts generated for the following types of activities are NOT eligible for inclusion in DPGR:
Gross receipts derived from non-operating mineral interests. For example, royalty income is a non-operating interest income and therefore not includible in DPGR. Treas. Reg. 1.199-3(i)(9).
Gross receipts relating to the sale of products that the taxpayer did not manufacture or refine. For example, gross receipts relating to gasoline sales at a convenience store are not qualifying except in the case where a taxpayer is selling their own refined products. Integrated taxpayers may extract natural gas or crude oil, process or refine that natural gas or crude oil, and sell the resulting items in their own convenience store. Taxpayers may also have purchased crude oil or refined products for resale that they did not extract, manufacture, or refine themselves. These products could be purchased for a variety of reasons, for example to satisfy a long-term supply contract. Examiners may find the gross receipts from these products accounted for as a part of refinery operations or in a marketing/distribution function. Regardless of the reason purchased or the operational area used, these purchased-for-resale products should not be included in DPGR.
Gross receipts relating to transportation and distribution. For example, pipeline companies' gross receipts generated in the transportation of products are generally not includible for purposes of DPGR. However, where an integrated oil company is transporting its own extracted product through its own pipeline to its own refinery, the transportation of such product could be includible in DPGR if all of such activities are included in the same EAG.
Gross receipts attributable to the transmission of pipeline quality gas from a natural gas processing plant to a local distribution company's citygate (or to another customer) are non-DPGR.
Gross receipts relating to convenience store revenues from non-gasoline sales (for example food and beverages) is not included in DPGR.
Gross receipts related to methane gas extracted from a landfill. Refer to Treas. Reg. 1.199-3(l)(2).
Gross receipts generated from the sale of a leasehold interest, regardless of producing or non-producing. For sale of producing leaseholds, Chief Counsel Advice (CCA) 201208029, released February 24, 2012 addressed the situation where an exploration and production company sold producing oil and gas properties and treated its entire capital gain as qualifying for IRC 199. The CCA concluded that gross receipts from the sale of Leasehold Rights are not DPGR under IRC 199(c)(4)(A)(ii). However, the gross receipts attributable to the sale of the Well (and well equipment) may qualify as DPGR. Also, if any capitalized IDC was included in the basis of the Lease, then such amounts should be considered costs related to the construction of the Well and an allocation of such may qualify for DPGR (but not more than the actual capitalized IDC included).
Examiners should be aware of other types of income that are generally not related to the production of qualified property. For example, service income is not included in DPGR. Also, rental income is generally not included in DPGR unless the property rented was manufactured by the same taxpayer in accordance with other requirements of Section 199. If a company claims DPGR on rental of tangible property and it is not performing qualifying construction activities, such as drilling oil and gas wells, an examiner should consider contacting Local Counsel and the appropriate Section 199 subject matter expert.
Allocated Expenses for Purposes of QPAI. The extraction and production of oil and gas have certain unique associated costs. Generally, taxpayers should include all costs associated with the extraction of the crude oil and natural gas or other qualifying activities that can be allocated and apportioned to a class of qualifying income per IRC 861 and the treasury regulations thereunder. For example, if a qualifying activity is from extraction, the following expenses are some examples of such directly allocable and includible costs:
Depletion (cost and percentage)
Geological and geophysical expenditures
Leasehold abandonments
Intangible Drilling Costs
Dry hole expenses
Oil related Gross Receipts for QPAI. For tax years 2010 and beyond, the applicable DPD percentage is held at 6 percent for oil related QPAI, verses 9 percent for other activities.
"Oil related" QPAI is income attributable to production, refining, processing, transportation, or distribution of oil, or any "primary product" thereof. Total QPAI should be calculated and then the reduction under IRC 199(d)(9) should be made to the extent there is oil-related QPAI. Refer to IRC 199(d)(9) . Oil related QPAI must first qualify under normal rules of QPAI to qualify for 6 percent. Therefore, gross receipts from transportation and distribution do not qualify even if they are oil related. However the exception for integrated oil companies as explained in 126.96.36.199.4.4.1 (3) c) still applies.
IRC 199(d)(9) refers to IRC 927(a) for definitions of the primary products of oil and gas. The regulations under IRC 927(a) provide that petrochemicals, medicinal products, insecticides and alcohols are not considered "primary products" from oil or gas.
Examination teams should consider analyzing the costs associated with petrochemicals vs. "Oil related" QPAI because of possible attempts to shift costs away from non-oil related QPAI (such as petrochemicals) to oil related QPAI to maximize the total DPD.
"Take-in-kind" and "elect-out" (of Subchapter K) partnerships are common in the oil industry. Instead of the partnership selling the oil and gas that it produces, it distributes the oil and gas to its partners for each to sell or use. Without the exception described below, neither the partnership nor the partners would have qualifying DPGR since the partnership did not have third party sales and the partners cannot be attributed the qualifying activities of the partnership. See Treas. Reg. 1.199-5 for general IRC 199 rules for partnerships.
A "qualifying in-kind partnership" is defined in Treas. Reg. 1.199-3(i)(7)(ii) and includes only certain partnerships operating solely in a designated industry – oil and gas, petrochemical, electricity generation, extraction and processing of minerals. The regulations provide that for "qualifying in-kind partnerships" each partner is treated as performing qualifying activity, such as extracting the property (e.g. oil and gas) that is distributed by the partnership to that partner. See Treas. Reg. 1.199-9(i)(7) for how this is accomplished. It is important to note that the taxpayer must be a partner in the partnership at the time the partner disposes of the property.
Qualified Exchanges . Energy companies sometimes exchange crude or refined oil products with other energy companies to achieve operational objectives. These arrangements are often made to save transportation costs by exchanging a quantity of product A in location X for a quantity of product A in location Y. The regulations provide a safe harbor that generally addresses the product exchanges above. The safe harbor is allowed for eligible property, which includes oil, natural gas, or petrochemicals, or products derived from oil, natural gas or petrochemicals, or any other property or product designated by notice in the Internal Revenue Bulletin. The safe harbor provides that "gross receipts derived by the taxpayer from the sale of eligible property received in an exchange, net of adjustments to account for difference in the eligible property, may be treated as the value of the eligible property received by the taxpayer in the exchange" . Thus, if energy companies C and D enter into a product exchange with a product that would have otherwise qualified as DPGR to both C and D, the fact that the product is ultimately sold to the consumer by the other respective energy company doesn't disqualify the original products from DPGR treatment for both C and D. The safe harbor requires a period of time for the exchange to be a qualified exchange per Treas. Reg. 1.199-3(i)(1)(iv)(B).
IRC section 1362(a) provides that a small business corporation as defined in IRC 1361(b), may elect not to be taxed and thus pass on a pro rata portion of the corporation's income for which the shareholder is liable for any tax. An S-corporation has no earnings and profits, except for any attributable to a taxable year prior to 1983 or to a taxable year in which it was a C-corporation.
An S corporation that was a C corporation at one time may have accumulated earnings and profits. In general, the earnings and profits of an electing Subchapter S corporation are computed in the same manner as any other corporation. In the computation of earnings and profits of an S corporation, the earnings are reduced by the taxable income, because the shareholders are required to include in their gross income. The results of this computation and other adjustments required by IRC 1368 may cause distributions in excess of the undistributed taxable income to be treated as ordinary dividends in the hands of the shareholder.
If corporate distributions made in the current year are in excess of current undistributed taxable income, the earnings and profits for the current and prior years should be verified to ensure proper excess depletion is being taken. The adjustments section on Schedule M–2 of Form 1120S should be inspected for such excess depletion adjustments.
IRC 1375 imposes a corporate level tax on excess net passive income if an S corporation has C corporation accumulated earnings and profit. Excess net passive income is passive income in excess of 25 percent of the S corporation's gross receipts, reduced by allowable deductions. For these purposes, passive income is similar to portfolio income as defined under the passive activity rules, which includes the royalties from oil and gas production payments, royalties, and overriding royalties. This would not include those production payments which do not retain economic interest status and are characterized as loans. Also does not include mineral, oil and gas royalties if the income from those royalties would not be treated as personal holding company income under IRC sections 543(a)(3) and (4) if the taxpayer was a C corporation. Some oil and gas lease bonuses are also considered "passive investment income" . If an S corporation has more than three consecutive years of passive investment income in excess of 25 percent of its gross income, the S election is terminated as of first day of the fourth year. Refer to Treas. Reg. 1.1362-2(c)(5)(ii)(A).
The examiner should be alert to the types of oil and gas income of electing Subchapter S corporations. The passive investment income relating to the oil and gas business when added to other types of passive investment income could result in an entity level tax or in a termination of the S corporation election.
The exploration, development, and operations of oil and gas properties are carried on in various business structures and forms, such as co-ownership, joint ventures, and partnerships. It is usually desirable to avoid the corporate form since the intangible drilling and development deductions would benefit only the corporation, and the percentage depletion in excess of cost depletion is added to taxable income in computing earnings and profits. It is normally more desirable to choose that organizational form which will enable the individual taxpayer to benefit the most from the tax deductions in their higher tax brackets. Normally, a partnership or disregarded entity will achieve this result.
Prior to promulgation of the "Check-the-Box Regulations" , the tax classification of business entities followed a complex system of entity classification under what was known as the "Kintner Regulations" . These regulations required organizational forms that were not corporations in the legal sense to be classified as corporations for tax purposes if they possessed the following corporate characteristics:
An objective to carry on business and divide the gains therefrom
Continuity of life
Centralization of management
Liability for corporate debts limited to corporate property
Free transferability of interest
Effective January 1, 1997, the Check-the-Box regulations replaced the Kintner regulations by simply allowing the taxpayer to check the appropriate box on IRS Form 8832. Treas. Reg. 301.7701–2(b)(1) and (3) through (8) list entities that are "per se" corporations that cannot change their classifications. Under Treas. Reg. 301.7701–3 entities not listed, such as limited liability companies (LLCs), are "eligible entities" that are treated as partnerships if they have two or more members. If the eligible entity has one member it will be disregarded for federal income tax purposes. An eligible entity can also elect to change its classification.
The limited liability company (LLC) is a hybrid business structure that combines the benefits of a sole proprietorship or partnership with those of a corporation. Like a corporation, an LLC offers its owners a limited liability shield that protects the business owners' personal assets from the debts or liabilities of the business. Like a partnership (or sole proprietorship), the LLC may allow all business income and loss to flow through to its owners. For these reasons, the LLC is becoming an increasingly popular format for doing business in most industries, including the oil and gas industry.
This section provides instructions for dealing with the many facets of the refining process.
Miscellaneous subjects and situations common to the oil and gas industry will be considered in this section. These topics were selected because they involve transactions or situations that are not common in other industries.
Exhibits and useful examination aids have been included at the end of this section. This material was included to provide inexperienced agents with tools that can be used in the examination of oil and gas operations. The suggested examination procedures are not mandatory but recommended for consideration.
Additionally more pertinent research material is shown in Exhibit 4.41.1-1 for study of the manufacturing phase of oil and gas operations.
Refining (as well as petrochemical) operations are basically manufacturing operations and, as such, involve additional aspects beyond the production technology discussed elsewhere in this handbook.
Refining operations may involve a relatively simple separation of components as in a topping plant or, as found in a modern large refinery, a separation of components plus the breaking down, restructuring, and recombining of hydrocarbon molecules.
In past years, domestic topping plants or skimming plants were sometimes used (i.e., Farmer's Cooperatives) to distill off light components with the sale of possibly only gasoline or diesel fuel. The residue was then subsequently processed at a major refinery to produce a full range of products. Domestic simple topping plants are a rarity today. In some foreign operations, topping plants are used to segregate rough cuts of the local crude. These cuts and virgin crude oil are then blended to produce a blend of crude suitable for sale/transportation to a particular refinery/market area depending upon the design of the refinery and/or the desired mix of finished products.
Modern large scale refineries not only produce the normal refinery products (kerosene, jet fuels, gasolines, heavy oils, etc.), but also are a source of feed stocks for the petrochemical industry.
Refiners make substantial investments to meet EPA requirements pertaining to emissions from their operations and fuel quality standards. Beginning in 1989, EPA required gasoline to meet volatility standards (in two phases) to decrease evaporative emissions of gasoline in the summer months. Upon passage of the 1990 Clean Air Act amendments, EPA began monitoring the winter oxygenated fuels program implemented by the states to help control emissions of carbon monoxide. It also established the reformulated gasoline (RFG) program which is designed to reduce emissions of smog-forming and toxic pollutants. EPA also set requirements for gasoline to be treated with detergents and deposit control additives. More recently, EPA has set standards for low sulfur gasoline and low sulfur diesel which will help ensure the effectiveness of low emission-control technologies in vehicles and reduce harmful air pollution. See http://www.epa.gov/otaq/fuels/index.htm. The American Jobs Creation Action created Code Section 179B (House Bill Section 338) and Code Section 45H (House Bill Section 339) which provided tax incentives for small business refiners in complying with EPA sulfur regulations. Refer to Exhibit 4.41.1-27.
Exhibit 4.41.1-12 provides an analysis of hydrocarbon series found in crude petroleum or in intermediate/finished product streams after refinery processing.
Originally petroleum refining was a rather simple process of separating crude oil into its component parts by distillation. The fractional distillation of an average crude oil yields a relatively small gasoline fraction, with larger amounts of kerosene and gas oil. Exhibit 4.41.1-13 illustrates distillation fractions of a typical crude oil. While the temperature range for indicated fractions remains relatively constant, the percentage distilled will vary based on the specific type crude involved.
Conversion of the higher-boiling materials into more valuable products (gasoline or petrochemical feedstocks) is essential. Conversion is partially accomplished in the cracking process by which the large paraffins are broken down to yield a mixture of smaller paraffins, olefins, etc. Such conversion enables the refiner to convert as much as 80 percent of some crude oils into gasoline (if desired) whereas, only about 20 percent could be attained by fractional distillation. In addition, the cracking and other processes not only increase the quantity of gasoline, but also the quality.
While the cracking process conversion of the heavier hydrocarbons to gasoline range hydrocarbons increases the quantity of gasoline products, the process also reflects an overall volumetric gain or increased yield. The total products produced, as a percent of feed to the unit, will reflect a 15–25 percent gain in volume (115–125 percent yield) due to the changes in gravities after cracking or hydrocracking. If refinery measurements were by weight, the yield would be approximately 100 percent.
The cracking process produces both saturated and unsaturated hydrocarbons. Other processes are used for recombining the resulting hydrocarbons to produce finished refinery products or for separating individual products as specialty feedstocks for the petrochemical industry. Separation of component streams is accomplished by additional fractionation, absorption, or solvent extraction. Precise separation/extraction of a particular product by fractionation is not always possible due to the small difference in boiling points. While some refineries may have a "super fractionation" area producing finely defined cuts, particular product extraction is often accomplished by absorption or solvent extraction.
In addition to the cracking and recombining of the hydrocarbons, other processes are available for the rearrangement of straight-chain hydrocarbons into ring or cyclic structures, the conversion of straight-chain hydrocarbons to branched-chain hydrocarbons, the removal of hydrogen to produce highly reactive hydrocarbons with double or triple bonds and/or aromatics, and the production of complex branched molecules of the paraffinic series. Some of these processes involve shrinkage (due to changes in gravities) with volumetric yields of 75–90 percent. See Exhibit 4.41.1-12 for illustrations of the various hydrocarbon arrangements. The relationship or arrangement of the hydrogen and carbon can be altered in many ways, and the resulting products have distinct characteristics.
Exhibit 4.41.1-14 provides a chart depicting the petroleum refining process. A specific refinery may or may not have all of the indicated processing units, or it may have additional units (isomerization, coking, asphalt, etc.). However, the chart is illustrative of possible product flows between some processing units.
The engineering design of a refinery is based on the type(s) of crude to be processed and optimum production of products. Actual production of the amounts of specific products will fluctuate, within limited parameters, based on seasonal demands or economic market conditions (i.e., a refinery designed to produce up to 60 percent gasoline may at times produce a lesser amount of gasoline with increased fuel oil production to satisfy seasonal demands, etc.).
Refinery operational flexibility is controlled by changes in individual processing unit operating conditions or by diversion of streams between units.
Changes in operating conditions could involve an adjustment to the severity on the reformers to increase/decrease yields versus decreased/increased quality (octane number) or an increase in the temperature in the catalytic cracker to generate more olefins and ultimately more alkylate.
Diversion of streams could involve sending the catalytic cracked light gas oils to be blended to furnace oil (for seasonal demands) rather than hydrocracking the total available stream, blending butylenes directly into gasoline instead of alkylating, or diverting the higher boiling components of straight-run naphtha (reformer feed) making more kerosene/turbine fuel.
Operational flexibility may also involve the coordination of shutting down of a single unit for repairs (turnaround), based on seasonal production demands. While a hydrocracker improves the quantity and quality of both gasoline and distillate blending stocks, its most important advantage is its ability to swing refinery production from high gasoline yields to high distillate yields. With seasonal peak production of distillates, the hydrocracker may be shut down for repairs.
The simplified flow diagram shows the entire hydrocrackate stream going to the catalytic reformer. In actual operations, fractionation of the hydrocrackate can produce a heavy hydrocrackate, a light hydrocrackate, and a kerosene range stream. These streams are suitable for distillate blending stocks or for upgrading to gasoline blending stocks.
In addition to the above design and operational flexibility in producing normal refinery products, the feasibility of producing petrochemical feedstocks creates other variables. The light gases from a catalytic cracker contain hydrogen, ethylene, propylene, and butylene. Separation of these components provides a design/operational stream for either alkylation or petrochemical feedstock. Catalytic reforming is a source of aromatic hydrocarbons (benzene, toluene, and xylene). Solvent extraction of aromatics from the reformate can provide a valuable petrochemical feedstock.
The importance/interaction of the petrochemical industry cannot be ignored when considering refining operations. The inter-relationship in research, licensing/royalty fees, disposition of intermediate products, and many other items must be analyzed through contractual arrangements, joint ownerships, and trade-offs, among others.
The potential utilization of petroleum based (hydrocarbon) building blocks is tremendous. Available byproducts of cracking (ethylene and propylene) provide the principal building blocks of the petrochemical industry. Methane can be converted to ammonia and ammonia to nitric acid. Anhydrous ammonia can be commercially sold in the liquid form as a fertilizer, or the ammonia and nitric acid can be combined to provide a solid fertilizer of high nitrogen content. Another example involves the production of synthetic rubbers. Successive dehydrogenation of n-butane produces 1,3–butadiene (plus hydrogen to be used in other processes). Polymerization or copolymerization of this product provides Buna rubbers for many products including automobile tires.
The integrated oil and gas operator may have its own petrochemical plants and/or may be involved in petrochemicals through arrangements with third-parties.
Fully integrated oil and gas operators with in-house divisions/companies for production, shipping, refining, petrochemicals, marketing, research and development, etc., provide a challenge in determining proper accounting for cross division/company operations. Research and development operations provide benefits and services to the other divisions/companies as well as development of patents, etc., available for lease or sale to third-parties. Intermediate streams or product streams from one plant provide feedstock for another plant.
Refining/petrochemical arrangements with third-parties may involve actual partnerships or be joint ventures with individual variable percentage ownership in the feed preparation plant(s) and the petrochemical plant(s) involved. In such integrated joint ventures, frequently an operating committee is responsible for daily operations, but has no ownership.
Particular problems encountered in such joint operations are further discussed in IRM 18.104.22.168.8, Joint Operations.
In refining/petrochemical plant processes, catalysts are frequently employed. By definition, a catalyst is a substance that hastens or retards a chemical reaction without undergoing a chemical change itself during the process. Such processes involve many substances as catalysts. Examples are acids, minerals, metals, mixed metals, metallic oxides or halides. Metallic catalysts may be utilized in the free state (i.e., gauze or sponge form) or bonded to a base material to facilitate handling or usage.
While the catalyst does not undergo any chemical change in the process, it may become inactive or ineffective after a time, due to physical abuse or buildup of impurities. Some processes include ongoing provisions for regeneration (i.e., burning off of carbon buildup) of physically stable catalysts. Where precious metals are involved (platinum, gold, silver, rhenium, etc.), reclamation of any physically deteriorated catalyst is standard operating procedure. Such reclamation usually involves returning the material to the manufacturer for reprocessing with credit for the precious metal (normally, practically no operational or reclamation loss of the precious metal is experienced).
The cost of catalysts is handled in different ways according to the types of catalyst involved and the taxpayer's accounting method(s). Some taxpayers may charge the catalyst to expense when it is placed in use. Others may capitalize the initial cost and claim depreciation. In some cases the catalyst may be rented or leased under a standard supply contract. The correct tax accounting method for handling catalysts depends on the contractual arrangements, the type of catalyst involved, and operational factors, among them operational life, recoverability, and reclamation. Refer to IRM 18.104.22.168.8.2 for further discussion of catalysts.
Refiners have historically used the Last-In, First-Out (LIFO) method for inventory accounting that is covered in IRC 472 and the regulations thereunder. The "dollar value" method of pricing LIFO inventories is specifically covered in Treas. Reg. 1.472-8.
It is beyond the scope of this manual to explain how LIFO inventory prices are calculated. However, examiners should be aware that some refiners have elected to use the Inventory Price Index Computation (IPIC) method that is addressed in Treas. Reg. 1.472-8(e)(3). IPIC relies primarily on consumer or producer price indices published by the U.S. Bureau of Labor Statistics (BLS). The election to use IPIC may constitute a change in method of accounting. See Treas. Reg. 1.472-8(e)(3) and Rev. Proc. 2011-14, IRB 2011-4 330.
LIFO inventory adjustments can affect the Adjusted Current Earnings (ACE) component in the AMT income calculation. See IRC 56(g)(4)(D)(iii) and IRC 312(n)(4).
Oil and gas taxpayers can be defining items in their calculation of LIFO inventory pools too broadly. Combining numerous types of crude oil or refined products into fewer items within pools for LIFO may not clearly reflect income.
It was determined that a Petroleum Refiner defined LIFO items too broadly in a 2008 Field Attorney Advice. Inhttp://www.irs.gov/pub/irs-lafa/080401f.pdf
The Petroleum Refiner had 2 LIFO pools, one for crude oil and one for refined products.
For the crude oil LIFO pool, the taxpayer maintained 3 items of inventory. However, the taxpayer's books and records defined approximately 140 different stock-keeping units (SKUs) within the 3 items.
For the refined products LIFO pool, the taxpayer maintained 12 items of inventory. However, these items were comprised of SKUs ranging from 4 to approximately 108 per item.
Based on the facts and circumstances, it was concluded that the taxpayer's definition of an item did not clearly reflect income because the overly broad definition could result in compensating the taxpayer for effects of artificial inflation resulting from changes in quality and/or product mix.
Crude Oil and Other Feedstock Pools
The physical characteristics of crude oil depend on varying scales of heavy versus light crude (measured by API specific gravity) and sweet versus sour crude (measured by sulfur content).
The price of crude oil varies with specific gravity. Lighter gravity crude oils tend to be more expensive because they tend to yield higher portions of more valuable refined products. Another factor in price is sulfur concentration. Generally, lower sulfur concentration is more desirable since refineries vary to the extent they are equipped to remove it.
There is no standard system of accounting employed by oil refineries, nor are there any prescribed examination guidelines within the industry.
In some situations, the refinery may operate as a self-contained entity preparing its own tax return or, in the case of a multinational conglomerate, feed its operational results back to corporate headquarters for consolidation.
Since refinery managers need various types of data to evaluate and control their operations, numerous types of reports and analysis are prepared using complex cost accounting techniques.
The examining agent should obtain a complete working knowledge of the accounting system prior to beginning his examination and should be cautious not to devote time to internal allocations having no tax significance.
An example of an information document request which could be used in a review of the accounting system is shown in Exhibit 4.41.1-15. This exhibit also provides a list of some terms which might be of use when reviewing the cost accounting system.
A prime area of examination concern should be the proper treatment of various types of overhead/indirect expenses.
Consideration should also be given to the form of business entity under which the refinery operates. Refer to IRM 188.8.131.52.8 for a discussion of Joint Operations.
During the course of an examination, the agent may discover items that are highly complex and unique which require the experience and expertise of a specialist examiner and/or a specialist within the Industry itself. A Technical Specialist with the Office of Pre-Filing and Technical Guidance (PFTG) — Petroleum is a good resource in such situations.
A major element in the cost of production at a refinery, and a significant source of examination potential, is the use of foreign crude oil.
Delegation Order 4-17 on Foreign Produced Crude Oil providing for servicewide coordination was rescinded effective 12/01/2011. Agents should refer to International Examination of IRC 482 transactions http://lmsb.irs.gov/hq/pftg/transferpricing/index.asp.
In addition to the examination potential to be found in crude oil pricing, International assistance from an international examiner may be required if issues are present.
The use of a CAS is discussed inhttp://irm.web.irs.gov/link.asp?link=22.214.171.124.3.2. It is essential that the CAS be requested as early in the examination as possible. Consultations should also be held during the course of the examination concerning updating existing record retention agreements in view of current experiences.
Examples of possible applications which may be helpful are to be found in Exhibit 4.41.1-17.
In addition to the skills of a petroleum engineer, the assistance of a general/industrial engineer may be required in the event the refinery has been involved in a major expansion or repair program. Refer to IRM 184.108.40.206.3, IRM 18.104.22.168.6, and IRM 18.104.22.168.7 for discussion of potential examination areas.
An excise tax examination may be conducted as a separate examination, as part of the "package audit" requirements for an Industry case. It is mandatory for the Coordinated Industry Case (CIC) Program.
A review of the taxpayer's retained copies of Forms 720 (Quarterly Federal Excise Tax Return) in conjunction with a "transcript" of taxpayer's account (and in light of the examination of the taxpayer's income and deductions per books and the income tax returns under examination) may indicate that an excise tax examination is warranted. This decision should be made as early as possible in each case so the examination work can be coordinated to the maximum extent desirable.
Review of the quarterly federal excise tax returns, Form 720 with attachments, is an important part of the examination of a taxpayer that owns or operates a refinery. The operator of the refinery may be liable for certain excise taxes.
Refer to IRC 4081(a)(1) in which a tax is imposed on certain removals, entries and sales of gasoline, diesel fuel, and kerosene. These three fuels are collectively referred to as "taxable fuel" . See IRC 4041(a) for tax on liquids other than gasoline (usually diesel fuel and kerosene used or sold for use in a diesel-powered highway vehicle or diesel powered train). IRC 4041(a)(1)(B) provides an exemption if these fuels were previously taxed as taxable fuels. IRC 4041(a)(2) imposes a tax on alternative fuels (excluding gas oil, fuel oil, and taxable fuel) used or sold for use in a motor vehicle or motorboat. Alternative fuels include those fuels referred to a "special fuels" prior to 10/01/2006. Common alternative fuels are liquefied petroleum gas (such as propane, butane, pentane, or mixture of these fuels). IRC 4042 imposes a tax on any liquid used by any person as a fuel in commercial waterway transportation known as an Inland Waterway tax.
The oil spill liability tax is an environmental tax. This $.05 per barrel tax generally applies to crude oil received at a U. S. refinery and to petroleum products entered into the U.S. for consumption, use, or warehousing. The tax also applies to certain uses and the exportation of domestic crude oil.
The tax imposed on ozone-depleting chemicals (ODCs) is also an environmental tax. This tax is imposed on an ODC when it is first used or sold by its manufacturer or importer. The manufacturer or importer is liable for the tax. The instructions for Form 6627 (Environmental Taxes) lists the taxable ODCs and tax rates.
Verification of the environmental taxes reported on the Form 6627 attached to the Form 720 (Excise Tax Return) may include the following items for Ozone-Depleting Chemicals or Imported Products (refer to IRC 4661 and IRC 4671:
Identification of the source documents, chart of accounts, flowcharts, operations manual, and responsible parties involved;
Records of all Ozone-Depleting Chemicals produced, and records of all Ozone-Depleting Products imported;
Records of the sale, export, or use of Ozone-Depleting Chemicals or Products;
Records to substantiate that the appropriate tax has been paid previously, including floor stocks, if applicable.
The environmental taxes deduction ledger account(s) should be analyzed and traced to source documents for a representative period. The examiner should determine that the taxable chemicals were properly classified for the appropriate tax rate, and that none of the taxable chemicals and none of the petroleum liquids were omitted from the amounts reported on Form 6627.
A major area of interest in the examination of refineries and petrochemical plants is the cost basis of property. The cost basis of tangible expenditures and intangible assets is involved in the determination of amortization, depreciation, and gain or loss on the disposition of all or part of such property.
In any transaction where different properties or assets are acquired, there is the problem of allocation of the basis to the various properties or assets. In some contracts, the amounts involved for each separate property or asset is stated. When stated at realistic values, the allocation problem may be eliminated. The acquisition of a refinery, refinery facilities, patents, processes, and know-how involve complex allocations of the purchase price.
The costs incurred incidental to the acquisition of a capital asset should be capitalized to the cost of the asset. Expenditures to be capitalized include items such as commissions, consulting fees, feasibility studies, environmental impact studies, legal fees, salaries, travel, and "new image" costs incidental to the acquisition of assets or expansion of the business. These incidental costs may include expenditures involved in forming a joint venture or a partnership. See IRM 184.108.40.206.8, Joint Operations.
Any costs incidental to the acquisition of a capital asset and having a benefit to the taxpayer beyond the current year should be capitalized, as part of the cost of the asset acquired or constructed. It is noted that the cost of such environmental studies should be distinguished from expenditures deductible under the provisions of IRC 174. Rev. Rul. 80–245, 1980-2 CB 72 and the potential problems involving environmental impact studies are discussed in IRM 18.104.22.168.3.4.
Examiners should be aware that the MACRS recovery period for refineries and petrochemical plants is 10 and 5 years respectively. See Asset Classes 13.3 and 28.0 in Exhibit 4.41.1-43.
Some taxpayers have asserted that certain assets located at their refineries should be depreciated using Asset Class 28.0. Guidance to examiners on this issue is provided by Field Directive on MACRS Asset Categories for Refinery Assets.
When examining acquisition costs, verify the total purchase price (including the adjusted cost basis of any property given in exchange), the incidental costs of the acquisition, etc.
Verify the allocation of the total acquisition cost to the respective assets acquired in ratio to their relative fair market values at the date of acquisition. Acquisition costs should be allocated to items such as:
"Going concern," "new image," environmental impact studies
Patents, licenses, processes, and know-how assets
Equipment and plant facilities
Pipeline and storage facilities
Land, right-of-way, and land improvements
Inventories (including pipeline "fill" ), intermediate stream and finished products, warehouse equipment and parts.
Some of the documents that should be examined for verification of acquisition costs include:
Authorization for expenditure (AFE) records
Letters of intent, offer, and counteroffer documents
Minutes of executive committee meetings and directors' meetings
Settlement sheets, transaction closing documents, papers transferring the consideration and conveying title
Purchase price/fair market value analysis and allocation workpapers used as the basis for recording the cost basis of the individual assets on the books
Analysis of the history and the projected performance of the tangible and the intangible assets including evaluation reports, Insurance coverage, and an itemized list of assets before and after the acquisition
Details for the vouchers of the original entries in the journals and ledger of accounts
Chart of accounts before and after the acquisition
Organizational chart before and after the acquisition
General information available such as employee newsletters, reports to stockholders, reports to SEC, or news releases.
Construction costs, in general, fall into three categories: initial refinery construction, expansion of refining capacity, and other improvements. In each category construction costs may include outside contractors, self construction, or a combination of both.
Contracts with outside contractors should be reviewed to ensure that all costs itemized in the contract have been properly considered as capital expense. The agent should also verify that the items included in the construction contract are properly classified or allocated for depreciation. Engineering assistance may be required where a lump sum construction contract calls for items to be constructed which will fall into more than one category for depreciation.
The agent should verify that appropriate self-construction costs have been properly capitalized. A good examination technique, when reviewing outside contractor costs, is to inquire if the taxpayer was furnishing personnel or equipment to supervise or assist in the construction process.
When self-construction costs are encountered, the agent should ensure that the capitalized costs include the direct costs, as well as the indirect costs such as insurance, benefits, and overhead.
In the oil and gas business, as with other industries, construction activities such as building pipelines, roads, canals, refineries, and industrial plants can have an adverse effect on the natural environment. Sometimes the company will spend a great deal of money making studies of the effect the proposed business expansion will have on the environment. Should these costs be deductible as ordinary operating expenses or should they be capital expenses? Any cost incidental to the acquisition of a capital asset and having a benefit to the taxpayer beyond the current year should be capitalized as part of the cost of the asset acquired or constructed. However, if the study results in the abandonment of the project, the cost would be deductible under IRC 165 in the taxable year the taxpayer decides to abandon the undertaking.
In the examination of taxpayers that have had large expansions, or have constructed plants that might have an environmental impact, the agent should be alert for such costs that might not have been capitalized.
Expenditures to conduct environmental impact studies to support its application to expand its facilities are not research and experimental expenditures, within the meaning of IRC 174. Whether such expenses are capital expenditures will depend upon the facts of the particular case. The expenses, if not chargeable to a capital account, are ordinary and necessary business expenses deductible under IRC 162(a) . Rev. Rul. 80–245, 1980–2 CB 72 holds that the costs of environmental impact studies paid by a public utility company in connection with its application to expand its generating facilities are not research and experimental expenditures within the meaning of IRC 174.
The operation of refineries and petrochemical plants often involves the utilization of numerous patents, exclusive processes, and trade secrets. During the examination of these operations, the agent should be alert for acquisitions of these types of assets. These items are capital assets and may be amortized over their useful life.
The purchase of these types of assets frequently will occur when other items of plant, property, or equipment are being purchased. When other items are purchased, the agent should inquire if the purchase includes any patents, exclusive processes or know-how.
Know-how may be defined as an aggregation of data or information that is employed in a business endeavor and has the effect of providing the user with a competitive advantage over others who do not have access to, or use of, such data or information.
Royalty payments for the purchase or license of know-how that are contingent upon the use of (and reasonable in terms of the benefits actually derived from) licensed know-how during the year for which the payment is made can be deducted as necessary and ordinary business expenses.
All other expenditures for know-how, with a few rare exceptions, must be capitalized and are not subject to the allowance for depreciation or amortization.
The inventory of refiners may include both domestic and foreign crude. See IRM 22.214.171.124.4 and IRM 22.214.171.124.6.1. The domestic and foreign crude inventory may include both produced and purchased crude oil.
In the examination of refinery and petrochemical operations, the agent should obtain the assistance of engineers if problems are encountered in the determination of the correct value of produced crude oil that is included in the inventory of a refiner.
The acquisition of crude oil for manufacture into finished products by refiners will be either through long-term contracts of supply by domestic and foreign producers or by spot purchases of crude oil on an as needed basis. The agent should be alert to per unit (barrel) variances in purchase price of purchased crude, especially if acquired from related entities.
Finished or saleable refinery products are a blend of various refinery streams and sometimes include purchased blending stocks. The prime example is gasoline.
With reference to the Simplified Flow Diagram in Exhibit 4.41.1-14, finished gasoline would be variable blends of the straight-run gasoline, reformate, catalytic cracked gasoline, thermal cracked gasoline, alkylate, and n-butane. These individual product streams (stocks) are normally segregated in storage tanks prior to actual blending operations.
For a refiner without the modern processing units to produce high quality gasoline components, or one faced with the temporary shutdown of such a unit, blending stocks are frequently purchased on the open market. Blending operations and blending stocks are further discussed in IRM 126.96.36.199.6.1.2.
The refiner's unfinished products inventory will normally include all produced or purchased basic stocks available for further processing or blending into finished products. The unfinished products inventory may be subcategorized to include:
Liquefied Petroleum Gas (LPG) Stocks
Gasoline Stocks
Kerosene and Gas Oil Stocks
Residual Stocks
Lube and Wax Distillate (Unfinished)
Industrial Chemicals
The refiner's finished products inventory will include all saleable products resulting from further processing and blending of unfinished stocks. Individual refineries produce different products and taxpayer's categorization and sub-categorization will vary. Refer to Exhibit 4.41.1-18 for a list of the types of goods found in product inventories.
To avoid unplanned shutdowns and to assist in performing routine maintenance, refineries normally maintain an inventory of spare parts and equipment.
The agent should examine those spare parts and equipment items that should be or are being inventoried. Items not held for resale are not inventory, and LIFO cannot be used to account for such items per Treas. Reg. 1.472–1. For non-inventory treatment of expendable, rotatable, or standby emergency spare parts, see Rev. Rul. 81–185, 1981–2 CB 59.
With respect to equipment, the agent should determine that proper consideration is given to investment credit and recapture of investment credit for items being placed in service or removed from service.
As explained in more detail in IRM 18.104.22.168.1.1, refineries convert crude oil and intermediate feedstock into finished petroleum products by a variety of physical, thermal, and chemical separation processes. Products that have been partially refined within the refinery are commonly called intermediate products. These intermediate products also must be included in inventory. Refer to Treas. Reg. 1.471-1.
Examination coined the term "line fill" to describe, in one name, intermediate product volumes within the refinery. However, line fill refers to all product volumes located within piping, processing units, surge tanks, vessels, drums, boilers, cylinders, reactors, vats, kettles, hoses, and other containers used within a refinery in the process of refining crude oil and intermediate feedstock into finished products and feedstock for sale. Line fill volumes are distinct and separate amounts from the tank volumes found in the taxpayer's storage tank farms, for both crude oil and finished products. The term "line fill" should also not be confused with the term "line pack" or "cushion gas" . Line pack refers to the volume of gas in a pipeline necessary to provide sufficient pressure to distribute gas over a large geographic area, and it is generally of uniform composition.
Examiners have observed that some taxpayers incorrectly account for line fill by:
Not treating any line fill as inventory
Not treating the proper amount of line fill as inventory (i.e., physical line fill volumes at year-end exceeds the volumes recorded for tax)
Treating line fill costs as deductible or depreciable
Some taxpayers may attempt to capitalize or depreciate the cost of line fill as part of the refining assets and depreciate it over the life of the refining equipment. Some taxpayers may not capture any line fill at all for tax accounting purposes, as either a separate capital asset or separate inventory item, and presumably expense the cost as incurred. Typical arguments from taxpayers are that line fill is necessary for the equipment to operate, or that depreciation is appropriate because of molecular changes to the petroleum product within the refinery.
Line fill represents petroleum products that are in the process of being manufactured and therefore the changes that are brought about are intentional. Depreciation allowance applies only to that part subject to, among other things, decay or decline from natural causes (refer to Treas. Reg. 1.167(a)-2). The molecular changes in the crude oil and feedstocks are not brought about from natural causes, but from intentional manufacturing actions. In contrast, line fill is a direct, income-producing factor because taxpayers are in the process of manufacturing a substantially transformed product, which is being held for sale. Thus, line fill is analogous to work in process and must be included in inventory (refer to Treas. Reg. 1.471-1).
Line fill represents a vast array of manufactured and work-in-process inventory items. Suggested steps by examiners include:
Determine if line fill volumes are captured within the existing tax inventory amounts. The refinery's tank farm inventory and line fill inventory may be held in different reporting entities so the agent should reconcile the inventory amounts down to the tank-detail level and/or reporting entity.
The total amount of line fill volume that actually exists within a refinery may not be properly captured in the taxpayer's inventory records. Examiners may need the assistance of a petroleum engineer to determine the types of petroleum hydrocarbons and the location and amounts of feedstocks within the refinery, as well as to identify the correct price for determining year-end inventory dollar amount.
The examination team should consider reviewing the taxpayer's regulatory agency filings with respect to refinery volumes. Refer to Exhibit 4.41.1-42.
If the examiner finds discrepancies in the taxpayer's dollar or volume amount of line fill inventory, an adjustment under IRC 481 may be required. Examiners are encouraged to contact an Inventory Subject Matter Expert or Local Counsel in the examination of line fill inventory issues.
Transactions involving disposition of raw materials, or the products of the refinery, may be reported as exchanges, transfers, or sales. Crude oil exchanges must be reported in crude oil costs using the basis of the item given up plus or minus any "boot" and related expenses of the particular exchange. Accordingly, it is necessary to distinguish an exchange agreement, a buy/sell agreement, and a true sale agreement.
Exchange agreements may exist when:
Both sides of the agreement are stated in a single document
The two agreements are negotiated simultaneously
The two agreements refer to each other
One side of the transaction involves a financial disadvantage sufficient that a prudent businessman would not enter into that part without the financial benefit of the other part of the agreement or agreements
Transfers of products intracompany may be recorded at cost basis and reported in the cost of sales of the respective divisions or recorded at "arm's-length" value and reported as a sale of products transaction. When refinery products are transferred to an intracompany division or to a related domestic company at cost, or at a stated value, the impact on the taxable income should be considered.
Transfer of products to or from a foreign related company should be examined. The product pricing should be evaluated against the "arm's-length" value so as to ensure that taxable income is not distorted and to ensure that the foreign tax credit is correctly determined. Refer to International Program Audit Guidelines (IRM 4.61) for discussion of international issues.
Buy/sell agreements are accounted for as "normal" purchase/sale transactions. They may involve transporting, handling, or warehousing petrochemical products. These agreements should be examined to verify what was done. Special consideration should be given to transactions near the end of the year when such agreements may be made to cover a LIFO inventory layer without physical delivery of the product. The examiner should be alert for identical "contra" agreements after the end of the year to offset the prior agreement. LIFO inventory issues are discussed in IRM 126.96.36.199.1.5.
True sale agreements and buy/sell agreements involve dispositions which are not exchanges or transfers reported in the cost of sales such as crude oil or other product transactions. The area of interest for the examination of the sales accounts, in addition to the gross receipts reconciliation, includes the special agreements with related parties (both domestic and foreign entities) and joint venture arrangements. Potential issues may involve "arm's-length" pricing, timing, and/or the character of the sales reported. Joint operations are discussed in IRM 22.214.171.124.8.
The refining/petrochemical products are ready for marketing at various points of the manufacturing process, including distillation, cracking, and treating. The various "split off" points in the manufacturing process are noted, in general terms, in the discussion in IRM 126.96.36.199.1.1 Refinery Processes.
Finished refinery products such as fuel and lubricating oil are the principal products sold. The accounting for amounts reported in gross sales of these products should be reconciled to the sales journal or ledger. Potential issues include transfers, exchanges, or sales at less than "arm's-length" value. The main line of petroleum finished products are illustrated in Exhibit 4.41.1-18.
Unfinished products in the manufacturing process are sometimes saleable for various uses, such as raw material for further refinery processing, blending, or as feedstock for many different manufacturing processes. The best known market for these "intermediate stream products" is their use in the manufacture of fertilizers, synthetic rubber, and plastics.
The petrochemical manufacturing plant may be nearby or contiguous to the refinery to take advantage of the convenient source of raw material. The plant may be an intracompany or related company-owned facility. The list of divisions and/or related companies and their business operations should be ascertained from the annual report to stockholders or SEC reports http://www.sec.gov/. The areas of interest for examination include "arm's-length" pricing and "timing" of the transactions reported on the return.
As technology progresses, substantially all of the by-products from the refining process are in demand and therefore are considered major products. The sale of by-products should be identified in the sales reported per return, usually as cost of sales rather than gross receipts.
The operator of the refinery may realize revenue from miscellaneous sources such as:
Sale of steam to contiguous or nearby facilities
Sale of electricity in circumstances similar to (a) above
Sale of scrap materials, equipment
Sale of containers, deposit recoveries
Royalties, fees, and rents from patents, know-how, catalysts, and/or facilities. This revenue should be reported as gross receipts, but some items may be included in the cost of sales or netted to an expense account.
Research and development has created technology that is a vital commodity for the refining and petrochemical industries. The demand for proven processes and the utilization of patent rights is an important source of revenue. Investments in these intangible assets and a listing of the in-house developed know-how, patents, and processes should be analyzed:
To verify the royalties and fees received from books to the return
To account for additions and removals
To verify the income reported from the disposition of all or an undivided interest in these intangible assets
To verify that the sale/transfer to a controlled foreign corporation or other related party was correctly reported
Rent or royalty income received for the use of intangible assets should include the value of any items or services received in exchange. Consideration should be given to the impact of the transactions involving these intangible assets on taxable income.
Some taxpayers maintain that long term gain under the provisions of IRC 1231 be recognized upon the sale or exchange of these intangible assets. Alternatively, others propose that no ordinary income be attributed to the sale or exchange when no "tax benefit" is realized for IRC 174 expenditures made and deducted for the creation of the intangible asset. Refer to IRC 111 and Rev. Rul. 85–186 1985-2 CB 84.
For patents disposed by the holder, IRC 1235 characterizes disposal as the sale or exchange of a capital asset held for more than one year IRC 1235(b). This special provision excludes the employer of the creator of the patent.
A significant cost incurred by a refiner will be the purchase of feedstock (crude oil) for the manufacturing processes of the refining operations. Acquisitions of domestic crude are from two primary sources: produced and purchased. In both instances, the acquisitions are treated as purchases, inasmuch the production of crude and purchases by the refiner are from different entities or from another division of an integrated oil company. Refer to IRM 22.214.171.124.6 if problems arise in the verification of the cost figures that are used by the refinery operating entity.
Foreign crude oil is a major source of supply for the operation of the refining complex. The agent should be alert to the fact that foreign crude oil, as a part of the raw material for the refining operations, can be from related producers and from unrelated suppliers. The acquisition of foreign crude can pose a problem for examiners. Foreign crude oil imports are subject to price adjustment per IRM 126.96.36.199.2.1. An international examiner or petroleum technical specialist can assist.
Also included in the cost of goods sold, more specifically as purchases, are finished products that are acquired for use in the manufacturing operations of the refining and petrochemical industry. During examination, attention should focus on inventory sections. Refer to Exhibit 4.41.1-18 for examples of finished products.
While blending stocks and additives are used for most finished products, the best known application involves gasoline. The two most important variables in gasoline blending are vapor pressure and octane number. Approximate characteristics of some blending components are found in Exhibit 4.41.1-19.
Effective engine performance involves the vaporization of the gasoline. For handling cold starting, there must be enough volatile hydrocarbon in the gasoline to get a vapor-air mixture that will ignite. Measurement of volatility is vapor pressure. Common measurement is Reid Vapor Pressure (RVP), named after the man who designed the test apparatus.
The RVP of gasoline must meet the extreme conditions of cold starts, normal running when warmed up, and restarting when hot. There is a direct correlation between a gasoline's ability to meet these conditions and the VP.
The most suitable RVP for gasolines varies with the seasons. Cold starting in northern Minnesota's cold winters requires a gasoline with a 3-pound per square inch (psi) RVP. During the hot days of August in South Texas, cars won't restart if the RVP is higher than 8.5 psi.
To avoid vapor lock, gasoline RVP may be localized to accommodate local prevailing environmental conditions as the combination of high altitudes and high temperatures can cause problems.
A review of the above approximate RVP characteristics of available blending components shows that all but one have RVP's below the usual limits of finished gasoline. Therefore, n-butane is used as the pressuring agent. Refinery production of butane, plus butane recovered from natural gas in gas recovery plants, provides an ample supply of relatively inexpensive butane or gasoline blending. The amount of butane that can be added is limited due to its high RVP.
The compression of the gasoline/air vapor in the engine heats the mixture, and it will get hot enough to self-ignite without the aid of a spark plug. Premature self-ignition produces knocking. The measurement of whether a gasoline will knock in an engine is in octane numbers. The most commonly known additive to improve the octane number of gasoline has been lead. The addition of tetraethyl lead (TEL) or tetramethyl lead (TML) does not affect any other properties, including vapor pressure. With the mandated phase-down in the lead content of gasoline and the introduction of unleaded gasoline, other additives are now available for octane improvements.
The listed approximate octane numbers of available blending components. Refer to Exhibit 4.41.1-19 for raw stock from the processing units. With the addition of lead or other additives, some components are more susceptible to octane enhancement than others.
Blending to meet octane specifications includes not only the selection of amounts of the various components, but also the octane enhancement available for each component with variable amounts of additives.
It can be seen that the octane number of straight-run gasoline is quite low for finished gasoline. The addition of butane will increase the octane number, but the amount that can be added is limited by the resulting high vapor pressure. The other blending stocks are required to meet both criteria.
Optimal blending of gasoline is not simple in overall refinery operations. Operational costs and seasonal availability of produced components, as well as costs of purchased components and additives, must be considered. Balancing the selection of components for both the desired RVP and octane rating requires the consideration of many alternatives.
Refineries utilize computers to blend finished gasoline. On-line blending may involve computer selections of streams or blending components from individual processing units and/or intermediate storage tanks, as well as the input of additives.
Additives for other than octane enhancement are commonly found in refinery operations. In some instances, chemical inhibitors or antioxidants which delay the formation of gum in gasoline are used. Coloring dyes may be used in gasolines or fuel oils. The production of lubricating oils and grease involves the use of other additives.
The nonrecognition rules of IRC 1031 apply to like kind exchanges. However, the section provides that property held for productive use in trade or business or for investment does not include stock in trade or other property held primarily for sale. Therefore, exchanges of inventoriable goods constitute a taxable transaction.
Exchange contracts of inventoriable goods are normally one of three types:
Spot. A one time exchange or an exchange that is for a short period of time.
Continuous Spot. A recurring short-term contract, often seasonal.
Continuous. An ongoing, evergreen contract that may run for several years with no fixed expiration date.
Exchanges are brought about by a need for a specific product at a specific location in a desired quantity that is not available within the system of the exchanging partner. Differentials attributable to location, handling, and grade are paid in cash and/or product.