Intangibles and Delay Rentals. The election to expense intangible drilling and development costs must be made by a taxpayer in the return for the first year in which such costs are first paid or incurred. See IRC section 263(c)(i) and Treas. Reg. 1.612–4. The election is made by claiming the intangible drilling and development costs as a deduction on the return and, when made, is binding for all future years. This election includes the right to deduct intangible drilling and development costs on productive and nonproductive wells. The failure by the taxpayer to deduct such expenses is deemed to be an election by the taxpayer to capitalize such costs. Such capitalized costs are thereafter recovered through the deductions of depletion. However, for treatment of IDC paid or incurred after 1982, see IRC section 59(e), IRC section 291(b), and IRM 4.41.1.2 and IRM 4.41.1.2.4.3. Delay rentals are required to be capitalized under IRC section 263A.

Taxpayers who are co-owners of oil and gas properties and have not elected to be excluded from the partnership provisions of Subchapter K of the Code must make a partnership level election to expense intangible drilling and development costs. If the partnership elects to capitalize such costs, the individual partners are bound by that election and may not deduct those costs on their individual returns.

For the purpose of computing allowable depletion and any gain or loss on the disposition of oil and gas minerals, the term "property " is important. The term "property" means each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land. See IRC section 614. The Code provides that all of the taxpayer's operating mineral interests in a separate tract or parcel of land are to be treated as one property unless taxpayer elects to treat such interests as separate properties. The election to treat each property as a separate property must be made in the first year the taxpayer makes any expenditure for development or operation of the property interest. The election must be made by attaching to the return a specific statement describing the tract and all the operating interest owned in the tract and must indicate which operating interests are being combined and which are being kept separate. Once the election is made, it is binding for all subsequent years.

The agent should make sure that the taxpayer is combining all income and expenses from the properties on tracts that are producing from different zones unless the proper election has been made to treat them separately.

The income from different types of oil and gas activities are reported by individuals on different schedules on their Form 1040. Royalty income is reportable by an individual on Form 1040, Schedule E. Income received from lease bonuses and delay rentals is also reported on Schedule E. Royalty income is usually not trade or business income and is generally not subject to self-employment taxes. Royalty owners do not pay production expenses other than taxes.

An individual taxpayer who owns a working interest reports income from the sale of oil and gas on of Form 1040, Schedule C. This income is considered trade or business income.

The losses realized from certain "activities" are limited to the amounts a taxpayer has "at-risk" with regard to those activities at the end of the tax year. The otherwise deductible loss from the "activity" of exploring or exploiting oil and gas reserves could be limited by the at-risk rules of IRC section 465. Each separate oil and gas property constitutes a separate activity for purposes of IRC section 465. Any losses which are limited by this section will be allowed as a deduction in the next succeeding tax year, provided there is additional at-risk basis of property at the end of that year. The amounts a taxpayer has at-risk with respect to an activity are as follows:

Examining agents need to keep in mind that in order to deduct losses from oil and gas activities, individuals must have a sufficient amount at-risk within the meaning of IRC section 465. This can be thought of and is sometimes referred to as "at-risk basis" . For example, if the taxpayer is engaged in a drilling program that is financed with borrowed funds and the leases are operating at losses, the examination should be extended to verify that the at-risk provisions of the law are being met. If the at-risk limitations are found to apply to a given oil and gas property, the transfer of lease equipment from that property to another property could trigger a realization of ordinary income under IRC section 465(e) since the assets at risk with respect to that particular activity have been decreased. Disposition of a property is not necessary for ordinary income to be realized; reduction of at-risk basis below zero can create income realization.

The typical oil and gas working interest owner or joint venture is a member of a partnership although he/she may account for his/her income and expense separately. See the definition of the term "partnership " under IRC section 761.

IRC section 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. 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 owner or working interest owners may not consider themselves to be partners.

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 section 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 section 59(e) for alternative minimum tax purposes.

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.

Elections should be made at the partnership level with respect to the following expenditures:

A discussion of oil and gas tax law would not be complete without a discussion of IRC section 704. You will remember from your previous study of partnerships that a partner's share of income and deductions will be determined from the partnership agreement. Enterprising oil and gas promoters use this provision of law 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 the investor, often the tax benefits are sufficient to justify the investment. IRC section 704(b) permits unequal allocations of deductions among partners 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 The Logic of Subchapter K by Laura and Noel Cunningham, American Casebook Series, 2nd Ed.Ed., the West Group (St. Paul, MN).

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 allowed as a deduction ratably 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 (see IRC section 709(a)). IRC section 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 sizable 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 you can usually speculate that a certain percentage of the first year management fee is for formation costs, your 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 for your adjustment. See IRC section 709.

The Tax Reform Act of 1975 added IRC section 703(a)(2)(F) to provide that the deduction for depletion under IRC section 611 is not allowable as a deduction to a partnership. Therefore, after January 1,1975, the depletion deduction must be deducted on a partner's return, not the partnership return. Due to IRC section 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 his or her own 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 his depletion deductions.

Your previous study of special partnership allocations such as losses and depreciation are equally valid in oil and gas partnerships.

As noted above, 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 section 704, but they must have substantial economic effect. A review of IRC section 704(b) and Treas. Reg. section 1.704-1(b) will provide guidance in this area. In addition, Chapter 6 of the MSSP Guide on Partnerships (Training Order No. 3123-071, 9/2002) 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. See Rev. Rul. 73–211, 1973–1 C.B. 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.

As an example, 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 whenever he/she doubts 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. See Rev. Rul. 73–211, 1973–1 C.B. 303.

A partner’s share of losses incurred by a partnership in a trade or business should be deducted on his Form 1040, Schedule E as an ordinary loss. However, IRC section 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 section 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 section 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. See IRC section 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 section 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 section 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 section 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 section 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 section 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 his/her services, a lease, and depreciable equipment, if needed, in return for a 40- to 50-percent interest in the partnership. Treas. Reg. section 1.721–1(b)1 provides that, if one partner gives up a part of his/her right to be repaid contributions of capital in favor of another partner who renders services, IRC section 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 section 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. If the capital contributed by a partner will not be returned to him/her upon liquidation of the partnership, the partner who receives the capital may be in receipt of income if he/she provided the 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 section 7704(b)); or 3) the service partner disposes of the interest within two years of receipt. Additional sources of information on this issue include:

In computing alternative minimum taxable income (AMTI), taxpayers must add back the amount by which"excess intangible drilling costs " exceed 65 percent of net income from oil and gas properties. However, IRC section 57(a)(2)(E) provides that for taxpayers other than integrated oil companies (so called "independent producers" ) the excess intangible drilling cost preference for oil and gas has been repealed for tax years beginning after December 31, 1992.

IRC section 907 provides a limitation on the amount of foreign taxes available as a credit under IRC section 901 that were paid or accrued on foreign oil and gas extraction income (FOGEI) and foreign oil related income (FORI). These limitations must be computed separately from the limitations for taxes on other foreign income.

This provision of the law can be quite complex and consideration should be given to consulting with an international examiner when FOGEI or FORI generates foreign tax credits. Refer to IRM 4.60.6.1 for referral criteria and procedures.

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 section 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 that the excess depletion is being properly accounted for. The adjustments section on Schedule M–2 of Form 1120–S should be inspected for such excess depletion adjustments.

Section 1375 imposes a corporate level tax on excess net passive income if an S corporation has C corporation accumulated Earnings & Profit. Excess net passive income is passive income in excess of 25% 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) & (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% of its gross income, the S election is terminated as of first day of the fourth year. See 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.

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 - 12 provides an illustration of the 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) became 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 increase 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 4.41.1-11 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 4.41.1-13 provides a simplified flow diagram for a modern refinery. 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 flow diagram 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.

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.

Refiners have historically used Asset Class 13.3, Petroleum Refining, for depreciation purposes. Some refiners are seeking to change their method of depreciation for certain assets used in petroleum refineries to Asset Class 28.0, Manufacture of chemicals and Allied Products. On April 2, 2002, the Industry Director for Natural Resources and Construction issued a Field Directive on this issue. The primary recommendation was that all processing assets involved in the activity of petroleum refining are to be included in MACRS Asset Class 13.3. This would include any incidental manufacturing or waste removal processes, which are integral parts of petroleum refining. See http://www.irs.gov/businesses/article/0,,id=171028,00.html.

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, etc., must be analyzed through contractual arrangements, joint ownerships, trade-offs, etc.

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 our Buna rubbers for automobile tires, etc.

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, etc.

Particular problems encountered in such joint operations are further discussed in IRM 4.41.1.6.8, Joint Operations.

In refining/petrochemical plant processes, catalysts are frequently Catalysts employed. By definition, a catalyst is a substance which hastens or retards a chemical reaction without undergoing a chemical change itself during the process. Such processes involve many substances as catalysts: acids, minerals, metals, mixed metals, metallic oxides or halides, etc. Metallic catalysts may be utilized in the free state (i.e., gauze or sponge form, etc.) 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 (operational life, recoverability, reclamation, etc.). See IRM 4.41.1.6.8.2 for further discussion of catalysts.

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 4.41.1-14. Exhibit 4.41.1-15 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. Joint operations are discussed in IRM 4.41.1.6.8.

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.

This area is a controlled issue under the responsibility of the Office of Pre-Filing & Technical Guidance (PFTG) - Petroleum. IRM 4.41.1.1.3 and IRM 4.40.4 discuss this area.

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 in IRM 4.41.1.1.3.2. It is essential that the CAS be requested as early in the examination as his need can be established. 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. A more detailed explanation can be found in the Computer Audit Specialist Handbook.

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. IRM 4.41.1.6.3 , IRM 4.41.1.6.6 and IRM 4.41.1.6.7 discuss potential examination areas.

Potential issues present in oil refineries are often common to both the chemical and petroleum industry since many refineries are part of an integrated petrochemical processing chain.

The Industry Specialization Program Handbook discusses the purpose and scope of the program. IRM 4.41.1.1.4 , discusses PIP and its responsibilities.

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.

IRC section 4081(a)(1) imposes a tax on certain removals, entries and sales of gasoline, diesel fuel), and kerosene. These three fuels are collectively referred to as "taxable fuel." Section 4041(a) imposes a 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. Section 4041(a)(1)(B) provides an exemption if these fuels were previously taxed as taxable fuels. section 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 liquified petroleum gas (such as propane, butane, pentane, or mixture of these fuels). boat. IRC section 4042 imposes a tax on any liquid used by any person as a fuel in commercial waterway transportation (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 (IRC sections 4661 & 4671):

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.

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 coownership for joint operations such as a joint venture or a partnership. See IRM 4.41.1.6.8 , 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 section 174. Rev. Rul. 80–245, 1980-2 C.B. 72, and the potential problems involving environmental impact studies are discussed in IRM 4.41.1.6.3.4.

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:

Some of the documents that should be examined for verification of acquisition costs include:

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 called for 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, etc. 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, etc.

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 well as in 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 section 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 effect, 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 section 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 section 162(a). Rev. Rul. 80–245, 1980–2 C.B. 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 section 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.

Finished or saleable refinery products are a blend of various refinery streams and sometimes include purchased blending stocks. The prime example is gasoline.

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:

The refiner's finished products inventory will include all saleable products resulting from further processing and blending of unfinished stocks. While individual refineries produce different products, and taxpayer's categorization and sub-categorization will vary. Exhibit 4.41.1-18 provides an indication 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 (Treas. Reg. 1.472–1). For non-inventory treatment of expendable, rotatable, or standby emergency spare parts, see Rev. Rul. 81–185, 1981–2 C.B. 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.

Due to rapidly increasing prices for oil and oil products, many companies have elected the LIFO method of valuation of inventory. For assistance, please contact PIP and/or the Inventory Technical Advisor.