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Part 4. Examining Process

Chapter 41. Oil and Gas Industry

Section 1. Oil and Gas Handbook (Cont. 4)

4.41.1  Oil and Gas Handbook (Cont. 4)

4.41.1.6 
Petroleum Refining

4.41.1.6.8 
Joint Operations

4.41.1.6.8.1  (07-31-2002)
Areas of Interest in Examination of Joint Operations

  1. If a partnership return has been filed, the control of the returns of the participants should be inaugurated as early as possible in the examination process so the determination may be uniformly applied and the statute of limitations protected.

  2. If a partnership return has not been filed, information reports should be disseminated as early as possible in the examination to ensure uniform application of the determination of a potential issue and to protect the statute of limitations.

  3. Does the co-ownership arrangement constitute an "association " taxable as a corporation?

  4. If the joint operations qualify as a "partnership," have the partners made an election to be excluded from the provisions of Subchapter K?

  5. Do the partners jointly sell the "partnership," products which may negate the election to be excluded from Subchapter K?

  6. Does the partnership have "startup" expenditures that should be capitalized?

  7. Are the organization expenditures properly capitalized?

  8. Do any of the partners have losses allocated to them in excess of their adjusted basis in the partnership, IRC sections 704(d) and 705?

  9. Does the operator of the refinery engage in any activity described in IRC section 465(c) subject to the at-risk rules in IRC section 465?

4.41.1.6.8.2  (07-31-2002)
Types of Catalysts

  1. As previously discussed (see IRM 4.41.1.6.1.4 ), many substances are used as catalysts. The royalty or licensing agreement for use of a particular type processing unit may also include an agreement for use of the designer's catalyst or any subsequently developed catalyst for the unit. The catalyst may be purchased or rented from parties other than the designer/licenser of the processing unit. The refiner may design its own processing unit and manufacture its own catalyst or purchase/rent the catalyst on the open market.

  2. It is not feasible to establish guidelines based on the type processing unit or on the content of the catalyst alone. Similar processing units will utilize different catalysts in different refineries. Sometimes the catalyst in a particular unit will be switched to a new improved variety. The catalyst for a particular process at one installation may involve precious metals while at another installation the precious metals are absent. One installation of a particular type process may use a liquid catalyst while another installation uses a solid catalyst with differences in operational factors. Analysis based on catalyst content alone is insufficient, as operational factors often are more indicative of proper accounting treatment.

  3. With reference to Exhibit 4.41.1 - 13 , the named processing units are indicative of the type of process involved. For each type process, there are different licensed processes available with variables in type of catalyst, type of reactor, method of regeneration (if applicable), method and timing of catalyst recharging, etc.

  4. Particle size of solid catalyst varies by the type of operation. In fixed bed reactors, the catalyst stays put in a chamber (reactor), and the hydrocarbon flows through or is dribbled through the catalyst. An extended residence time is usually found where fixed bed reactors are involved. Frequently, there are several reactors, and a cyclic operation is involved. Where regeneration is involved, several reactors may be on stream (processing the hydrocarbons) while others are in a regeneration cycle (burning off the carbon) or in a recharging cycle. The size of the catalyst in fixed bed reactors is larger than in moveable bed reactors.

  5. With moveable beds, both the hydrocarbon and the solid catalyst flow through the reaction chamber. In catalytic cracking, after a very short residence time, the mixture is separated with the catalyst circulated to the regeneration chamber. The type catalyst is generally bead or particle.

    1. The beads are approximately 1/8 to 1/4 inch in diameter and extremely porous to provide extensive reaction surface area. The small size permits movement through the chambers. Beads are not now as acceptable, as particles are more effective.

    2. The particles are much smaller and have the appearance of fine sugar or baby powder. The particle type (it also is very porous) is now more prevalent due to its fluidity. If the particles are placed in a container and the container is tilted or shaken, they react just like a fluid (liquid). The nomenclature, fluid catalytic cracker, is with reference to particle type catalysts. This type cracker utilizes the enhanced fluidity/mobility for internal movement of the catalyst through the reactor, regenerator, etc.

  6. One example of the use of liquid catalysts is in alkylation units where the catalyst is usually sulfuric acid or hydrofluoric acid. The mixture of hydrocarbons and acid is pumped through a battery of chilled reactors to provide an extended residence time. The mixture then moves to a vessel (acid settler) where no mixing takes place, and the acid and hydrocarbons separate like oil and water. As the acid circulates through the process, it gets diluted with water and picks up tar. As the acid concentration declines, it is partially drawn off, and it may be sent back to the acid supplier for refortification (purification). Internal regeneration of the catalyst is not found in this type process. The partial withdrawal of a diluted catalyst, with additions of a fresh catalyst, is an ongoing operation. It should be noted that some alkylation units utilize a solid catalyst, rather than a liquid catalyst.

  7. The reclamation costs for some catalysts may be so great, in relation to the original purchase price, that they are dumped when their effectiveness declines. Some catalysts may be used up in the manufacturing process in one way or another, even though they do not enter into the reaction itself.

  8. The use of catalysts is also involved in petrochemical operations. The production of ammonia (NH3) provides an example of the extensive use of catalysts in the petrochemical field. As seen in the above formula, ammonia contains one part nitrogen and three parts hydrogen. In many installations, the source of the nitrogen is air, and the source of the hydrogen is methane gas. The liquefaction and separation of nitrogen from air do not involve a catalyst. A mixture of methane and steam flow through furnace tubes packed with a catalyst to produce a stream of hydrogen, carbon dioxide, steam, and carbon monoxide. This stream then flows through a vessel packed with a catalyst for shift conversion of the carbon monoxide to carbon dioxide (with the generation of additional hydrogen). The produced hydrogen is separated and proportionately mixed with the nitrogen for conversion to ammonia. Such conversion requires high pressure and a catalyst. If the subsequent production of nitric acid is involved, a catalyst is also involved.

4.41.1.6.8.2.1  (07-31-2002)
Accounting Treatment

  1. There are tax accounting inconsistencies in proper capitalization, depreciation, etc., when catalysts are involved. The internal accounting instructions/procedures for catalysts (for unit cost accounting or financial accounting) of different companies vary. However, an understanding of general internal accounting procedures may be helpful in clarifying the treatment of catalyst costs. An understanding of a particular taxpayer's internal accounting procedures is essential in the agent's examination of the taxpayer.

  2. In most cases, a company will have specific procedures when catalysts with precious metals are involved. This is due to the significant costs involved and the arrangements for reclamation with credit for the precious metal(s). A single processing unit may require several million dollars worth of such catalysts.

    1. The precious metal content alone may comprise 50–65 percent of the total cost of such catalysts. The balance of the total cost would be the manufacturer's production fee, freight, and sometimes a royalty fee.

    2. When the catalyst is purchased, the total cost may be charged to a prepaid inventory account. Later, when the catalyst is issued to the process unit, a cost may be capitalized and amortized for internal unit cost accounting purposes or deducted as a current expense. The amortized cost may be the total cost, or it may be a net cost (total cost, less original metal cost or less salvage value of the metal and projected reclamation costs).

    3. Some companies may maintain the original charge is inventory on an indefinite basis and expense/amortize only the replacement quantities.

    4. It should be noted that some refiners may own excess quantities of the precious metal itself or of such catalysts, and they are sometimes rented to other companies.

  3. While those metallic base catalysts without precious metals are less costly, in many instances the cost is still substantial. As such, with reclamation and credits for spent catalysts, the nonprecious base metal(s) may require the same treatment as precious metal(s).

  4. Beyond special procedures for precious metals, some companies will (for unit cost accounting purposes) segregate catalysts based on operational differences: those that are used in quantity each month or those that are used in quantity every 12–24 months or a further extended period.

    1. Monthly utilization (make-up) might be found at some cracking units or alkylation units. Some of the catalyst is regularly partially withdrawn and is either reclaimed, sold at its salvage value, or junked. The original charge of such catalysts is normally capitalized to the cost of the processing unit and amortized (for unit cost purposes) over the useful life of the unit. The reason for such treatment is that there always is an equivalent amount of catalyst in the unit. The net cost of a fresh catalyst added (make-up) is normally expensed. Some refiners may expense the original charge for unit cost purposes.

    2. Extended utilization, without significant make-up between recharges, might be found at a reformer where the catalyst may have an effective life of 12–18 months and only small quantities are added between turnarounds. At the end of the operating period, the entire catalyst charge is removed and either reclaimed or sold for its salvage value. For unit cost accounting, some companies may expense the initial charge, as well as any subsequent additions. Others may amortize the initial charge over the life of the unit or over the effective life of the catalyst itself. From a unit cost accounting viewpoint, the preferable method would be to amortize the net cost (after crediting the cost for the salvage value of the spent material) over the effective life of the catalyst itself. With complete replacement at turnarounds, the amortization of the initial charge over the life of the unit is illogical for unit cost accounting (i.e., complete replacement at 12 months versus a unit life of 15 years).

    3. It should be noted that some catalysts have an effective life of many years before recharging is required.

  5. Proper accounting for catalysts must include coordination of the amount capitalized, the appropriate life, the accountability of reclamation credits, and treatment of sales proceeds or salvage value of spent catalysts.

4.41.1.6.8.2.2  (02-19-2008)
Depreciation

  1. Depreciation in refinery operations is discussed in IRM 4.41.1.6.7. Exhibit 4.41.1 - 21provides some useful examination techniques for catalyst accounts.

  2. As previously discussed, it is not feasible to provide guidelines for a specific processing unit or specific catalyst. However, with some understanding of how catalysts are used and with a review of the taxpayer's internal product cost accounting, the examiner should be able to properly resolve any problem areas. Engineering assistance is available for resolving questionable areas.

  3. The precious metal used in the catalyst is not consumed and very little is ever lost. It is not subject to exhaustion, wear and tear or obsolescence. As such, depreciation (Treas. Reg. 1.167(a)–2) on the precious metal content of catalysts is not allowable.

  4. Four revenue rulings are frequently cited when precious metal catalysts are involved.

    1. Rev. Rul. 68–192, 1968–1 C.B. 78, states "… the life of radium has been scientifically estimated to be indeterminate … the cost must be capitalized … but no deduction is allowable for depreciation."

    2. Rev. Rul. 72–507, 1972–2 C.B. 198, held that the costs of nuclear fuel elements are capital expenditures subject to the allowance for depreciation.

    3. Rev. Rul. 75–491, 1975–2 C.B. 19, states"…the tin is not a material of construction that becomes part of a depreciable property, it does not lose its identity as tin in the elemental state."

  5. None of the above revenue rulings actually involved catalysts. Most practitioners will admit that Rev. Ruls. 68–192 and 75–491 are general rulings that elemental metals are not depreciable. However, some firms advocate that there is no authority for holding that a manufactured asset should be considered nondepreciable because of metallic content. Their basic premise is the contrast between Rev. Rul. 68–192, holding radium nondepreciable and Rev. Rul. 72–507, holding nuclear fuel assemblies depreciable. Based on the different basic characteristics and the actual product recovered (reclaimed) between nuclear fuel elements and precious metal catalysts, it is believed that Rev. Rul. 72–507 can be distinguished and held not applicable for precious metal catalysts.

  6. Excluding the cost of the precious metals (and in some cases, the cost of nonprecious metals), the other capitalized costs of the catalyst charged to a process unit are depreciable. Based on operational factors, the useful life may be either the life of the processing unit or the life of the catalyst. See Rev. Rul. 90–65, 1990–2 C.B. 41.

4.41.1.6.8.3  (07-31-2002)
Extraordinary Losses

  1. Refineries are prone to have fires and explosions occasionally due to the inherent nature of refining operations and the highly volatile nature of the products involved.

  2. The agent should check local publications, company news items, annual reports, and SEC filings for such losses.

  3. If an extraordinary loss has occurred in a year under examination, the agent should determine if there has been a write-off concerning the casualty loss.

  4. Any casualty loss claimed should be verified to determine that the write-off is limited to the property lost in the casualty and that proper consideration has been given to potential insurance recoveries.

  5. The casualty loss may involve lawsuits and damages of property owned by unrelated parties. The agent should check for contingency reserves which have been set up for the possible liability resulting from the casualty.

4.41.1.6.8.3.1  (07-31-2002)
Abandonments and Discontinued Operations

  1. Examiners should insure that any deductions for property claimed to be worthless are valid.

  2. Examiners should ascertain whether the plant has actually been closed permanently or is merely being placed on a standby basis. This can often be determined in the following ways:

    1. A review of corporate minutes or other internal documents should ascertain who authorized the shutdown or abandonment.

    2. A review of maintenance expenses could disclose extensive maintenance not normally present in an abandoned plant.

    3. Contacts with local taxing authorities will often provide data as to any changes in assessed valuation of property in question.

  3. In the event the taxpayer claims the loss as a result of suits brought by environmental groups and/or agencies, the examiner should ascertain the status of pending appeals.

  4. Examiners should insure that property held to be abandoned is not being offered for sale.

  5. When facilities are shutdown (abandoned or placed on standby) and the expensive catalysts are recovered, was proper tax accounting treatment given to the recovery and disposition of such catalyst?

  6. Examiners should also be certain to review Schedule M for any possible differences between book and tax treatment.

4.41.1.6.8.3.2  (07-31-2002)
Fines, Penalties, and Payments in Lieu of

  1. No deduction is allowed for any "fine or similar penalty " paid to a government for the violation of "any" law, IRC section 162(f) as enacted by Public Law 91–172 (1969). The Senate Finance Committee made the following statement regarding IRC section 162(f) in comments explaining section 310 of the Revenue Act of 1971, P.L. 92–178, "In approving the provisions dealing with fines and similar penalties in 1969, it was the intention of the committee to disallow deductions for payments of sanctions which are imposed under civil statutes but which in general terms serve the same purpose as a fine exacted under a criminal statute. "

  2. Treas. Reg. 1.162–21(b) provides that a fine or similar penalty includes an amount paid or incurred in settlement of the taxpayer's actual or potential liability for a fine or a penalty (civil or criminal).

  3. It should be noted that a payment in lieu of a fine, or a payment made as compromise of such a liability takes on the character of the underlying asserted obligation and it is similarly nondeductible, Adolph Meller Company F2d 1360 (Ct. Cl. 1979). Amounts deducted as contributions may, in fact, be made as a settlement of, and in lieu of, a penalty or under an agreement for nonprosecution involving a fine or a penalty (civil or criminal). It is well established that, " a contribution or gift, for the purpose of section 170, is a voluntary transfer of money or property made by the transferor without receipt or expectations of financial or economic benefit." , Rev. Rul. 76–257, 1976–2 C.B. 52. Rev. Rul. 79–148, 1979–1 C.B. 93 determined that the amount paid by the taxpayer to the charitable organization in satisfaction of a judgment or as a condition of probation by a federal district court is "not deductible under IRC section 162(a) of the Code because the amount paid was a fine for purposes of section 162(f)." Furthermore, this ruling holds that such a payment does "not qualify as a charitable contribution, it is not deductible under section 170 of the Code."

  4. The examiner should be alert to identify fines and penalties which may be erroneously classified and/or inadvertently claimed as a deduction.

  5. A deduction claimed in a subsequent year(s) via a schedule M adjustment requires a review of the earlier year's basis for the payment.

4.41.1.6.9  (02-19-2008)
Pipeline Right of Way

  1. Effective March 8,1971, the Service modified an earlier ruling and announced its current position on high pressure natural gas pipeline right of way easement, clearing, and grading costs (Rev. Rul. 71–120, 1971–1 C.B. 79). The same position was announced effective October 27, 1971, for crude oil and petroleum products pipeline costs (Rev. Rul. 71–448, 1971–2 C.B. 130).

  2. These rulings hold that easement costs (including aerial reconnaissance, preliminary surveys, roddage fee payment to the grantor based on length of the easement, crop damage reimbursement, legal fees, title work, abstract and recording fees, etc.) have a determinable life measured by the useful life of the pipeline and are, therefore, depreciable. Since easement costs are similar to a license or franchise, they are considered an intangible asset and will not qualify for any accelerated depreciation. Depreciation of right of way costs must be calculated using the straight line method. See Panhandle Pipe Line Co. v. U.S., 408 F2d 690 23 AFTR 2d 933 (Ct. Cl. 1969).

  3. Rev. Rul. 72-403, 1972-2 C.B. 102, holds that clearing and grading of the right of way are part of the pipeline construction costs and, as such, qualify for accelerated depreciation methods and investment credit when applicable and that initial clearing and grading are not included in any of the asset guideline classes for ADR purposes. Under Rev. Proc. 87-56 (for MACRS property), initial clearing and grading land improvements as specified in Rev. Rul. 72-403, are excluded from asset class 00.3, Land Improvements, asset class 46.0, Pipeline Transportation, and asset class 49.24, Gas Utility Trunk Pipelines and Related Storage Facilities. The American Jobs Creation Act of 2004 added IRC section 168(e)(3)(E)(v), which provides that 15-year MACRS property includes initial clearing and grading land improvements with respect to gas utility property.

  4. The costs for the easement and for clearing and grading referred to above do not include expenditures incurred to keep the right of way clear and the pipeline in its normal operating state. Whether such expenditures are ordinary and necessary expenses or capital expenditures requires a determination based on facts and circumstances of each case.

4.41.1.6.10  (02-19-2008)
Inventory in the Pipeline

  1. In order to maintain pressure and effect uninterrupted flow or transportation of natural gas to purchasers through pipelines, it is necessary to maintain a certain volume of gas in the lines at all times. This volume of gas is called "line pack" by the industry. Some taxpayers will expense this cost as ordinary and necessary business expense. Some may attempt to capitalize this cost as part of the pipeline cost and depreciate it over the life of the pipeline.

  2. Charges incurred by retail gas utilities obtaining natural gas for resale are includable inventory costs. These costs include damage charges, capacity charges, injection charges, storage charges, withdrawal charges, delivery charges, etc. (Rev. Rul. 66–145, 1966–1 C.B. 98).

  3. While it is true that only oil will be flowing through the pipeline, different grades of oil may be in the pipeline at the same time. It is possible to space different grades of oil by running a cleaning tool (called a pig) and a water spacer between each type of oil. In this manner, it is possible to have many different types of petroleum products in the pipeline at yearend. Therefore, it is necessary to determine, with the help of a petroleum engineer, not only the quantity of the oil in the pipeline but also the type of oil. Once the quantity of the specific types of oil is determined, then the correct price must be applied to arrive at the correct ending inventory.

  4. In examining a pipeline, the agent should first determine what type of line is in use (gas or oil). Determine how the taxpayer handles the line pack or oil in the line expensed, capitalized or inventoried. If he/she inventoried the costs, determine whether all costs pertaining to the inventory are included. If the taxpayer has an oil line, ensure that the costs taken into inventory reflect the correct costs based on the correct type of oil. It is possible that the taxpayer, while correctly including the oil in inventory, may have assigned one cost for the entire oil in the pipeline while, in reality, different prices should have been used since different oils were in transit at year end.

4.41.1.7  (07-31-2002)
Use of Average Freight Rate Assessments (AFRA)

  1. This section sets forth the circumstances under which the Service will accept the use of Average Freight Rate Assessments (AFRA) as a measure of the cost of sea transportation incurred on crude oil and products. Rules are given for the allowance of AFRA as well as for the allowance of other charges associated with sea transportation such as transshipment, lightering, deadfreight, and demurrage.

4.41.1.7.1  (10-01-2005)
Overview of AFRA

  1. One of the major elements in the cost of foreign crude oil and products imported into the United States is the freight charge. Foreign crude oil and products are typically purchased by U.S. importers f.o.b. the loading port. Freight charges are, thus, determined separately and are usually paid to a company engaged in the transportation of oil. Thus, it is necessary for the Service to review these intercompany charges and make appropriate adjustments under IRC section 482 when it is determined that such charges do not meet the arm's-length standard set forth by the regulations.

  2. AFRA is one of the principal means used by the oil industry on a worldwide basis to determine intercompany freight charges.

  3. When a U.S. importer pays shipping charges directly to an independent shipper for all crude oil and products imported into the U.S., such charges will ordinarily be allowed as a cost element for the crude oil or products.

4.41.1.7.1.1  (10-01-2005)
Acceptance of AFRA

  1. Under the Delegation Order No. 153, as revised, the Director, Natural Resources & Construction, has been assigned the nationwide authority and jurisdiction to determine the acceptance of AFRA and/or other freight rate determination methods as an intercompany charge for shipping of foreign-produced crude oil and products.

  2. The IRS has evaluated and monitored AFRA on a continuing basis. AFRA is supported by subscriptions paid by oil companies, oil traders, shipping companies and others using AFRA. The terms of reference are now the responsibility of the London Tanker Brokers Panel. The IRS will make periodic reviews to determine if AFRA remains an acceptable basis for computing freight charges. A major change in the terms of reference under which AFRA is computed may be cause for rejection of its use for tax purposes. The Panel has agreed to notify the IRS prior to making any material changes to the terms of reference.

  3. A company importing crude oil may adopt the use of AFRA to compute its intercompany and/or intracompany ocean freight charges. The IRS has accepted the use of AFRA provided the applications are made in the manner described in IRM 4.41.1.7.1.4, Application of AFRA.

  4. If AFRA is adopted by a company, it should be used for all shipments of crude oil imported into the United States, except for those categories specifically excluded. See IRM 4.41.1.7.1.2 (8). In that AFRA reflects the tanker market over an extended period of time, a company should adopt AFRA only if it intends to use the system for an extended or indefinite period. The Service will not accept shifts to and from AFRA because of changes in market levels.

4.41.1.7.1.2  (10-01-2005)
Description of AFRA

  1. AFRAs are calculated on a monthly basis by the London Tanker Brokers' Panel. The rates are published as of the first day of each month based on the data for the month ended on the 15th day of the previous month. The publication of AFRA is financed on a paid subscription basis and reproduction is restricted.

  2. The London Tanker Brokers' Panel has access to details of charters between oil companies and independent shipowners. The assessments calculated by the Panel are an average of all charters in force for a given period of time, with each charter rate weighted by the carrying capacity of the particular ship.

    Example:

    All charters in effect from April 16, 2004, through May 15, 2004, are averaged and published as AFRA assessments for June 1, 2004; these rates are intended to be used for all cargos loaded during the period June 1, 2004, through June 30, 2004.

  3. AFRA is an average of all charters for vessels in service during a specified period, irrespective of the dates on which the charters were concluded. It includes time charters and charters for consecutive voyages, both for long term and short term periods, and single voyages (or spot) charters. The charter rates are weighted according to the amount of cargo carried.

  4. The traditional AFRA is published for five categories of vessels based on size expressed in deadweight long ton (dwt). The categories are:

    Name of Category Size of Range
    Medium Range Vessels (MR) 25,000–44,999 dwt
    Large Range 1 Vessels (LR–1) 45,000–79,999 dwt
    Large Range 2 Vessels (LR–2) 80,000–159,000 dwt
    Very Large Crude Carriers (VLCC) 160,000–319,999 dwt
    Ultra Large Crude Carriers (ULCC) 320,000–549,999 dwt

  5. AFRA assessments are expressed in terms of Worldscale. Worldscale is a series of standardized, nominal freight rates computed jointly by two non-profit making associations situated in London and New York and managed respectively by British and American tanker brokers. Worldscale rates are widely used in the shipping industry to denominate charter rates between independent parties as well as for AFRA and other purposes. Worldscale published rates, computed in U.S. dollars per metric ton, are cited as "Worldscale 100 " or W100. Thus, an AFRA assessment of W60 would indicate that the rate for any particular voyage would be 60 percent of the Worldscale dollar rate for that voyage.

  6. Worldscale rates are revised annually. Examiners should ensure that the rates used are appropriate for the period under examination.

  7. Worldscale rates are expressed in U.S. dollars per metric ton. Rates can be expressed in U.S. dollars per barrel by using standardized tables published in trade journals giving the number of barrels per metric ton for each American Petroleum Institute (API) gravity of oil.

  8. AFRA should not be used for certain categories of shipments, even though it is adopted for general use. These excluded ships correspond to the categories which are excluded from the computation of AFRA. Freight charges for use of tankers in the excluded categories below should be determined on a case-by-case basis. Currently, the excluded categories are:

    1. Vessels under 16,500 dwt and over 549,999 dwt

    2. Vessels laid up or idle

    3. Government-owned vessels, except those operating on commercial charters

    4. Vessels carrying clean products (e.g., gasoline, naphtha). AFRA may be used for the transportation of "dirty " products, e.g., fuel oil

    5. Vessels engaged in specialized trades, such as petrochemicals, lube oil, asphalts

    6. Vessels engaged in other trades, e.g., tankers carrying grain, molasses, whale oil

    7. Vessels engaged in protected coastal trade (e.g., U.S. flag vessels)

    8. Vessels engaged in lightering other vessels

  9. Beginning January 1, 1985, at the request of the Service, The London Tanker Brokers' Panel Ltd. began calculating and providing free of charge on request to any subscribers a multirate AFRA. The multirate AFRA is a computer generated interpolation of the traditional AFRA category rates based on the average size of vessel in each category. The manner of application of the multirates is the same as the traditional five category rates described in IRM 4.41.1.7.1.4.

4.41.1.7.1.3  (10-01-2005)
Exceptions to Use of AFRA

  1. The nature of AFRA requires that it be used only by those companies which regularly and continuously transport crude oil and products by sea. Thus, AFRA should not be used to compute intercompany freight charges by companies which only occasionally purchase foreign oil.

    Example:

    A company, a U.S. refinery, ordinarily buys only domestic crude oil. However, in 2004 it contracts to buy 2 million barrels of Persian Gulf crude oil to be delivered over a 6-month period, July through December 2004.
    a. Through a Bahama Islands subsidiary, it charters a tanker from a third party for the six-month period, July through December, to deliver the oil to the U.S. The Bahamas company then charges the U.S. parent AFRA rates on the actual delivery of the oil to the U.S.
    b. Since this is only an occasional purchase of foreign oil, AFRA should not be used to determine the charge to the U.S. refinery. Instead, the charges should be based on an arm's-length charge for a six-month charter, July through December 2004. The examiner should make an adjustment if it is appropriate.
    c. No hard and fast rule can be made as to precisely what constitutes "occasional" transportation as opposed to "regular and continuous" transportation. In questionable cases, examiners should consult with the Petroleum Industry Program Manager.

  2. AFRA is a charge for the transportation of oil and not a measure of current charter rates. Therefore, it should not be used as a measure for chartering ships between affiliated companies. Intercompany ship charters should be based on current market charter rates. Intercompany chartering of ships should not be confused with the exchange of tonnage, in which the use of AFRA may be appropriate.

  3. AFRA may not be accepted by the IRS if all or part of the foreign-flag chartered-in tankers included in the company's fleet are chartered by the U.S. importer or by any U.S. affiliate of the importer. For AFRA to be acceptable, such ships should be chartered by the foreign shipping affiliate or other foreign affiliates.

    Example:

    The U.S. importer regularly pays AFRA rates to its affiliated shipping company. However, because of an inflated tanker market the U.S. importer charters directly from independent shipping companies for a part of its needs. This is an abuse of AFRA; in that, the affiliated shipping company is supplying the importer's needs when it is profitable to do so and the importer is chartering directly when it is not profitable for the affiliate.

4.41.1.7.1.4  (07-31-2002)
Application of AFRA

  1. The method of applying AFRA to shipments is based on the route and size of vessel used for the particular shipment. For periods prior to January 1, 1985, the traditional AFRA results must be used. For the period January 1, 1985 through June 30, 1985 the use of the multirate AFRA is optional. After June 30, 1985 only the multirate AFRA is acceptable for federal tax purposes. The following is a description of the application of AFRA together with the steps to be taken by examiners in verifying intercompany freight charges for each cargo of oil imported.

    1. Determine the size of the vessel used to transport the oil expressed in deadweight tons (dwt) computed at the ship's summer marks. The summer deadweight tonnage is a standard statistical measurement of ships as reported in many trade manuals. The summer dwt determines the AFRA rate that will apply to the shipment.

    2. Determine the loading date. Normally, this date is the date actual loading began or the date the notice of readiness to load is presented. The loading date determines the monthly AFRA assessment to be used. The loading date used historically by the company will be accepted provided it is applied consistently to all shipments. The loading date determines the AFRA rate even though the loading period is divided between two months.

      Example:

      If the company's loading date falls on June 30, the AFRA rates published for June 1 will apply to the full cargo even though loading is not completed until July 1, or later.

    3. Determine the appropriate AFRA assessment to be used based on the category size and the loading date.

    4. Determine the Worldscale nominal freight rate for the voyage from the loading port to the discharge port applicable at the loading date.

    5. Determine the AFRA rate per ton of cargo by multiplying the Worldscale nominal freight rate [step (d) above] by the AFRA index [step (c) above]. If the route includes transit of the Suez or Panama Canals, transit fees must be added to the AFRA rate per ton.

    6. Determine the gross tons of cargo loaded on board the ship.

    7. The total freight charge to be allowed on the cargo is determined by multiplying the gross tons of cargo [Step (f) above] by the AFRA rate per ton of cargo [Step (e) above]. Exhibit 4.41.1-22 shows an example of the computation under AFRA.

  2. The elements of this computation may be converted from metric tons to barrels and vice versa by using the standard conversion rates based on the average API gravity of the cargo transported.

  3. Rates for multiport loading and discharge are provided in the Worldscale publications. Two-port loading does not require an allocation. Two-port discharging may require an allocation of the shipping charge. The allocation should be examined when the discharges are made in separate countries or between separate companies. The total AFRA charge for the two-port discharge should be allocated to the separate ports on the basis of the relationship of the charge to each port computed separately. The separate charges should be computed using the tons delivered times the AFRA category rates based on the cargos delivered. Other methods of allocation used by the taxpayers will be accepted provided the charges do not exceed the following limitations:

    1. The amount allocated to either port should not exceed the charge that would have been incurred if the cargo had been delivered using a single discharge vessel rate based on the cargo size.

    2. The combined total of the amount allocated to both ports should not exceed the total amount determined by the total tons delivered using the two-port discharge rate.

4.41.1.7.1.4.1  (10-01-2005)
Cargo Sharing

  1. Cargo sharing referred to in this section relates to foreign crude transported into the United States by a shipping company charging AFRA rates to an affiliate and the transporting of crude oil for a third-party customer on the same voyage. An example of the method of computing cargo sharing is shown in Exhibit 4.41.1-23.

  2. The AFRA charge to the related importer when the shipment involves cargo sharing is limited to the lesser of:

    1. The charge computed on the basis of the multiport rate times the total cargo carried on the voyage less the amount actually paid by the third party.

    2. The charge computed on the basis of the single-port discharge rate for the AFRA category determined by the cargo size times the actual cargo received.

4.41.1.7.1.4.2  (07-31-2002)
Space Sharing

  1. Space sharing referred to in this section relates to foreign crude oil imported into the U.S. by an affiliated shipping company when the cargo is transported on a third-party vessel. The allowable charge to the U.S. importer by the affiliated shipping company for cargo moved in a third-party vessel on a space sharing basis is the greater of:

    1. The imported cargo times the AFRA rate for the vessel used.

    2. The actual amount paid by the affiliate shipping company to the third party for transporting the crude.

4.41.1.7.1.4.3  (07-31-2002)
Abuses of AFRA Applications

  1. Examiners should be alert to potential abuses in the application of AFRA.

    1. Examiners should verify that the vessels are correctly classified based on the dwt when determining the rate to be used.

    2. A charge for deadfreight (see IRM 4.41.1.7.2) is not allowable on space required for bunkers, stores and water. As a general guide approximately four to five percent of the vessel's dwt is not available for cargo on vessels below 100,000 dwt. For vessels 100,000 dwt and over the space not available for cargo is approximately three percent.

4.41.1.7.1.5  (07-31-2002)
Freight Charges in Addition to AFRA

  1. The freight rates computed under AFRA cover charges for bunkers, port charges, and brokers fees in addition to the normal operation costs of the ship which are to be paid by the shipping company. In addition, AFRA rates take into account an average non-steaming time to cover delays and lay time. None of these costs should be charged to the importer. Certain additional charges, however, may be incurred which are to be borne by the importer. The rules for the allowance of these charges are discussed below.

4.41.1.7.1.6  (07-31-2002)
Transshipment

  1. Transshipping charges are those incurred in transferring cargo from one ship directly to another ship or to an on-shore terminal for later loading on another ship. The cost of transshipping is a proper charge to the importer.

  2. Transshipping has become significant with the shipment of Persian Gulf and African crude oils to terminals in the Caribbean for later shipment to U.S. ports. The U.S. importer will be charged AFRA rates for the two legs of this journey plus a transshipping fee paid to the terminal owner. When transshipping occurs at sea or outside a port listed in the Worldscale service, the U.S. importer will ordinarily request the associations preparing Worldscale to compute special freight rates to the point of transshipment.

  3. When the transshipping fees are paid to affiliated companies, such charges should be made at arm's-length standards, taking into account the cost of transferring oil between ships or between ships and terminals and the period of storage, if any. Examiners should analyze such intercompany fees.

4.41.1.7.1.7  (07-31-2002)
Intransit Pipeline Costs

  1. Intransit pipeline costs are those incurred in transferring cargo from one ship via pipeline to another, e.g., transferring cargo from a Red Sea port to a Mediterranean seaport via the Sumed pipeline. Pipeline related tariff and other transfer expenses are proper charges to the importer. As with transshipping costs, when intransit pipeline costs are paid to affiliates, they should be at arm's-length.

4.41.1.7.1.8  (07-31-2002)
Lightering

  1. Lightering is a charge of unloading a part of a cargo into barges or other small ships to enable the tanker to be berthed in a port which is not large enough to accommodate the tanker when fully loaded. The term lightering has also been used to describe the complete off-loading of a vessel. This has generally been considered transshipping. In either event the cost of lightering is a proper charge to the U.S. importer. When the lightering charge is paid to an affiliate, the charge is subject to the arm's-length standard.

4.41.1.7.2  (10-01-2005)
Deadfreight

  1. Deadfreight is the excess cargo capacity on a partially loaded tanker, e.g., a 90,000 dwt ship with a cargo of 60,000 tons of cargo, stores, bunkers, etc., would have 30,000 tons of deadfreight. Tankers may be light loaded for the following reasons:

    1. To allow them to berth in ports which are not large enough to accommodate the tankers when fully loaded

    2. Non-availability of sufficient cargo at the loading port

    3. Lack of sufficient storage space at the discharging port

    4. Need to transit waterways with draft restrictions

  2. Deadfreight is not an allowable charge to the importer when it is incurred for the benefit or convenience of the shipping company.

  3. Prior to 1985, when deadfreight was incurred for the benefit of the importer, the charge will be allowed to the extent the cost per barrel incurred does not exceed the cost per barrel for the vessel class of the largest fully loaded vessel which can make the voyage between the ports of loading and unloading under the normal operating conditions. The charge is measured by the amount of deadfreight tonnage times the AFRA rate applicable to the vessel size. For the purposes of this test, the following draft rules based on fully loaded vessels are recommended as a guide to determine the port classification.

    Port Drafts Port Classification
    22–30 ft. General Purpose (GP)
    31–36 ft. Medium Range (MR)
    37–41 ft. Large Range 1 (LR–1)
    42–54 ft. Large Range 2 (LR–2)
    55–71 ft. Very Large Crude Carrier (VLCC)
    72 and above Ultra Large Crude Carrier (ULCC)

    Example:

    A 100,000 dwt vessel is used to transport 82,000 tons of crude from Jebel Dhanna, Abu Dhabi to Portland, Maine. The cost per ton determined by dividing the total shipment charge including deadfreight by the tons of delivered cargo cannot exceed the cost per ton for the AFRA category of the largest fully loaded vessel that can make the voyage between the loading port and the discharge port. The 100,000 dwt vessel is in the LR–2 category. The draft limitation for Jebel Dhanna is 49 feet which is a LR–2 port. The draft limitation for Portland, Maine, is 45 feet which is a LR–2 port.
    Based on the port category size, the largest fully loaded vessel that could make the voyage is a LR–2 vessel. No deadfreight would be allowed in this example because the vessel category is the same as the category for the largest fully loaded vessel that could make the voyage. An example of the method of computing the deadfreight limitation for periods prior to January 1,1985, is shown in Exhibit 4.41.1-24.

  4. After December 31, 1984, beginning with the use of multirate AFRA (which was optional between January 1,1985, and June 30, 1985), the allowable deadfreight will be determined based on the following rules. The total charge for voyages involving allowable deadfreight will be limited to the lesser of: the total tons carrying capacity reduced by the amount that the actual cargo is less than 70 percent of the vessel dwt times the rate determined by the vessel dwt, or the actual cargo tons loaded times the rate based on 103 percent of the cargo. It is assumed that 103 percent of the cargo represents the smallest fully loaded vessel that could carry the cargo. The intent of the rules is to allow deadfreight at the vessel rate up to 30 percent of the vessel dwt. The amount allowable is limited to the actual cargo times the rate based on the cargo size plus three percent for non-cargo capacity. An example of the deadfreight calculation using the multirate AFRA is shown in Exhibit 4.41.1 - 25.

4.41.1.7.3  (07-31-2002)
Demurrage

  1. Demurrage is a charge paid to a vessel owner or operator when a vessel is delayed in port beyond the lay time allowed by contract. The allowed lay time varies with each contract, usually depending on the size and loading capacity of the vessel; however, allowed lay time of 72 hours is common. Demurrage may be allowed if, due to the fault of the seller or buyer of the cargo, loading or unloading is not completed within the allowed lay time.

  2. Worldscale volumes include standard tables giving demurrage rates for various size ships. These rates can be used in conjunction with the AFRA assessments to determine the amount of demurrage on a particular shipment. For example, the Worldscale volume gives the demurrage rate for a 90,000 dwt ship as $15,200 per day. If the AFRA assessment for the particular shipment is W60, the daily demurrage rate would be $15,200 x 60 percent or $9,120. This rate is equivalent to $380 per hour.

  3. Demurrage is an allowable charge to the importer in addition to AFRA to the extent the importer caused the delay that resulted in the demurrage charge.

    1. The importer is not responsible for vessel related delays such as vessel equipment malfunctions, fueling, late arrival or vessel operations. Storm delays may be shared by both parties.

    2. The importer is not normally responsible for delays at the loading facility. The title to the crude purchased on an FOB basis passes to the importer as the crude is loaded onto the vessel. Delays in the loading port may be paid by the importer and recovered later from the producer or seller.

    3. The importer may be responsible for the demurrage charge at the discharge port when the delay is caused by the importers employees or facilities.

      Example:

      If the importer's offloading equipment, pipeline or storage facility malfunctioned the delay would be its responsibility. If the offloading facilities belong to a third-party they may be responsible for the delay. If the delay is caused by the vessel's equipment the shipping company is responsible.

    4. Demurrage is incurred when the actual time for the voyage exceeds the contract time. If there is no specific identifiable cause for the delay it will be assumed to be related to the vessel and the shipping company will not be entitled to demurrage.

  4. Demurrage charges are applicable only to the normal delays incurred in loading and discharging cargo. When extended delays are incurred and the delays indicate the ship is being used for storage, the demurrage rate should be adjusted by the examiner to an amount commensurate with on-shore storage, if appropriate. Such adjustments must be made on a case-by-case basis.

4.41.1.7.4  (07-31-2002)
Other Charges

  1. Charges such as insurance, fees, and taxes not included in the Worldscale or AFRA calculations will be allowed to the U.S. importer or to the shipper in accordance with industry practice.

4.41.1.8  (10-01-2005)
New Tax Provisions

  1. This section provides information on tax law that has been recently passed.

4.41.1.8.1  (02-19-2008)
Working Families Tax Relief Act of 2004 (P.L. 108-311)

  1. On October 4, 2004, the President signed into law the Working Families Tax Relief Act of 2004 (P.L. 108-311). Income tax provisions affecting the domestic petroleum industry are summarized in Exhibit 4.41.1-27 Working Families Tax Relief Act of 2004 Income Tax Provisions.

4.41.1.8.2  (02-19-2008)
American Jobs Creation Act (P.L. 108-357)

  1. On October 22, 2004, the President signed into law the American Jobs Creation Act (P.L. 108-357). Income tax provisions affecting the domestic petroleum industry are summarized in Exhibit 4.41.1-28 American Jobs Creation Act Income Tax Provisions.

4.41.1.8.3  (02-19-2008)
Energy Policy Act of 2005 (HR6)

  1. On August 8, 2005, the President signed into law the Energy Policy Act of 2005 (HR6). Income tax provisions affecting the domestic petroleum industry are summarized in Exhibit 4.41.1-29 Energy Policy Act of 2005 Income Tax Provisions.

4.41.1.8.4  (02-19-2008)
Tax Increase Prevention and Reconciliation Act of 2005 (P.L. 109-222)

  1. On May 17, 2006, the President signed into law the Tax Increase Prevention and Reconciliation Act (TIPRA) of 2005 (P.L. 109-222). Income tax provisions affecting the petroleum industry are summarized in Exhibit 4.41.1-30 Tax Increase and Reconciliation Act of 2005 Income Tax Pro-visions.

4.41.1.8.5  (02-19-2008)
Tax Relief And Health Care Act of 2006 (HR6111)

  1. On December 20, 2006, the President signed into law the Tax Relief And Health Care Act of 2006 (HR6111). Income tax provisions affecting the domestic petroleum industry are summarized in Exhibit 4.41.1-31 Tax Relief And Health Care Act of 2006 Income Tax Provisions.

4.41.1.9  (10-01-2005)
Definition of Terms Pertaining to the Oil and Gas Industry

  1. Abandonment Costs: Once production from an oil or gas well becomes unprofitable the well is abandoned. Usually, before a well is abandoned, some of the casing is removed and salvaged and one or more cement plugs are placed in the borehole. In many states, abandonment must be approved and by the official regulatory agency.

  2. Absorption: The physical assimilation of one substance into another; the extraction of one or more fluids from an atmosphere or mixture of gases or liquids by the substance of a sorbent material with which the atmosphere, gases, or liquids come in contact.

  3. Acidize: To treat an oil-bearing formation with acid causing a chemical reaction, thereby increasing pore space and permeability in the immediate vicinity of the bore hole. This allows easier passage of oil to the hole.

  4. Acid Treating: A process for removing undesirable (chemically active) constituents of oil by contacting with sulfuric acid.

  5. Acquisition Well: A well drilled in return for a mineral interest in a property.

  6. Acreage Selection Option: A provision in a leasing agreement giving the grantee the right to select certain acreage, for the purpose of additional exploration or development, out of the total acreage explored.

  7. Active Income/Losses: Income/losses generated from an activity (trade or business) in which the taxpayer materially participates on a regular, continuous, and substantial basis.

  8. Actuals: The physical, cash, or spot market commodities, distinguished from commodity futures.

  9. Additive: A chemical or other product that enhances certain characteristics or gives them other desirable properties (e.g., adding methyl tertiary butyl ether to gasoline to improve its octane).

  10. Adsorption: The adhesion of molecules of gases or liquids to the surface of other bodies, usually solids, resulting in a relatively high concentration of the gas or solution at the point of contact.

  11. Advance Royalty: An advance payment made by the owner of an operating interest to the royalty owner for a specific number of units of minerals regardless of whether oil or gas was extracted during the year. The payment is recoupable out of the future production.

  12. AFE: Authorization for expenditures.

  13. AFRA: Average Freight Rate Assessments. A measure of the cost of sea transportation incurred on crude oil and products.

  14. Alkali: Any substance, such as ammonia, or caustic soda, containing a reactive hydroxide or oxide that forms a salt when reacted to neutralize acid. It is often referred to as a base.

  15. Alkylate: Product obtained in the alkylation process. Chemically, it is a complex branched molecule of the paraffinic series. The alkylate will be of higher octane than the feedstock.

  16. Allowables: Most oil producing states have regulatory agencies that are concerned with the conservation of natural resources, including extractive minerals. In regard to oil and gas, efficient extraction rates promote conservation of the resource. State regulatory agencies determine the amount of production that will be allowed within a given period. This may be stated in terms of producing days, or as a percentage of full production, and is usually figured on the basis of the individual well. The term "allowable production" has been shortened to allowables. These allowables are based on the market demand for oil or gas and the most efficient rates of production for the particular fields.

  17. Anhydrous: Lacking water, dry, including loss of water in crystallization.

  18. Anticipatory Hedge: A hedge involving the purchase and sale of futures contracts or forward commitments to protect against adverse changes in prices for anticipated transactions. For example, an oil producer may sell a futures contract to fix the price of future production.

  19. Antioxidants: Chemicals added to gasoline, lubricating oils, waxes, and other products to inhibit oxidation, and thus, degradation of fuel quality.

  20. API: American Petroleum Institute.

  21. Arbitrage: The simultaneous purchase and sale of identical or substantially similar securities or commodities in different markets in order to benefit from a price differential.

  22. Area of Interest: The original project area is subdivided into smaller projects, or "Areas of Interest", to conduct more intensive geological and geophysical exploration in order to determine whether to acquire or retain certain mineral interests within or adjacent to the area of interest. The costs incurred with respect to these surveys are capital in nature, and must be added to the basis of any mineral interests acquired or retained and are recoverable through depletion or deductible as a loss upon abandonment. See Rev. Rul. 77–188, 1977–1 C.B. 76; Rev. Rul 83–105, 1983–2 C.B. 51.

  23. Aromatics: Hydrocarbons derived from or characterized by the presence of the benzene ring. Some of this large class of cyclic and polycyclic organic compounds are odorous. Most burn with a sooty flame but have high octane numbers.

  24. Ash: Inorganic residue remaining after ignition of combustible substances, measured by standard prescribed methods.

  25. Ask: The price at which a commodity or security is offered for sale.

  26. Assignment of Lease: A legal document transferring all or a portion of the operating rights of a lease.

  27. Balancing: The process by which persons having an interest in production adjust their take therefrom to ensure each interest holder receives his or her proportionate part of production.

  28. Barrel (BBL): A standard measure of volume for crude oil and liquid petroleum products. A barrel is 42 U.S. gallons.

  29. Basic Sediment and Water (BS & W): A combination of impurities and water that is often produced with crude oil. BS & W is heavier than oil and will settle to the bottom of a tank of produced oil.

  30. Benzene Ring: A six-member ring of carbon atoms, joined together by alternate single and double bonds. A benzene ring is present in all aromatics.

  31. Bid: An offer to buy securities or a specific quantity of a commodity.

  32. Bit: A drilling tool that cuts a hole.

  33. Black Oil: A general term used to describe liquid crude oil or heavy fuel oils. (Also referred to as "Dirty cargoes.") It is necessary to clean a tank car, storage tank, etc., that has contained black oils before it can be used for clean fuels.

  34. Blending: (1) Mixing refinery products to suit market conditions. (2) Mixing on-specification fuel with off-specification fuel to bring the latter within use limits (reclamation).

  35. Blow Out: A sudden, violent expulsions of oil and gas from a drilling well, followed by an uncontrolled flow from the well.

  36. BOE: Barrel of Oil Equivalent.

  37. Boiling Points: Initial boiling point is the temperature at which a liquid begins to be converted into a vapor. End boiling point is the temperature at which a liquid becomes completely vaporized. These two points are called cut points or fractions.

  38. Bonus: The consideration received by the lessor or sublessor upon execution of an oil or gas lease.

  39. Bonus Exclusion Rule: A rule that is designed to prevent a percentage depletion deduction, by both a lessor and lessee, on the same production. The rule provides that the taxpayer (lessee) who paid the bonus must exclude an allocable part of the bonus when computing "gross income" and "taxable income " from the property for purposes of determining the amount of the percentage depletion allowance. See Treas. Reg. section 1.613–2(c)(5)(ii), Rev. Rul. 79–73, 1979–1 C.B. 218; and Rev. Rul. 81–266, 1981–2 C.B. 139.

  40. Bottom-Hole: The lowest or deepest part of a well.

  41. Bottom-Hole Contributions: Money or property given to an operator for use in drilling a well on property in which the payor has no property interest. The contribution is payable when the well reaches a predetermined depth, regardless of whether the well is productive or nonproductive. Usually, the payor receives geological data from the well.

  42. Bottoms: In a distilling operation, that portion of the charge remaining in the still at the end of the run; i.e. that portion that does not vaporize called the residuals.

  43. British Thermal Unit (BTU): A measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.

  44. Bulk Petroleum Products: Large volume of products normally transported by pipeline, rail tank, tank truck, barge or tanker.

  45. Butane: An inflammatory gaseous hydrocarbon belonging to the methane series. It is gaseous at ordinary atmospheric conditions, but it is readily convertible to a liquid state.

  46. Carbon Dioxide: An inert, noncombustible, odorless gas at normal temperature and pressure conditions. This gas has become a valuable resource employed in tertiary oil recovery methods.

  47. Carried Interest: An arrangement where one co-owner of an operating interest incurs an obligation to pay all of the costs to develop and operate a mineral property, in exchange for the right to recoup this investment out of the proceeds of the first production from the property. After the investment is repaid, any subsequent production is split between the co-owners. The co-owners are not obligated to pay for the development and operation hold a carried interest in the mineral property until the carrying party's investment is repaid.

  48. Carved-Out Drill Site: A site for drilling a single well. It is "carved out" of a large tract and is transferred in total, or in part, to an operator or operators who will drill a well on it. It is generally the smallest sized tract on which the state regulatory body will allow a well to be drilled. For example, the carved out drill site may be 40 acres out of a 160 acre tract owned.

  49. Carved-Out Oil or Gas Payment: A payment in oil or gas assigned by the owner of an interest in oil and gas. The payment is to be paid out of a fractional part of the owner's interest and will run for a period less than the life of the interest from which it was carved. Except for oil or gas production payments pledged for development, production payments are treated as loans.

  50. Cash Price: Price in the cash market for actual or spot commodities with delivery through customary market channels.

  51. Casing: Steel pipe placed in an oil or gas well. Its main function is to prevent the well walls from caving in and to protect the well bore and in-hole equipment. It also prevents oil from migrating into other porous zones.

  52. Casing Point: The point in time in the drilling of a well when drilling is completed and the operator must decide to set casing and attempt to complete the well or plug it as a dry hole.

  53. Casinghead Gas: Gas produced from an oil well. The casinghead gas is usually taken off at a gas/oil separator.

  54. Catalyst: A substance that affects, provokes, or accelerates chemical reactions without being altered itself.

  55. Catalytic Cracking: A method of cracking in which a catalyst is employed to bring about the desired chemical reaction.

  56. Cementing: The process by which a slurry of cement and water is placed in the well bore between the casing and the walls of the hole or another string of casing. The cement is forced behind the casing from the bottom up. It holds the casing in place and seals the producing zone off from other upper (possible "thief') zones.

  57. Checkerboard Acreage: Mineral interest situated in a checkerboard pattern. Generally, this is done to spread the risk, or to make sure the producer will have some ownership if production is found.

  58. Christmas Tree: An assembly of valves mounted on the casinghead through which oil and gas is produced. The Christmas tree also contains valves for testing the well and for shutting it down if necessary. A subsea production system is similar to a conventional land tree except it is assembled complete for remote installation on the sea floor with or without diver assistance. The marine tree is installed from the drilling platform and anchored to foundation legs implanted in the ocean floor. The tree is then latched mechanically or hydraulically to the casinghead by remote control.

  59. C.I.F.: Cost, insurance, and freight (included in the price quoted). Any price stated C.I.F. is not gross depletable income because it includes insurance and freight.

  60. Coke: The carbon residue left in the coker after a charge of reduced crude has been run to dryness.

  61. Common Carrier: Any cargo transportation system that may be accessed by any appropriate shipper and all shippers are charged the same rate schedule. Many pipelines are common carriers.

  62. Complete Payout: Complete payout occurs when the owner of the operating interest completely recovers the cost of drilling, equipping, and operating a well from proceeds of production of that well. The term is commonly used in reference to carried interest transactions

  63. Completion Cost: Costs incurred, after the completion of the drilling of a well, in preparing the well for production; i.e., fracturing, wellhead cost, acidizing, cleaning, swabbing, and cementing the oil string.

  64. Condensate: A light hydrocarbon liquid that is in a gaseous state in the reservoir, but becomes liquid when temperature and pressure are reduced.

  65. Contiguous Property: Tracts that have a common boundary. Tracts that touch only at a common corner are not contiguous.

  66. Continuing Interest: An economic interest in an oil or gas property that entitles the holder to receive all or a portion of the oil and/or gas produced, or the proceeds from the sale of such oil and/or gas for the entire life of the property. A continuing interest is contrasted to a production payment, which must, by definition, have an economic life of shorter duration than the economic life of one or more of the properties it burdens.

  67. Contract Price: See Term Price.

  68. COPAS: Council of Petroleum Accountants Society of North America.

  69. Core: A solid column of rock, usually from two to four inches in diameter, taken as a sample of an underground formation.

  70. Cracking: The refinery process of breaking down the larger, heavier, and more complex hydrocarbon molecules into simpler and lighter molecules.

  71. Crude Oil: A mixture of hydrocarbons that exist in a liquid phase in natural underground reservoirs and which remains liquid at atmospheric pressure after passing through surface separating facilities. In the United States, crude oils are classified as paraffin base, naphthene base, asphalt base, or mixed base. The properties of the residuum left from nondestructive distillation determine the appropriate classification.

  72. Cushion Gas: The gas required in a reservoir to maintain reservoir pressure.

  73. Cut: See Fraction.

  74. Damage Payments: Payments made to the landowner by the oil or gas operator for damages to the surface, to growing crops, to streams, or other assets of the landowner.

  75. Day Rate: An agreed rate per day to drill a well. This rate does not include additional cost for such items as drilling mud, site preparation, fuel, etc.

  76. Decline Rate: The rate at which the flow of oil or gas from a field falls as production proceeds.

  77. Deferred Bonus: A lease bonus payable in installments over a period of years. The deferred bonus is distinguishable from delay rentals because the deferred bonus payments are due even if the lease is terminated, while delay rentals are discontinued with the termination of the lease or when development activities begin.

  78. Delay Rental: Money payable to the lessor by the lessee for the privilege of deferring drilling operations or commencement of production during the primary term of the lease.

  79. Delineation Well: A well drilled to determine the boundaries of the field.

  80. Depletion: Treas. Regs.1.611 through 1.613A provide taxpayers with an annual deduction in respect of a mineral property. Taxpayers are allowed the greater of cost depletion or percentage depletion with respect to each mineral property. The cost depletion allowance is a ratable recovery of basis as mineral is produced while percentage depletion is an allowance based on a percentage (15% for oil and gas properties) of the taxpayer's income from the sale of minerals.

  81. Development Well: A well drilled for production in an area where proven reserves are located.

  82. Derrick: A tower used in the drilling of oil and gas wells as support for the equipment lowered into the well.

  83. Discovery Well: The first oil or gas well drilled in a field revealing oil or gas deposits.

  84. Distillation: This generally refers to vaporization processes in which the vapor evolved is recovered by condensation. Thus, a separation is effected between volatile fractions that vaporize at a specific temperature and those that do not.

  85. Disposal Well: A well used for disposal of saltwater.

  86. Division Order: A contract between all of the owners of an oil and gas property and the company purchasing production from the property. The contract sets forth the interest of each owner and serves as the basis on which the purchasing company pays each co-owner their respective share of the proceeds of the oil and gas purchased.

  87. DOE: U.S. Department of Energy.

  88. Drilling Mud: A special mixture of clay, water, and chemical additive circulated through the well bore during drilling. Its functions are to cool the drill bit, lubricate the drill pipe, protect against blowouts by holding back subsurface pressure, carry rock cuttings to the surface, and deposit mud cake on the wall of the hole to prevent the bore hole from collapsing.

  89. Drill Site: The location at which a well is to be drilled. The "site" contains sufficient leasehold working interest acres to permit the drilling of one well.

  90. Dry Gas: Natural gas composed of vapors with only small amounts of dissolved liquid. Dry gas generally is composed of almost 100% methane (CH4).

  91. Dry-Hole: A well drilled for the production of oil and/or gas that has not produced and is not expected to produce oil or gas in commercial quantities.

  92. Dry-Hole Contributions: Money or property paid by property owners to another operator drilling a well on property in which the payors have no property interest. Such contributions are payable only in the event the well reaches an agreed depth and is found to be dry. Usually the payor receives geological data for this payment.

  93. Dual Capacity Taxpayer: One who is subject to a foreign tax levy, but who also receives a specific economic benefit (directly or indirectly) from that foreign country. In the oil and gas context, the most frequent concern is whether payments made by companies to the sovereign are income taxes or royalties.

  94. Economic Interest: In order to be eligible to obtain income tax benefits, such as depletion, a taxpayer must possess a legal or equitable ownership interest in the minerals in place and receive income from the extraction and sale of such minerals. The definition of "economic interest" found in Treas. Reg. Section 1.611–1(b) is as follows:

    "An economic interest is possessed in every case in which the taxpayer has acquired by investment any interest in mineral in place or standing timber and secures, by any form of legal relationship, income derived from the extraction of the mineral or severance of the timber, to which he must look for a return of his capital."


    Investment in the minerals in place is not an indispensable element that would preclude a taxpayer from possessing an economic interest in the minerals in place. See Palmer v. Bender , 287 U.S. 551 (1933) and Commissioner v. Southwest Exploration Co., 350 U.S. 308 (1956).

  95. Enhanced Oil Recovery: Sophisticated recovery methods for crude oil that go beyond the more conventional secondary recovery techniques of pressure maintenance and waterflooding. Enhanced recovery drives now being used include micellar surfactant, steam, polymer, miscible hydrocarbon, CO2, and steam soak. EOR methods are not restricted to secondary or even tertiary projects. Some fields require the application of one of the above methods even for initial recovery of crude oil.

  96. Excess IDC: Intangible drilling cost (IDC) paid or incurred in connection with producing wells, less the amount that would have been allowable for the taxable year had the costs been capitalized and recovered by cost depletion or straight-line 120-month amortization. See IRC section 57(a)(2).

  97. Exchange Oil: Name given to oils exchanged between companies. Company A has excess oil on the West Coast but needs oil on the East Coast. Company B has excess oil on the East Coast but needs oil on the West Coast. Rather than incur large transportation costs, Company A exchanges oil with Company B.

  98. Expendable Wells: Another name for exploratory and delineation wells drilled in relatively deep waters and which the operators have no intention of completing for production.

  99. Expired Lease: A lease that is no longer in force due to either an expiration of a time limit or nonpayment of delay rentals.

  100. Exploration Rights: Permission granted by landowners allowing others to enter upon their property for the purposes of conducting geological or geophysical surveys.

  101. Exploratory Well: A well drilled in a nonproductive area in search of oil or gas deposits. Sometimes it is called a wildcat well.

  102. Farm-in: An arrangement whereby one working interest owner acquires an interest in a lease owned by another. Consideration for the transfer is usually an agreement by the transferee to pay all or part of the drilling and development costs, and the transferror frequently retains some interest.

  103. Farm-out: The same thing as a farm-in, but seen from the opposite perspective. The arrangement is a farm-in to the one who acquires the interest and a farm-out to the one who transfers it.

  104. Federal Energy Regulatory Commission (FERC): The U.S. Agency that regulates interstate natural gas and oil pipelines.

  105. Feedstock: Crude oil or other hydrocarbons that are the basic input to a refinery, petrochemical plant, or intermediate processing units.

  106. Fee Interest: The ownership of both surface and mineral rights.

  107. Field Price: Posted price of oil taken from a specific field.

  108. Flashing: To vaporize from heated charge stock, to distill. Vacuum flashing of straight-run residue allows further distillation without cracking.

  109. Flow Line: Surface pipe through which oil or gas is pumped or flowed from the well to either processing equipment or storage facilities.

  110. Footage Drilling Contract: A well drilling contract that provides for payment at a specified price per foot for drilling to a certain depth.

  111. Foreign Oil and Gas Extraction Income (FOGEI): Taxable income derived from all sources outside the United States and possessions from the extraction of minerals from oil or gas wells; or, taxable income from the sale or exchange of assets used by the taxpayer in the business of extracting minerals from oil or gas wells.

  112. Foreign Oil Related Income (FORI): Taxable income derived from sources outside the U.S. and it's possesions from: the processing of oil and gas into their primary products; the transportation, distribution and sale of oil and gas and their primary products; the disposition of assets used in these activities, excepting the sale of the stock of any corporation; or, the performance of any directly related services.

  113. Forward Contract: A transaction common to many industries, including commodity merchandising, in which the buyer and seller agree upon delivery of a specified quality and quantity of goods at a specified future date for a price agreed upon in advance or to be determined at the time of delivery.

  114. Fracturing: The process of forcing a fluid, usually oil, through the perforations in the casings into the formation. The fluid enters the formation under high pressure and breaks it or fractures it. This allows the oil and gas, which are in the formation, to more easily enter the well.

  115. Fraction: A portion of distillate (having a particular boiling range) separated from other portions in the fraction distillation of petroleum products.

  116. Free-Well Agreement: A form of sharing arrangement in which one party drills one or more wells completely free of cost to a second party in return for an interest in the property.

  117. Futures Contract: A firm commitment to deliver or receive, at a specified price and grade, a specified quantity of a commodity during a designated month that is traded through an exchange.

  118. Futures Price: The price of a given commodity futures unit determined by public outcry on a futures exchange

  119. Gas Payment: A production payment payable out of gas.

  120. Geological and geophysical (G&G): These costs are expended for the acquisition of information relative to subsurface formations. This information may be the result of interpretative work of geologists; seismic surveys; gravity meter surveys; magnetic surveys; core samples or any other method used in the industry. The costs are capital in nature.

  121. Gravity: Short for "Specific gravity" . It is a measure of the density of oil and is usually expressed in degrees API. Generally, the higher the API gravity, the higher the value. Light oils have a high API gravity. Heavy oils have a low API gravity. The API Gravity is calculated from the specific gravity at 60°F using the following formula:

        141.5    
    API Gravity = Specific Gravity at 60° − 131.5
        F    

  122. Gross Income from the Property: Since crude oil and natural gas are normally sold directly at the wellhead, the gross sales from which the percentage depletion allowance is computed are usually the actual sales prices. When oil or gas is transported from the premises or converted into a refined or manufactured product prior to sale, the representative market or field price is used for purposes of computing percentage depletion. See Treas. Reg. section 1.613–3.

  123. Heavy Crude Oil: Crude oil of 20 degrees API gravity or less (adjusted to 60 degrees Fahrenheit). There are perhaps billions of barrels of heavy oil still in place in the U.S. that require special production techniques, notably steam injection or steam soak, to extract them from the underground formations.

  124. Hedge: A transaction entered into primarily to manage price risk by taking a position in a financial product equal and opposite to an existing or anticipated cash position or by shorting a security similar and equal to one in which a long position has been established.

  125. Hydrocarbon: Any of the compounds made up exclusively of hydrogen and carbon in various ratios.

  126. Hydrocracking: Catalytic cracking in the presence of hydrogen. The combination of the hydrogen, the catalyst, and the operating conditions (temperature and pressure) permit cracking low quality gas oils that would otherwise be made into distillate fuel. The heavy hydrocrackate product contains aromatics.

  127. Hydroforming: A special catalytic hydrogen reforming process employed for upgrading straight run gasolines.

  128. Independent Producers and Royalty Owners Exemption: An exemption from the denial of percentage depletion provided in IRC section 613A(a). This exemption is provided in IRC section 613A(c) and is based on average daily production of oil and/or gas. Independent producers are defined in IRC section 613A(d) as producers who do not have more than $5,000,000 in retail sales of oil or gas in a year and who do not refine more than 50,000 barrels of crude oil on any given day during the year.

  129. Injection or Input Well: A well used to inject gas, water, LPG'S, or other foreign substances under pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.

  130. Intangible Drilling and Development Costs: Those expenditures which do not have a salvage value and which are incurred in the drilling and deepening of an oil and gas well.

  131. Integrated Oil Company: A company engaged in all phases of the oil business, i.e., production, transportation, refining, and marketing. It frequently also includes petrochemicals/chemicals.

  132. Investment in Lease and Well Equipment: Capital investment in items having potential salvage value. Such items include the cost of casing, tubing, wellhead assemblies, pumping units, lease tanks, treaters and separators, etc.

  133. IPAA: Independent Petroleum Association of America.

  134. Isomerization: Process for altering the fundamental arrangement of the atoms in a molecule without adding or removing anything from the original materials. In petroleum refining, straight-chain hydrocarbons are converted to branched-chain hydrocarbons of substantially higher octane rating, in the presence of a catalyst, usually at moderate temperatures and pressures.

  135. Jack-up Rig: A mobile drilling platform with extendible legs for support on the ocean floor.

  136. Jobber: A buyer of oil products from refiners for resale to retail outlets.

  137. Joint Operating Agreement: (1) An agreement between two owners or among several concurrent owners for the operation of a leasehold for oil, gas, or other minerals. The agreement calls for the development of the lease or the premises by one of the parties to the agreement, who is designated as operator or unit operator for the joint account. All parties share in the expenses of the operations and in the proceeds resulting from the development. (2) An agreement among adjoining landowners or leaseholders to develop a common pool, again sharing expenses and profits.

  138. Joule: A unit of energy. One joule is equivalent to 9.48 X 10–4 BTUs. The joule is the measure of natural gas used in Canada.

  139. Landman: A person engaged in securing oil and gas leases from landowners.

  140. Lease Agreement: (1) The legal instrument by which a leasehold is created in minerals. A contract that, for a stipulated sum, conveys to an operator the right to drill for oil and gas. The mineral lease is not to be confused with the usual lease of land or a building.

  141. Lease and Well Equipment: Capital investment in items having a potential salvage value. Such items include the cost of casing, surface pipe, tubing, wellhead assemblies, pumping units, lease tanks, treaters, and separators.

  142. Lease Bonus: Consideration paid by the lessee to the lessor for executing the lease.

  143. Leasehold Costs: Costs of acquiring and holding a lease.

  144. Lifting costs: Costs of operating wells for the production of oil and gas (producing costs).

  145. Light Ends: In any given batch of oil, that portion of lowest boiling point. In gasoline, it is the portion distilling off up to 158°F. In making lubricating oils, the light ends must be removed in order to produce finished oils of high flash point.

  146. Limited Partnership: A form of organization, frequently employed in financing oil and gas ventures, by which an investor of funds becomes a limited partner with limited liability and limited management rights.

  147. Line Pack Gas: The volume of gas maintained in a pipeline to maintain pressure.

  148. LNG: Liquified Natural Gas, composed almost entirely of methane. The temperature at which methane becomes liquid at normal pressure is -260°F. In liquid form, natural gas retains only 1/600th of its original volume.

  149. Marginal Production: Domestic crude oil or natural gas that is produced from a stripper well property for the calendar year in which the taxable year begins, or oil produced from a property whose production is substantially all heavy oil during such calendar year. See IRC section 613A(c)(6)(E).

  150. Marginal Wells: A well of such low producing capacity that the profitability of future production is marginal.

  151. Mark to Market: This is a procedure in which the broker debits or credits the available balances of customers' accounts daily for changes in the value of open contracts.

  152. MCF: Thousand cubic feet.

  153. Mercaptans: Organic compounds having the general formula R-SH, meaning that the thiol group (SH) is attached to a radical, such as CH3 or C2H5. The simpler mercaptans have a strong, repulsive, garlic like odor which becomes less pronounced with increasing molecular weight and higher boiling points.

  154. Methane: A simple gaseous hydrocarbon associated with petroleum.

  155. Mineral Deed: A lease instrument that conveys an interest in minerals on or under a tract of land.

  156. Mineral Interests (Mineral Rights): The ownership of the minerals and the right to remove them from the property.

  157. Minimum Royalty: An obligation of a lessee to periodically pay the lessor a fixed sum of money after production occurs, regardless of the amount of production. Such minimum royalty may or may not be chargeable against the royalty ownership of future production.

  158. MMBTU: Million British Thermal Units.

  159. MMCF: Million cubic feet.

  160. MOGAS: Motor gasoline.

  161. Mud Pit: Tank near the drilling rig used for storage of drilling mud during drilling operations. The drilling mud is prepared for drilling in the pit by mixing the mud and water. Slush pumps withdraw the mud from the pit and circulate it down the drill pipe. At the surface the mud passes back to the mud pit through the "shale shaker" which removes the drill cuttings that were carried to the surface by the mud.

  162. Multiple Completion Well: An oil and/or gas well completed in such a manner that it is capable of producing oil and/or gas separately from two or more reservoirs. Such separate production may be simultaneously through two or more strings of tubing or through a string of tubing and between the tubing and the casing.

  163. Natural Gas: Any hydrocarbon product (other than crude oil) of an oil or gas well if a deduction for depletion is allowable under IRC section 611 with respect to such product. Specifically natural gas refers to any hydrocarbon gas.

  164. Natural Gas Liquids: Natural gas liquids are the heavier hydrocarbon liquids produced along with natural gas, including butane, propane, natural gasoline and ethane.

  165. Natural Gas Sold Under a Fixed Contract: Domestic natural gas sold under a contract in effect on February 1, 1975, under which the price cannot be adjusted to reflect the increase in income tax due to the repeal of percentage depletion. See IRC section 613A(b)(3)(A).

  166. Net Profits Interest: An interest in production created from the working interest and measured by a certain percentage of the net profits from the operations of the property.

  167. Neutral Oils: Term used quite generally to mean a lubricating oil of medium viscosity made from a wax bearing crude.

  168. Nonconventional Source Fuels Credit: A tax credit authorized by IRC section 29 for sales of qualified fuels to unrelated persons.

  169. Nonoperating Interest: An economic interest that does not meet the definition of operating interest as defined in Treas. Reg. section 1.614–2(b). A royalty, overriding royalty, or net profits interest is a nonoperating interest.

  170. Normal: When used to refer to a chemical compound, this means the straight-chain version. Branched-chain molecules have higher octane numbers.

  171. Octane Number, Motor Method (MON): Octane number of automotive gasolines determined by a method of test that indicates the knock characteristics under severe conditions (high temperatures and speed).

  172. Offset Well: Well drilled on one tract of land to prevent drainage of oil or gas to a nearby tract on which a well has been drilled.

  173. Oil Payment: A production payment payable from oil.

  174. Oil or Gas Property: Each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land.

  175. Operating Mineral Interest: A separate mineral interest in respect of which the costs of production of the mineral are required to be taken into account by the taxpayer for purposes of computing the 50 percent of taxable income from the property in determining the deduction for percentage depletion. See Treas. Reg. 1.614–2(b).

  176. Operator: The individual or company responsible for conducting exploration and production activities in a defined area. In a joint venture the operator is usually the holder of the largest interest.

  177. Overriding Royalty: A right to a stated fraction of production, in kind or in value, created from the working interest, having a term coextensive with that of the working interest, but not burdened with development or operation costs.

  178. Oxidation: In general, the process in which oxygen reacts with a compound. The oxidation reaction in petroleum may lead to degrading gum or resin formation which is common in gasolines and jet fuels, particularly those that contain considerable unsaturated compounds.

  179. Paraffinic: Refers to a petroleum product containing large amounts of alkyl compound of the formula CnH2n+2. Alkyl compounds are saturated organic molecules with important lubricating properties found in the heavier members of the series.

  180. Participating Area: That part of a unit area which is considered reasonably proven to be productive.

  181. Participation Agreement: An agreement between two or more parties to share in the cost and production of a well.

  182. Passive Activity: Income/losses generated from an activity (trade or business) in which the taxpayer does not materially participate or from a rental activity, usually regardless of participation levels.

  183. Payout: Recovery from the net proceeds of production of the entire cost of drilling, completing, and equipping a well.

  184. Perforating: The piercing of the casing wall and cement to provide holes through which the hydrocarbons may enter the well bore.

  185. Percentage Depletion: The method of computing the depletion deduction based upon an arbitrary percentage of gross income from production (gross income from the property). The percentage depletion allowance is limited to 100 percent of the taxable income from oil and gas operations computed with respect to each separate operating mineral interest. Percentage depletion allows a taxpayer to deduct costs in excess of basis. See Treas. Reg. 1.613–1(a).

  186. Petrochemicals: Chemicals derived from petroleum feedstocks for the manufacture of a variety of plastics, synthetic rubber, etc.

  187. Petroleum: A complex mixture of hydrocarbons with small quantities of other materials, such as sulphur (usually combined), nitrogen compounds, water, and silica.

  188. Petroleum Coke: A solid residue which is the final product of the condensation process in cracking.

  189. Pool of Capital: Under this doctrine, a taxpayer contributing property, cash or drilling services to the drilling of an oil or gas well in return for an economic interest in that well makes a capital contribution to the "pool of capital" available to the venture. The taxpayer is considered to have received a capital interest in the well that was not taxable upon its receipt. See Rev. Rul. 77–176, 1977–1 C.B. 77

  190. Pooling: The bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules, as distinguished from unitization which is the joint operation of a reservoir. Pooling is important to prevent the drilling of unnecessary and uneconomic wells. See Treas. Reg. 1.614–8(b)(6).

  191. Possible Reserves: The reserves that are estimated with less certainty than probable reserves and are less likely to be recovered. See Treas. Reg. 1.611–2(c)(1)(ii).

  192. Pour Point: The lowest temperature at which an oil will pour or flow when chilled without disturbance under specified conditions. By ASTM instruction, it is taken as the temperature 5 degrees F above the solid point.

  193. Primary Production: Oil production which is recovered through the use of the natural energy source in the reservoir. Also called primary recovery.

  194. Primary Term: The period of time a lease may be kept in force even though no drilling operations have commenced. Payments of delay rentals may or may not be required. The time period varies.

  195. Probable Reserves: The reserves that are less likely to be recovered than proven reserves but are estimable and more likely to be recovered than not recovered. See Treas. Reg. 1.611–2(c)(1)(ii).

  196. Producer: One who owns an economic interest in a well that produces oil or gas.

  197. Production Payment: A share of the minerals produced from a lease, free of the cost of production, that, inter alia, terminates when a specified sum of money has been realized. Production payments may be reserved by a lessor or carved out by the owner of the working interest. See Treas. Reg. 1.636–3(a)(1)&(2).

  198. Production Taxes: Taxes levied by state governments on mineral production based on the value and/or quantity of production. These are also referred to as severance taxes.

  199. Project Area: In the search for mineral producing properties, it is customary for a taxpayer to conduct geological and geophysical studies and surveys within a large geographical area (the project area). The purpose of these initial reconnaissance type surveys is to identify specific geological features with sufficient mineral producing potential to merit further exploration. The costs incurred with respect to these initial surveys are capital in nature and must be allocated equally among the "areas of interest" that are selected for more intensive surveys. See Rev. Rul. 77–188,1977–1 C.B. 76.

  200. Propane: A gaseous hydrocarbon associated with petroleum.

  201. Property: Each separate interest owned by a taxpayer in each mineral deposit in each separate tract or parcel of land. See Treas. Reg. 1.614–8.

  202. Proved Reserves: The reserves of ores and minerals in sight, blocked out, developed or assured to exist in place.

  203. Recompletion: Redrilling the same well bore to reach a new reservoir after production from the original reservoir has been abandoned.

  204. Reconnaissance Survey: A survey of a project area utilizing various geological and geophysical exploration techniques to identity specific geological features with sufficient mineral producing potential to merit further exploration. See Rev. Rul. 77–1 88, 1977–1 C.B. 76; Rev. Rul. 83–105, 1983–2 C.B. 51.

  205. Recoverable Reserves: The total recoverable units (e.g., barrels or thousands of cubic feet) of ores or minerals reasonably known to exist in place as of the estimation date. The estimation of recoverable reserves must be made in accordance with the method current in the industry in light of the most accurate and reliable information obtainable. The estimation must be made in the first taxable year within which depletion is taken with respect to a mineral interest and the recoverable reserves can only be reestimated if it is determined by operations or development work that the number of recoverable reserves are materially greater or less than the number remaining from the prior estimate. See Rev. Rul. 67–157, 1967–1 C.B. 154; G.C.M. 33140 (Nov. 24, 1965).

  206. Reduced Crude: The bottoms from a distillation of crude oil.

  207. Reformate: Liquid product from the reforming process (increased percentages of aromatics and iso-paraffins) and feedstock for gasoline blending and/or further processing to petrochemicals.

  208. Reforming: A catalytic process for converting low octane number naphthas or gasolines into high octane number products.

  209. Regeneration: In catalytic cracking, removal of carbon from the catalyst in order to make it suitable for reuse.

  210. Reservoir: A porous, permeable sedimentary rock containing commercial quantities of oil or gas.

  211. Residual (Residue or Residuum): The dark colored, highly viscous oil remaining from oil after the more volatile portion of the charge has been distilled.

  212. Residue Gas: Natural gas, mostly methane, which remains after processing in a separator or plant to remove liquid hydrocarbons contained in the gas when produced.

  213. Retained Interest: A special nonoperating interest retained by the lessor when the lessor transfers the responsibilities for developing the property to another party.

  214. Royalty: A share of the gross production of the minerals (or a share of the proceeds from sale) on a property by the landowner without bearing any of the cost of producing the minerals. The usual landowner's royalty is one-eighth of gross production. See Treas. Regs. 1.614–2(b) and 1.614–5(g).

  215. Run Statement: A statement supplied by the purchaser of oil or gas to an interest owner setting forth the gross volume of product taken, sales value, taxes paid, and net payment to the owner. The run statement usually accompanies the payment for the runs.

  216. Runs-to-Stills: The amount of crude oil withdrawn from inventory and placed into production by a refiner.

  217. Run Ticket: Evidence of receipt or delivery of oil issued by a pipeline or other carrier or purchaser.

  218. SAE Viscosity: A system for classifying motor oils according to their viscosities established by the Society of Automotive Engineers.

  219. Salt Water Disposal Wells: Wells used for disposal of saltwater that is produced along with oil or gas.

  220. Secondary Production: Oil recovered by a secondary recovery method used to recover oil from a field by a means other than the normal pumping or flowing methods. This will normally involve the flooding of the formations through injection wells with water to drive the recoverable oil to producing wells.

  221. Seismic Survey: Geophysical information on subsurface rock formations gathered by means of a seismograph.

  222. Separator: A gas-oil separator is a cylindrical tank, usually located at or near the tank battery, which is used to separate oil and/or gas well effluent into liquids and gas at or near atmospheric pressure.

  223. Severance Taxes: See Production taxes.

  224. Sharing Arrangement: A transaction where a person contributes to the acquisition, exploration, or development of an oil or gas property and receives as consideration an interest in the property to which the contribution is made.

  225. Shooting Rights: The right to make a geological survey on land.

  226. Short: A trader obtains a short position by selling a security he does not own and making delivery with borrowed securities.

  227. Shut-in Wells: A producing well that has been closed down temporarily, or one that was never connected to a pipeline because of it's very remote location.

  228. Side Tracking: An operation involving the use of an existing well to drill a second hole.

  229. Sour Oil or Gas: Oil or gas containing more than a certain proportion of hydrogen sulfide or other sulfur compounds, usually 0.5 percent or more.

  230. Speculator: An individual, or entity, that is not a hedger. One who trades for profits by anticipation of price movements.

  231. Spot price: The price at which a physical commodity is selling at a given time and place, often involving prompt delivery. Same as cash price. The spot price differs from a contract or term price in that the latter involves multiple sales overtime, whereas the former usually involves a single cargo or transaction.

  232. Spread (or Straddle): The purchase of one futures delivery and the sale of another futures delivery month of the same or similar commodity, or the purchase of a commodity in one market against the sale of that commodity or a like commodity in another market to take advantage of differences or anticipated differences in price relationships.

  233. Spud: To start the actual drilling of a well.

  234. Stripper Oil: Oil recovered from a stripper well. Oil produced from a well that is not a gas well which produces less than 15 barrels a day. See IRC section 613A(c)(6)(E).

  235. Stripper Well Property: A property where the average daily production of domestic crude oil and gas produced from the wells on the property during a calendar year divided by the number of such wells is 15 barrels or less. See IRC section 613A(c)(6)(E).

  236. Sweet Oil or Gas: Crude oil or natural gas which contains little or no sulphur or hydrogen sulfide.

  237. Take or Pay Contract: A contract by which a pipeline company, within a specific period of time, must pay for an agreed number of units whether or not the units have been taken. The pipeline company usually has the right to take these units, within a specified time period, without further payment.

  238. Tank Battery: Two or more tanks connected together on a property to store oil production prior to sale and/or removal.

  239. Tank Farm: A number of oil storage tanks located together where oil gathered by a pipeline company is stored prior to transportation to the refinery.

  240. Tar Sands: Native asphalt, solid and semisolid bitumen, including oil-impregnated rock or sands from which oil is recoverable only by special treatment. Processes have been developed for extracting the oil, referred to as synthetic oil. See TAM 8940004 (October 6,1989) and FEA Ruling 1976–4, 41 FED. Reg. 25, 886 (1976).

  241. Term Price: A contract price, usually involving multiple deliveries over time. See Spot Price.

  242. Tertiary Production: A method used to recover oil after a secondary method has been applied, typically by using heat or chemicals to increase the flow of hydrocarbons in the formation.

  243. Tight Gas: Natural gas produced from a tight formation, one that will not give up its gas readily or in large volumes. The production of tight gas is more costly and therefore less attractive to producers owing to the need for fracturing, acidizing, and other expensive treatments to free the gas from the relatively impermeable formations. In view of these constraints, such gas was given an incentive price of 150 percent of the price of gas from new, conventional onshore gas wells by the Natural Gas Policy Act of 1978 (NGPA). The Revenue Reconciliation Act of 1990 provides a credit for gas wells drilled after November 11, 1990, and before January 1, 1993, without reference to the NGPA.

  244. Top Lease: The granting of a new oil or gas lease prior to the termination of an existing lease; the new lease becoming effective upon expiration of the old lease.

  245. Topped Crude: Crude oil from which some of the lighter constituents have been removed by distillation.

  246. Turnaround: The planned periodic inspection and overhaul of the units of a refinery or processing plant requiring the shutting down of a refinery (or individual units) for inspection, cleaning, repair, or upgrading.

  247. Turnkey Well: A completed well, drilled and equipped by a contractor for a fixed price.

  248. Ullage: The distance from a given point at the top of a container down to the surface of the liquid.

  249. Unitization: A term denoting the joint operation of separately owned producing leases in a pool or reservoir. Unitization makes it economically feasible to undertake cycling, pressure maintenance, or secondary and tertiary recovery programs. See Treas. Reg. 1.614–8(b)(6).

  250. Unit of Production Method: A method for computing depreciation or amortization based on a ratably recovery of basis over the expected number of units to be produced by an asset. The method is similar to the computation of cost depletion.

  251. Unrealized Profit or Loss: The profit or loss on open positions that has not become actual. It is realized when the security or commodity futures contract in which there is a gain or loss is actually sold.

  252. Viscosity: That property of a liquid which causes it to offer resistance to flow. The higher the viscosity of an oil the less readily it will flow; the lower the viscosity of the oil the more readily it will flow. Motor oil with a viscosity of SAE 10 will flow more readily than a SAE 20.

  253. Volatility: A measure of the propensity of a substance to change from the liquid or solid state to the gaseous state. A volatile liquid is one which readily vaporizes at comparatively low temperatures.

  254. Volumetric Production Payment: A production payment that is to be satisfied by delivery of a certain volume of hydrocarbons as distinguished from one to be satisfied by delivery of hydrocarbons of a specific value.

  255. Wash Sale: A fictitious transaction to make it appear that there was a trade. This is prohibited by the Commodity Exchange Act. See wash trading.

  256. Wash Trading: Entering into, or purporting to enter into, transactions that give the appearance of purchases and sales but usually do not result in a change in the traders' market position.

  257. Waterflooding: A method of secondary recovery, in which water is injected into an oil reservoir for the purpose of pushing the oil out of the reservoir rock and into the bore of a producing well.

  258. Wellhead: Equipment used to maintain surface control of a well. See Christmas Tree.

  259. Wildcat Well: A well drilled in an unproved area, far from a producing well; an exploratory well in the truest sense.

  260. Working Interest: The usual working or operating interest consists of seven-eighths of the production subject to all of the costs of drilling, completing and operating the lease. See L. W. Brooks Jr. v. Commissioner , 424 F.2d 115 (5th Cir. 1970) and Treas. Reg. 1.614–2(b).

  261. Workover Costs: Expenses of "reworking" a well. These are costs of cleaning, reaciding, reperforating, recementing, plugging back, and similar costs. They may be recurring type costs but not on an annual or shorter time basis.

  262. Yield: In petroleum refining, the percentage of product or intermediate fractions based on the amount charged to the processing operation.

Exhibit 4.41.1-1  (07-31-2002)
Research Material Available, Oil and Gas Taxation

A. Income Taxation of Oil and Gas Production, Breeding and Burton
B. Oil and Gas Federal Income Tax Manual, 11th Ed., Arthur Andersen & Company
C. Millers Oil and Gas Federal Income Taxation, James L. Houghton, CPA; Arthur Young and Company
D. Income Taxation of Natural Resources, Partners of KPMG Peat Marwick, LLP, Research Institute of America, Inc.
E. Revenue Rulings and Revenue Procedures under Code IRC sections 263(c), 611, 612, 613, 613A, 614, 636, and 1254 (See Bulletin Index-Digest)
F. Oil and Gas Taxes, Prentice Hall, Inc.
G. The RPI Primer of Oil Exploration, Drilling and Production, Resource Programs, Inc.
H. A Primer of Oilwell Drilling, Petroleum Extension Service, The University of Texas at Austin
I. Bulletins published by the Council of Petroleum Accountants Societies of North America (COPAS)
J. Primer of Oil and Gas Production, American Petroleum Institute
K. Petroleum Industry Program Handbook
L. Oil and Gas Tax Quarterly, Matthew Bender & Co., Inc.
M. Oil and Gas Journal (published weekly), PennWell Publishing Co.
N. Manual of Oil and Gas Terms, Fifth Edition, Williams and Meyers

Exhibit 4.41.1-2  (06-30-2005)
Division of the Production From Oil and Gas Property

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Exhibit 4.41.1-3  (07-31-2002)
Useful Examination Techniques — Lease Acquisition Costs

1. Scan the nonproducing lease account in the asset section of the ledger to determine the number of oil and gas leases acquired during the year and their names.
2. Test lease operating costs, legal and accounting, office supplies, miscellaneous, and similar accounts for acquisition costs that may have been deducted as current expenses.
3. Inquire about the taxpayer's method of allocating overhead costs to the leases acquired. Are land department costs, salaries of geological departments, and administrative costs included in the cost of properties acquired? Request copies of authorization for expenditures (AFE) for lease purchases to see if direct costs are set out as part of the cost of the property.
4. Test the delay rental account for bonuses that may have been charged to expense in error.
5. Has the taxpayer allocated leasehold cost correctly on producing leases purchased? Do you need engineering assistance?
6. Scan and test the chargeoffs of geological and geophysical expenses to determine if they should be capitalized as cost of drilling projects acquired.
  a. Were seismic costs incurred in areas where leases were acquired?
  b. Have commissions to geologists or consultants been incorrectly deducted as IDC?
  c. Have seismic survey projects really been abandoned without acquiring leases? Scan subsequent year acquisitions. (Some lessors, such as state or Federal government, put selected lands up for lease each year and hold other lands to put up for future years.)
  d. Questionable deductions should be brought to the attention of an IRS petroleum engineer.
  e. See Rev. Rul. 77–188, 1977–1 C.B. 76 and Rev. Rul. 83–105, 1983–2 C.B. 51.

Exhibit 4.41.1-4  (07-31-2002)
Useful Examination Techniques — Intangible Development Costs (IDC)

1. Determine if the taxpayer has made a proper election to deduct IDC as a current expense.
2. Test the larger deductions in the intangible development expense account.
  a. Schedule large amounts
  b. Request invoices
  c. Request AFEs
  d. Compare above documents with amounts claimed
3. Inspect the drilling contracts on a selected basis, especially December deductions.
4. Determine if prepaid IDC is required by the contract, or if it is merely a deposit, and whether or not paid directly to the drilling contractor.
  a. Determine when the well was "staked" and when work was started.
  b. Consider the facts surrounding the prepaid IDC in relationship to Rev. Rul. 71–579, 1971–2 C.B. 225, and 71–252, 1971–1 C.B. 146.
  c. Consider the effect of an adjustment. Does the adjustment have tax significance or would it be a mere "rollover?" (remember timing of IDC deduction could affect the net income limit for percentage depletion under IRC section 613A).
5. Scan the depletion schedules to determine which newly acquired leases are productive.
  a. Have the drilling costs been shown as a deduction on the leases for the 100-percent percentage depletion limitation?
  b. Prepare a list of new productive leases from the depletion schedule.
6. From the list prepared in item 5(b), request the lease files on all new productive leases, or on a selective basis if the number is large.
  a. Review the lease files to determine if the taxpayer's ownership percentage corresponds with the amount of IDC deducted. If not, why? Is the deduction allowable?
  b. Review assignments, correspondence, and related documents to determine if the taxpayer has drilled for his/her interest in the lease and if he/she is " carrying" other owners.
  c. If transactions as described in (a) and (b) are found, has the taxpayer handled them correctly? See Rev. Rul. 70–657, 1970–2 C.B. 70; Rev. Rul. 71–206, 1971.1 C.B. 105; Rev. Rul. 69–322, 1969–1 C.B. 87; Rev. Rul. 77–1 76, 1977–1 C.B. 77, etc.
7. Scan the producing lease account in the asset section of the ledger.
  a. Note the leases that have been removed (credits).
  b. Have the leases removed been reported as sales?
  c. Should IDC be recaptured in accordance with IRC section 1254?
8. Allocate a reasonable amount of administrative overhead costs to IDC for tax preference purposes before computing the minimum tax.
  a. Usually, this can be done by allocating overhead based upon the direct departmental costs.
  b. In many cases, this can be easily accomplished by using the taxpayer's workpapers prepared for the purpose of allocating overhead for depletion purposes.
9. Taxpayers must own the entire working interest during the complete payout period to be allowed to deduct 100 percent of the IDC in a carried interest arrangement.
10. Has surface casing been deducted?
11. Has IDC been shown in operating expenses incorrectly to avoid minimum tax under IRC section 57 or recapture under IRC section 1254?

Exhibit 4.41.1-5  (07-31-2002)
Classification of Expenditures in Acquisition, Development, and Operation of Oil and Gas Leases

A. Leasehold Cost (Capital Expenditure)
  1. Research of lease location by engineer, geologist, etc., for purposes other than locating a well site.
  2. Geological and geophysical expenditure leading to acquisition or retention of an oil and gas property.
  3. Expenses in connection with leasing the property from a landowner.
  4. Legal costs of securing lease and clearing title.
  5. Legal fees incurred to obtain access to the property and to obtain easements, etc.
  6. Lease bonus paid to the landowner or other owner.
  7. Purchase price of an existing lease.
  8. Core-hole wells drilled to obtain geological data.
  9. Seismic work to determine the size of the reservoir or reserves.
  10. Legal fees incurred in drafting contracts.
  11. Travel expenses incurred in acquiring leases.
  12. Salaries of land department personnel in acquiring leases.
  13. Equalization payments paid in furtherance of a unitization when paid in connection with prior IDC.
  14. Bottom-hole contribution when paid to obtain information which enhances the value of the property.
  15. IDC if no election to expense has been made under IRC section 263(c) or if "foreign IDC."
  16. Delay rentals unless the taxpayer can establish that it was not reasonably likely for the lease to be developed.
  17. Remaining basis in equipment which is transferred to another person under any type of reversionary agreement.
     
B. Intangible Drilling Costs (current deductions or capital cost depending on election)
  1. Administrative costs in connection with drilling contracts.
  2. Survey and seismic costs to locate a well site on leased property.
  3. Costs of drilling.
  4. Grading, digging mud pits, and other dirt work to prepare drill site.
  5. Cost of constructing roads or canals to drill site.
  6. Surface damage payments to landowner.
  7. Crop damage payments.
  8. Costs of setting rig on drill site.
  9. Transportation costs of moving rig.
  10. Technical services of geologist, engineer, and others engaged in drilling the well.
  11. Drilling mud, fluids, and other supplies consumed in drilling the well.
  12. Transportation of drill pipe and casing.
  13. Cementing of casing (but not the casing itself).
  14. Rent of special equipment and tanks to be used in drilling a well.
  15. Perforating the well casing.
  16. Logging costs, but not velocity surveys.
  17. Costs of removing the rig from the location.
  18. Dirt work in cleaning up the drill site.
  19. Cost of acidizing, fracturing the formation, and other completion costs.
  20. Swabbing costs to complete the well.
  21. Cost of obtaining an operating agreement for drilling operations.
  22. Cost of plugging the well if it is dry.
  23. Cost of drill stem tests.
     
C. Lease and Well Equipment (Capital Expenditures)
  1. Surface casing.
  2. Equalization payments of a unitization when paid in connection with equipment.
  3. Cost of well casing.
  4. Salt water disposal equipment and well.
  5. Transportation of tubing to supply yard but not from supply yard to well site.
  6. Cost of production tubing.
  7. Cost of well head and "Christmas Tree."
  8. Cost of pumps and motors including transportation.
  9. Cost of tanks, flow lines, treaters, separators, etc., including transportation.
  10. Dirt work for tanks and production equipment.
  11. Roads constructed for operation of the production phase.
  12. Laying pipelines, including dirt work and easements.
  13. Installation costs of tanks and production equipment.
  14. Construction costs of trucks turnaround pad and overflow pits at new tank battery.
     
D. Lease Operating Expense (current deduction)
  1. Cost of switcher or pumper to operate the wells.
  2. Cost of minor repair of pumps, tanks, etc.
  3. Grading existing roads.
  4. Treat-o-lite and other materials and supplies consumed in operating the lease.
  5. Pulling sucker rods, pump, and cleaning the well.
  6. Utilities.
  7. Taxes other than Federal income taxes.
  8. Depreciation of equipment used on the lease.
  9. Rental of lease equipment.
  10. Salaries for painting and cleaning the lease.
  11. Lease signs.
  12. Salaries of other operating personnel—farm boss, superintendent, engineer, etc.
  13. IDC when elected to expense under IRC section 263(c).
  14. Salt water disposal costs (other than those under C.4. above).
  15. Allocable portion of overhead costs.
  16. Qualified tertiary injectant expenses. See Treas. Reg. 1.193–1.

Exhibit 4.41.1-6  (07-31-2002)
Information Required Before Maximum Allowable Depletion Can be Computed*

What is the taxpayer's average daily production of domestic crude oil and how was it computed [IRC section 613A(c)(2)]?

Is the taxpayer required to share the tentative depletable oil quantity with related entities or family members [see IRC sections 613A(c)(3) and (8)]?

If question 2 is "yes" , determine the taxpayer's individual share of tentative oil quantity under IRC sections 613A(c)(3) and (8).

Is the percentage depletion limited to 65 percent of adjusted taxable income?

Are any of the properties marginal oil or gas production properties held by independent producers or royalty owners

Have overhead expenses been allocated to the properties for percentage depletion purposes?

Is the taxpayer a refiner or retailer [IRC section 613A(d)(2) or (4)]?

  1. Note:

    The information above is not needed for a taxpayer with only a few small oil and gas leases because the facts may be obvious. However, for a taxpayer with large production, much time can be saved by obtaining the facts above before making any computations.

Exhibit 4.41.1-7  (07-31-2002)
Steps in the Computation of Depletion for All Taxpayers Other than Retailers or Refiners as Defined in IRC sections 613A(d)(2) & (4)

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NOTES:

Start with a schedule of all properties in which the taxpayer owns an economic interest and has income from production of oil or gas. If the taxpayer is on a tax year different than a calendar year, for computation of percentage depletion under IRC section 613A(c), treat each part of a calendar year within the tax year as if it were a "short period" return. Two separate percentage depletion computation schedules are required for a fiscal-year taxpayer. For each property, the allowable percentage depletion deductions from each schedule are combined to compute the property's allowable percentage depletion deduction for the fiscal year. Each property's allowable percentage depletion deduction is then compared with that property's cost depletion deduction. The larger of the two computed deductions is the allowable deduction. The agent should scan the schedule for leases with similar names. He/she should consider the effect on the computations if properties with similar names were, in fact, one property as defined in IRC section 614. The agent should obtain the lease acquisition and well files for the purpose of determining (a) if these wells were drilled on a single property as defined in IRC sections 614 (a) and (b) if their income and expense should have been reported together on the depletion computation schedule.

The schedule above illustrates what a depletion schedule might look-like per the tax return. "ALL" depletion schedules, should show and compute for each property the following:

The 65% Taxable Limitation. The tentative percentage depletion determined in (i) above may be subject to the 65 percent of the taxpayer's taxable income limitation of IRC section 613A(d)(1). Determine the 65 percent of the taxpayer's taxable income by:

Starting with the taxpayer's taxable income per return.

  1. Add back to income: Any operating loss carryback (IRC section 172); any capital loss carryback (IRC section 1212); and in the case of most trusts, distributions to the beneficiaries (see IRC section 613A(d)(1)(D)).

  2. Add back to income: Any depletion on production from an oil or gas property which is subject on the provisions of IRC section 613A(c) (Exemption for Independent Producers and Royalty Owners).

  3. In the case of an individual: Subtract the "zero bracket amount."

  4. Make appropriate adjustments to income based on audit recommendations.

Multiply the results obtained in above by 0.65. This product is the 65 percent of taxpayer's taxable income limitation. The taxpayer is not allowed Depletion under IRC section 613A(c) [percentage depletion] in excess of this amount. If the tentative depletion determined in (i) does not exceed the 65 percent limitation determined above, the tentative depletion is the allowable depletion for those properties. If the tentative depletion determined in (i) exceeds the 65 percent of taxable income limitation determined above. If the tentative depletion computed in (2) exceeds the 65 percent of taxable income limitation, the excess is disallowed. The disallowed percentage depletion must be allocated to each of the properties so that the allowable percentage depletion can be compared with the cost depletion applicable to each property. (The greater of cost depletion or percentage depletion is allowable.) See IRC sections 613(a) and 613A(d)(1).

The Barrel Limitation (Depletable oil quantity). The IRC defines "depletable oil quantity" in terms of barrels per day. It appears that the agent will be better able to make computations and keep the taxpayer's depletion under IRC section 613A(c) in perspective if the depletable quantity of oil is expressed in barrels per tax period. We have, therefore, expressed the amount of oil subject to percentage depletion under IRC section 613A(c) in barrels per tax period. Include "all" production. Reconcile all production on return. Is production from "flow through entities " included? Spot check price per barrel by dividing gross income by barrels per lease or property. If large differences in price per barrel appears between properties, investigate. Business under common control and members of the same family are treated as one taxpayer, and the tentative quantity must be allocated. See IRC section 613A(a)(8). Compute the total of the taxpayer's production of oil in barrels and gas in barrel equivalents for all properties. If the production from the taxpayer's properties exceed 365,000 barrels (1000 barrel per day), then the "depletable oil quantity" will apply. Oil and gas should not be separated for each property. Separate schedules can be prepared for primary production and marginal production. The taxpayer can allocate the barrel limitation to marginal production first, then to primary production. The schedules should provide the information below:

  1. Name of the property AND whether it's marginal or not.

  2. Number of barrels of production for the tax period.

  3. Convert the gas to equivalent barrels at 1 barrel = 6 MCF of gas.

  4. Add barrels of oil to barrels of gas to get total production from property.

Note:

Percentage depletion disallowed per Barrel or Depletable oil quantity limitation is not carried forward and is lost forever.

Carryover of Percentage Depletion Disallowed from 65% Limitation. IRC section 613A(d)(1) provides that any amount of percentage depletion disallowed because of the 65 percent of taxable income limitation will be treated as an amount allowable under IRC section 613A(c) in the following year. In the following year, it will still be subject to the 65 percent of taxable income limitation. The amount of percentage depletion disallowed shall be allocated to the respective properties from which the oil or gas was produced in proportion to the percentage depletion otherwise allowable to such properties under IRC section 613A(c).

The allocation of disallowed depletion should be computed in a schedule which has the following column headings:

  1. Name of Property

  2. Cost depletion

  3. Tentative allowable percentage depletion

  4. Disallowed percentage depletion

Exhibit 4.41.1-8  (07-31-2002)
Allocation of Overhead Expenses

This exhibit is an example of the proper allocation of a company's overhead to the various producing leases. The allocation is based on direct expenses. The allocation is required under Treas. Reg. 1.613–5(a) for the computation of taxable income from the property and the 50 percent of taxable income limitation in computing percentage depletion. See Treas. Reg. 1.613–1.

If a taxpayer has not made an allocation of overhead to the various leases, the agent should scan the depletion computation schedules to decide whether or not an allocation of overhead would probably affect an adjustment in depletion. [How near to the 50 percent (100 percent for taxable years beginning after December 31,1990) net taxable income limitation is the 22 percent, or applicable percent, of gross income?] If adjustment is probable, the agent should scan the unallocated overhead account to determine the proportion that would most likely be allocated to producing leases. If a relatively significant adjustment appears likely, the agent should make the allocation schedule. Computer assistance may be requested in larger cases.

If the taxpayer has made an overhead allocation, the agent should consider the points listed in (2) above. If adjustment to depletion might be significantly affected by a reallocation, the agent should carefully analyze the taxpayer's overhead allocation and verify that it is based on an acceptable method.

Interest expense paid on money borrowed for operating capital is an overhead item which should be allocated to producing and nonproducing activities prior to allocation among the properties. Interest expense paid on money borrowed for investment (equipment, IDC, leasehold, etc.) is a direct expense of those properties and should be allocated to them 100 percent.

If the taxpayer operates his/her properties in conjunction with properties owned by others and charges a fee for services, the fee is not a credit to his/her operating expenses or overhead account; it is an income item. However, to the extent that the taxpayer has expense in connection with earning these fees, the expenses should not be charged to his/her leases.

In examining the allocation, the agent should verify that " nonproducing" activities are consistently treated. If a well was capable of production but was temporarily shut-in (perhaps waiting pipeline connection), its expenses should not be included under nonproducing for allocation between producing and nonproducing activities and also included under producing properties in allocating to the various leases.

Once the allocation is made to specific properties, the agent should verify that the overhead is properly entered in the "line computation " for the property. He/she should be particularly alert for transposition errors between properties with similar names.

Exhibit 4.41.1-9  (06-30-2005)
Items To Consider During Examination

Leases Expired or Forfeited:

  1. Obtain list of leases charged off description, etc.

  2. Verify cost or basis-expiration date of lease.

  3. Review current lease records for evidence of top leasing.

  4. Are leases involved in a unitization or other reclassification?

  5. Partial abandonments are not deductible.

Intangible Development Costs:

  1. Has proper election been made? Treas. Reg. 1.612-4, IRC section 59(e), IRC section 291.

  2. Are there advance payments involved? Rev. Rul. 71-252.

  3. Are tangible costs included? Treas. Reg. 1.612-4(a).

  4. Do IDC costs correspond to taxpayer's interest in property? How was it acquired?

  5. If the taxpayer is a corporation which is an integrated oil company, did it reduce its IRC section 263(c) deductions (IDC for years after 1982) by 15 percent as required by IRC section 291(b)?

Condemned or Expired Royalties:

  1. Determine proper year of deduction based on event taxpayer relied on.

  2. Verify tax basis. Has amount been previously charged off?

  3. Has taxpayer disposed of title to property?

Dry-Hole Costs:

  1. Is expense charged to appropriate property for purpose of computing depletion limitation?

  2. Examine contracts; determine existence of dry-hole contributions, bottom-hole contributions, and farm-ins.

  3. Do dryhole costs include only abandonments? IDC with respect to dryhole costs are deductible under IRC section 263(c) unless taxpayer has elected to capitalize IDC.

Depletion:

  1. Is taxable income (before depletion) computed by property? Percentage depletion cannot exceed 50 percent of the property’s taxable income for years beginning prior to 1991. For tax years 1991 through 1997, percentage depletion cannot exceed 100 percent of the property’s taxable income For taxable years beginning after December 31, 1997, the net income limitation does not apply to domestic oil and gas production from marginal properties.

  2. Is depletion claimed on proven properties acquired after 1/1/1975?

  3. IRC section 613A(d) limits the percentage depletion to 65 percent of the taxpayer’s current year taxable income, calculated without considering any percentage depletion deductions.

Gross Income :

  1. Obtain detailed schedule of lease operations for current and prior year. (Depletion schedules may serve for this purpose.)

  2. Compare reported receipts, by property, secure explanations for all unusual increases or decreases.

  3. Test income on run tickets for selected leases and selected months.

  4. Working interest income is subject to self-employment tax.

Operating Expenses:

  1. Analyze for large unusual expenses; capital expenditures.

  2. Legal and professional-geological and geophysical.

  3. Determine why some leases have losses.

Alternative Minimum Tax:

  1. Percentage depletion in excess of adjusted basis of leasehold as of beginning of year.

  2. Excess intangible drilling costs is a tax preference item and should include a portion of the overhead. This preference applies only to costs for which the corporation did not elect the optional 60-month write-off under IRC section 59(e) for the regular tax.

Sale of Oil and Gas Properties:

  1. Was leasehold basis reduced by allowed or allowable depletion?

  2. Recapture post-'75 intangible development costs? IRC section 1254.

  3. Was a continuing economic interest retained?

Joint Interest Accounting:

  1. Are expenses billed to joint owners handled correctly?

  2. Is the taxpayer deducting pro-rata share of expenses? Test selected leases-consider those operating at a loss and those with unusually large expenses.

  3. Does an increasing credit balance in the oil and gas payout account represent income that should be reported?

Mandatory Referrals:

  1. Engineers-

    • Cases with Activity Codes 219-225 & 290

    • Cases with Activity Code 483 and Gross Receipts/Deductions $1,000,000 and above.

  2. Financial Products-

    • Cases with Activity Codes 219-225 & 290

    • Cases with Activity Code 483 and Gross Receipts/Deductions $1,000,000 and above.

  3. Economist-

    • Cases with Activity Codes 225

    • All CIC Cases

  4. Employment Tax-

    • Cases with Activity Codes 223–225

  5. Computer Audit Specialist-

    • Cases with Activity Codes 219–225 & 290

Exhibit 4.41.1-10  (07-31-2002)
Useful Examination Techniques—Oil and Gas Income

Reconcile the oil and gas income on the depletion schedule to the taxpayer's books.

Review the depletion schedules or the subledgers and list the leases that are operating at a large loss.

  1. Determine the reasons for the losses.

  2. If a large loss is not caused by IDC or some unusual expense, request the lease file and oil run tickets.

  3. From the lease file, determine if the income-sharing arrangement is proper. Income may have been diverted to production payments, selected entities, or children.

  4. Compare the oil run tickets to the oil income reported on a test basis.

Analyze the suspense account for income that should be recognized in the current year.

Verify the accuracy of the oil and gas payout account for joint owners:

  1. Does a credit balance represent oil and gas income that the taxpayer should report?

  2. If all income received by a operator is posted as a credit to the oil and gas payout account, has the operator transferred his/her share to the income account?

  3. Do the debits and credits to the oil and gas payout account balance on a monthly basis? If not, why?

Test the accuracy of oil and gas income reported on selected leases:

  1. Compare lease income reported with oil run tickets for selected months.

  2. Reconcile differences.

Exhibit 4.41.1-11  (07-31-2002)
Hydrocarbon Series in Petroleum

Paraffin Series (Saturated)

Type formula: C nH2n+2 Suffix -ane
Examples    
  Methane CH 4  
  Ethane C 2H6  
  Propane C 3H8  
  Butane C 4H10  
  Pentane C 5H12  
  Hexane C 6H14  

Isomers of Paraffin Series


Starting with the formula C4H10, the carbons may be arranged either in a straight chain, or in a branched chain.
The straight chain is designated as normal butane (n-butane) and the branched chain as isobutane. These compounds have entirely different physical properties as well as different chemical (reactive) properties. The number of possible isomers increases rapidly as the number of carbon atoms in the hydrocarbon molecule is increased (i.e., three pentanes, five hexanes, nine heptanes, eighteen octanes, etc.).

Olefin (Ethylene Series Unsaturated)

Type formula: C nH2n Suffix -ene or -ylene
Examples    
  Methane CH 4  
  Ethene (Ethylene) C2H4
  Propene (Propylene) C3H6
  1–Butene (Butylene) C4H8
  2–Butene (Butylene) C4H8

Napthene Series (Saturated)

Type formula: C nH2n Suffix -ane
Ring or Cyclic Compounds (Cycloparaffins)

Aromatic (Benzine) Series

Type formula: C nH2n-6 Suffix -ene

Diolefin (dienes) Series (Unsaturated)

Type formula: C nH2n-2 Suffix -ane
System of conjugeted double bonds

Acetylenes (Highly Unsaturated)

Type formula: none Suffix -yne
Contains one triple bond

Exhibit 4.41.1-12  (06-30-2005)
Distillation Fractions — Typical Crude Oil

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Exhibit 4.41.1-13  (06-30-2005)
Flow Diagram — Modern Refinery

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Exhibit 4.41.1-14  (07-31-2002)
Illustrative Information Document Request — Accounting System

Shown below are the contents of a typical Form 4564 (Information Document Request) which can be used to survey a taxpayer's accounting system.
  In order that we might conduct the examination of your tax return in the most efficient manner, we would like to review the accounting system used. Would you please make available the listed items. We would like to have a member, or members, of your accounting department available to answer any questions that might arise.
  1. Organization Chart listing key personnel
  2. Chart of Accounts & description of accounting system
  3. Data Processing Department Systems Manual
  4. Tax workpapers
  5. Consolidated Profit & Loss Statements
  6. Divisional Profit & Loss Statements
  7. Analysis of consolidating eliminations
  8. Internal Control Manual
  9. Internal Audit Procedures Manual
  10. Capitalization Policy Manual
  11. Cost Accounting Policy Manual

Exhibit 4.41.1-15  (07-31-2002)
Classification of Costs

Classification of costs is necessary in order to determine the most suitable method of accumulating and allocating cost data. The principal methods of accumulating costs are described below.

Function:

  1. Manufacturing. Costs applied to producing a product.

  2. Marketing. Costs incurred in selling a product or service.

  3. Administrative. Costs incurred in policy-making activities.

  4. Financial. Costs related to financial activities.

Elements:

  1. Direct material. Material which is an integral part of the finished product.

  2. Direct labor. Labor applied directly to components of the finished product.

  3. Overhead. Indirect materials, indirect labor, and the manufacturing expenses that cannot logically be charged directly to specific units, jobs, or products.

Product:

  1. Direct. Costs which are charged to the product and require no further allocation.

  2. Indirect. Costs which are allocated.

Department:

  1. Production. A unit in which operations are performed on the part or product and whose costs are not further allocated.

  2. Service. A unit not directly engaged in production and whose costs are ultimately allocated to a production unit.

When Charged to Income:

  1. Product. Costs included when product costs, as defined above, are computed. Product costs are included in inventory and in cost of sales when the product is sold.

  2. Period. Costs associated with the passage of time rather than with the product. These are closed out to the income summary each period since no future benefits are expected.

Relation to Volume:

  1. Variable. Costs which change in total in direct proportion to changes in related activity. The unit cost remains the same regardless of volume.

  2. Fixed. Costs which do not change in total over wide ranges of volume. The unit costs decrease as volume increases.

Period Covered:

  1. Capital. Costs which are expected to benefit future periods and are classed as assets.

  2. Revenue. Costs which benefit only the current period and are thus expenses.

Degree of Averaging:

  1. Total. The cumulative cost for the established category.

  2. Unit. The total cost divided by the number of units of activity or volume.

Exhibit 4.41.1-16  (07-31-2002)
Reference and Research Material

Periodicals:

  1. Oil and Gas Journal (weekly)
    PennWell Publishing co.; Tulsa, Oklahoma

  2. Oilweek (weekly)
    Maclean Hunder Ltd.; Calgary, canada

  3. Chemical Week (weekly)
    McGraw Hill Inc.; New York, New York

  4. Petroleum Intelligence Weekly (weekly)
    Wanda Jablonski; New York, New York

  5. Chemical and Engineering News (weekly)
    American Chemical Society, Washington, D.C.

  6. Petroleum Economist (monthly)
    Petroleum Press Bureau Ltd.; London, England

  7. Petroleum Engineer International (monthly plus 3 specials)
    Harcourt Brace Jovanovich Publications; Dallas, Texas

  8. Hydrocarbon Processing (monthly)
    Gulf Publishing Co.; Houston, Texas

  9. Process Engineering (monthly)
    Morgan Grampion Ltd.; London, England

Text:

  1. Petroleum Refining for the Non-Technical Person
    William L. Leffler (1979)
    Petroleum Publishing Co.; Tulsa, Oklahoma

  2. Accounting and Management Control Practices in Petroleum Refining
    William F. Schmeltz (1966)
    University Microfilms International; Ann Arbor, Michigan
    (Available at AICPA Library (NY) to Members; Reference 250 Oil 4)

  3. Principles and Presentation: Refining
    One of a series of surveys of financial reporting practices prepared by Peat, Marwick, Mitchell
    & Co. copies of such surveys (9 industries) may be ordered from their offices.

  4. The Petrochemical Industry, Market and Economics
    Albert V. Hahn (1970)
    McGraw Hill Book Co.; New York, New York

  5. Origin and Refining of Petroleum
    H.G. McGroth and M.E. Charles (1971)
    (Advances in Chemistry Series #103)
    American Chemical Society, Washington, D.C.

  6. Refining Petroleum for Chemicals
    H. Leftin (1970)
    (Advances in Chemistry Series #97)
    American Chemical Society, Washington, D.C.

Articles:

  1. Effect of Product Costing on Refinery Income Determination
    Mohamed H. EI-Badawi
    Oil and Gas Tax Quarterly, March 1982
    Matthew Bender, New York, New York

  2. Petrochemicals: Changing Markets and Limits to Growth Alter Outlook
    Edward L. McClelland
    Federal Reserve Bank of Dallas, Economic ReviewlMay 1982

Exhibit 4.41.1-17  (07-31-2002)
Examples – Computer Application Programs

Stratification. Divides an account into dollar ranges and accumulates amounts in each range as well as the number of items in each range. The account is then totaled to show total dollars and total items. The stratification program can be applied to all real accounts as well as all nominal accounts.

Regression Analysis. A comparative analysis of certain accounts which have an apparently normal inter-relationship. Prior years are evaluated electronically to determine a range of normality over a representative number of years. Those relationships are then compared against current year account balances and aberrations identified for examination action.

Selected Invoices Listed by Account. After the stratification program has helped identify examination areas, this program protects vouchers within selected accounts and stratas.

Selected Invoices Listed in Filing Sequence. If the original selection (item 3) is not in filing sequence, the vouchers can be resorted to expedite voucher extraction from files.

Vendor Analysis. Identifies number of records, total charges, and all accounts to which the charges of a particular vendor appear.

Cost of Sales.

  1. This voluminous area can be examined through use of statistical sampling techniques.

  2. Every nonrecurring vendor can be printed. Based upon an examination by exception, nonrecurring vendors may indicate a potential examination area.

Sales. Extraction of sales to foreign affiliates for the purpose of comparing foreign pricing to domestic pricing.

Fragmentation. This program formats invoices (or vouchers) into an unfragmented listing. Can be used for lists by vendors and/or accounts.

Employment Tax Program. Produces a computer generated Form 4668, FUTA tax report, social security data file, and W–4 analysis identifying employees with little or no withholding.

Depreciation. Calculates depreciation on each class of asset by year as each class is capitalized producing a listing by year and class of asset and cost component breakdown.

Foreign Sales. Computes the gross margin on unrelated customer sales and compares with gross margin on related customer sales.

Statistical Sampling. (PAL) Produces random sample of universe and calculates adjustment based on an examined sample.

Analysis of Expenses for Application of Regulation 1.861.8.

Calculation of Foreign Tax Credits.

Examination of Investment Tax Credits.

Exhibit 4.41.1-18  (07-31-2002)
Illustrative Finished Products Inventory

Main Line of Petroleum Finished Products

  1. Products tailored to meet rigid specifications by appropriate treating and blending of unfinished stocks and inclusion of additives.

  2. Subcategories:

    All gasolines Liquified Petroleum Gas
    Special Naphtha Gas Oils (i.e., Diesel)
    Jet Fuels Fuel Oils
    Kerosenes Asphalt

Specialty Products

  1. Generally low volume, high value products manufactured from otherwise saleable stocks.

  2. Subcategories:

    Lubricating Oils
    Finished Waxes and Greases
    Petrochemicals

Byproducts

  1. Products resulting from processing designed primarily for other objectives.

  2. Subcategories:

    Sulfur (from quality improvement processes)
    Coke (from converting residual stocks)

Exhibit 4.41.1-19  (07-31-2002)
Characteristics of Gasoline Blending Components

    Octane Number
Gasoline Component Vapor Pressure (RVP) Motor Research
N-butane 52.0 92 93
Reformate 2.8 – 4.2 84 – 88 94 – 100
Hydrocrackate 1.7 – 3.9 73 – 76 75 – 79
Alkylate 4.6 96 97
Straight-run Gasoline 11.1 61 66
Catalytic Cracked Gasoline 4.4 77 92

Exhibit 4.41.1-20  (07-31-2002)
Cost of Production Report

The cost of production report shows all costs chargeable to a department or cost center for the period. Since its principal objective is the control of costs, detailed data relating to total and unit costs are provided. Typically, the cost breakdown is made by cost elements for each department (or cost center). This report is also a good source for summary journal entries at the end of the month.

The cost of production report generally contains three sections:

  1. Quantities. This section accounts for the physical flow of units into and out of a department.

  2. Costs to account for. This section accounts for the incurrence of costs that were:

    1. In process at the beginning of the period

    2. Transferred in from previous departments

    3. Added by the department

  3. Costs accounted for. This section accounts for the disposition of costs charged to the department. Were the costs:

    1. Transferred out to another department or to finished goods?

    2. Completed and on hand?

    3. Still in process at end of the period?


It should be noted that the total of the costs to account for must equal the total of the costs accounted for.

The cost of production report may be very detailed or may only show totals.

The examiner should peruse these sections to ensure that improper adjustments are not being made for tax purposes via Schedule M and that various types of overhead items are being properly allocated.

Exhibit 4.41.1-21  (07-31-2002)
Suggested Techniques for Examining Catalyst Accounts

Review taxpayer's internal accounting manuals to ascertain systems/methods of accounting for catalysts.

Obtain a simplified flow diagram of refinery operations.

  1. Identify all units using catalysts

  2. Segregate those utilizing precious metals

  3. From refinery operating handbooks or manuals, ascertain operational factors (on-going change out versus turnaround change-out, etc.)

  4. Obtain specifics as to type of each catalyst

Is spent catalyst reclaimed, sold for salvage value, or junked?

  1. If reclaimed:

    1. What are the charges? How handled?

    2. Is there a credit for spent catalyst?

    3. How are the credits handled?

  2. If sold, how are the sales proceeds handled?

When precious metal catalysts are involved:

  1. What is the total cost of the catalyst?

  2. What is the cost of the precious metal?

  3. Is the total cost or net cost (less metal) capitalized?

  4. How was net cost determined?

When operations involve continuous frequent replenishment of fresh catalyst, was the initial charge capitalized?

  1. If so, over what life (life of unit versus life of catalyst)?

  2. How were additional expenditures (total or net cost of make-up catalyst added to unit) treated?

Internal cost accounting records for operational purposes/financial purposes may provide additional information.

Exhibit 4.41.1-22  (07-31-2002)
AFRA Computation Method

AFRA

Vessel Category Abbreviation Vessel dwt
(Long Tons)
Medium Range MR 25,000–44,999
Large Range 1 LR–1 45,000–79,999
Large Range 2 LR–2 80,000–159,999
Very Large Crude Carrier VLCC 160,000–319,999
Ultra Large Crude Carrier ULCC 320,000–549,999
The following is an example of how the multirate AFRA freight charge is computed for a shipment from Forcados, Nigeria to Philadelphia on a 74,499 dwt (long ton) vessel (75,694 metric ton dw. equivalent) loaded July 4, 1997.
1. The vessel size (dwt) determines the AFRA category rate, LR–1 in this example.
2. Multirate AFRA for a 75,694 metric ton vessel loaded in July 1997, is W131.3.
3. The 1997 Worldscale rate for a voyage from Forcados to Philadelphia is $7.40 per metric ton.
4. The AFRA rate times the Worldscale rate gives the rate per ton (W 131.3 x 7.40 = $9.69).
5. The actual cargo times the rate per ton gives the total charge:
Vessel dwt (LR–1 Category) 75,694  metric tons
Less: Bunker fuel, water, and stores (4,694)  metric tons
__________
Cargo (actual cargo loaded) 71,000  metric tons
Rate per ton (see 4. above) $9.69  per metric ton
__________
   
Total charge per cargo $687,990
___

Note:

This example does not include the effect of the fixed rate differential applicable in respect of additional premiums for coverage of Oil Pollution Liability Insurance on vessels carrying crude oil trading to the U.S.

Exhibit 4.41.1-23  (07-31-2002)
Cargo Sharing–Example


Vessel 64,499 dwt (LR–1 category) (65,534 metric ton dw. equivalent)

Voyage: Loading in Puerto la Cruz and Trinidad in July 1997
   Discharging in Philadelphia and New York

Related U.S. Importer paying multirate AFRA rates:
   30,000 metric ton cargo from Puerto la Cruz to Philadelphia $4.49 per metric ton

Third-Party cargo sharing at spot rate per ton:
   30,000 metric ton cargo from Trinidad to New York $6.00 per ton


  Total Multiport
Rate 		Related
Importer 		Third-Party
Importer
Cargo (Metric Tons) 60,000   30,000 30,000
Worldscale Rates   $5.64 $4.49  
Multirate AFRA (July 1997)        
 For a 65,543 metric ton vessel   W141.2    
 For a 30,000 metric ton cargo     W185.9  
    _______________
Multiport Rate   $7.96
_____ 		   
Single Discharge Rate     $8.35
_____ 		 
Third Party Spot Rate       $7.00
_____
         
Limitation a.        
Total Cargo 60,000 metric tons X multiport rate ($7.96)     $477,600
Less charge paid by third party        
 [30,000 metric tons X spot rate ($6.00)]       $210,000
_____
  Limitation a. Charge       $267,600
_____
         
Limitation b.        
Related Importer cargo 30,000 metric tons X single discharge rate ($8.35)   $250,500
_____
         
Amount allowable:        
 The lesser of limitation a. or b.     $250,000
_____

Note:

This example does not include the effect of the fixed rate differential applicable in respect of additional premiums for coverage of Oil Pollution Liability Insurance on vessels carrying crude oil trading to the U.S.

Exhibit 4.41.1-24  (07-31-2002)
Computation of Deadfreight and Deadfreight Limitation

In 1976, a 84,000 dwt ton ship is used to transport 55,000 tons of 34 Arab Light crude from Ras Tanura to Philadelphia. The deadfreight was deemed to have been incurred for the benefit of the importer. The draft restrictions at the U.S. importers terminal in Philadelphia is 39 feet. The maximum draft at Ras Tanura is 72 feet.
  Loading Began: August 5, 1976

Worldscale rates per ton:

Ras Tanura to Quoin Island $ .60
Quoin Island to Philadelphia $15.80
____
 Total $16.40
____
Cost of Shipment to the Importer
    Total Cargo Deadfreight
Vessel dwt tons   84,000    
Less stores, water, bunker   (2,000)    
  tons   82,000 55,000 27,000
Worldscale charge $16.40      
Vessel AFRA LR–2 x .573
_______ 		     
Charge per ton $9.397 $9.397 $9.397 $9.397
  ________________________
Total Charge   $770,554 $516,835 $253,719
    __________________
Cost per barrel:        
Conversion of API 34 crude long tons to barrels: 7.4917
Cargo tons: 55,000 x 7.4917 = 412,043 barrels
Total cost: $770,554 412,043 = $1.87 per barrel
Based on the recommended guide for determining port classification, the largest fully loaded vessel that can make the voyage between the ports of loading and discharge under normal operating conditions is a LR–1 category vessel. Deadfreight is allowable to the extent that the cost per barrel does not exceed the cost per barrel had the cargo been carried in a LR–1 vessel.
Worldscale Rate $16.40
AFRA Rate LR–1 Category .783
_____
Cost per Ton $12.84
_____
The barrel cost for cargo based on a fully loaded vessel is computed as follows: Cost per ton $12.84_7.4917 (barrels per long ton) = $1.714. The charge for deadfreight is not fully allowable because the actual charge per barrel exceeds the charge per barrel that would have been incurred had the cargo been transported in a fully loaded vessel capable of clearing the draft limitations of the loading and discharge ports. The allowable deadfreight is computed as follows:
  TOTAL CARGO DEADFREIGHT
Shipment Charge based on Vessel size LR–2 $770,554 $516,834 $253,719
Maximum Allowable:      
  Cargo 412,043 barrels x $1.714 = 706,242 516,835 189,407
  __________________
Deadfreight Not Allowable $ 64,312 –0– $64,312
  __________________

Exhibit 4.41.1-25  (07-31-2002)
Computation of Deadfreight Using Multirate AFRA

Caution: This section may be revised.
A vessel of 110,000 dwt moved cargo of 75,000 tons from Bonny Nigeria to the U.S. Gulf Coast. The cargo was loaded in July 1985.

        AFRA
Index 		WS
Rate 		Charge
per Ton
Actual Vessel of 110,000 dwt 41.7 $ 14.30 $ 5.96
Smallest fully loaded vessel that could carry the cargo 57.2 $ 14.30 $ 8.18
(75,000 dwt x 103%) = 77,250 dwt      
Computation of the voyage charge including deadfreight      
1. Total tons carrying capacity      
   Vessel dwt         110,000
   Less: Bunker       ( 2,800)
      Stores, water, supplies     ( 350)
      Ballast included in dwt     ( 4,270)
            ____
   Net carrying capacity     102,580
Deadfreight limitation        
   (70% of 110,000)   77,000  
   Less actual cargo   75,000
____ 		 
   Deadfreight not allowable 2,000 ( 2,000)
____
   Cargo and deadfreight     100,580
   Rate for vessels dwt     x 5.96
____
   Charge based on cargo and deadfreight     $599,467
2. The cargo times the rate for the smallest fully loaded vessel that could carry the cargo
   Total tons loaded       75,000
   Assumed vessel gross up       77,250
   (103% of 75,000)        
             
   Rate per tone for 77,250 dwt vessel   $ 8.18
   Actual cargo (tons)     x 75,000
____
   Cargo charge for fully loaded vessel     $613,500
____
3.  Allowable charge    
   The lesser of (1) or (2) above     $599,467
____

Exhibit 4.41.1-26  (06-30-2005)
Analysis of SPE Factual Scenarios of Probable Reserves

Scenario No. One: Reserves anticipated to be proved by normal step-out drilling where sub-surface control is inadequate to classify these reserves as proved.

  1. A well to be drilled as a "normal step-out" is a well to be drilled into an extension of a known deposit. Whether a well is a normal step-out is a question of fact. Proximity to producers is usually indicative of such existence. These types of wells are sometimes referred to as "one location step-outs." See generally Rev. Rul. 77-136, 1977-1 C.B. 167. Exhibit G. The examiner/engineer should include probable reserves associated with normal step-out drilling in the cost depletion computation.

  2. Amount of Reserves to include: Most likely quantity expected to be recovered by the drilling of the normal step-outs. The examiner/engineer may determine the quantity by multiplying the quantity anticipated to be recovered from a successful well by the anticipated probability of success of the well. Taxpayers are likely to maintain estimates of this category of probable reserves.

  3. The appropriate time to include the estimated quantity is the earlier of:

    1. when the taxpayer classifies the reserves as probable, which may occur as early as the acquisition of the property;

    2. when an authority for expenditure (AFE) to drill the step-out has been approved by the operator;

    3. when an application to drill the well has been approved by the appropriate conservation agency; or

    4. when significant expenditures related to drilling the step-out have occurred

    .

Scenario No. Two: Reserves in formations that appear to be productive based on well log characteristic but lack core data or definitive tests and which are not analogous to producing or proved reservoirs in the area.

  1. The existence of multiple geologic formations is a common occurrence in many geographic locations. Information gathered in the course of drilling and logging wells routinely identifies these "behind pipe" formations. The testing of behind pipe formations is a common part of the complete development of any oil and gas property. The formations are described as not being "analogous to producing or proved reservoirs in the area" , thus they would not be extensions of a known deposit. Whether they represent a new body or mass whose existence is indicated by geological surveys or other evidence to a high degree of probability is a question of fact. The ability to determine the vertical extent and petrophysical properties of these formations is usually evidence of such existence. The fact that the taxpayer describes the reserves contained in the formation as probable is further evidence of such existence. Accordingly the examiner/engineer should include probable reserves associated with these formations in the cost depletion computation.

  2. Amount of Reserves to include: The quantity most likely to be recovered by the testing of the behind pipe formations. The examiner/engineer may determine this quantity by multiplying the amount anticipated to be recovered from a successful well completion by the anticipated probability of success of the completion. Taxpayers are likely to maintain estimates of this category of probable reserves.

  3. For this type of activity, the appropriate time to include the estimated quantity is the earlier of: 1), 2), 3) or 4), as described above in Scenario No. One section c).

Scenario No. Three: Incremental reserves attributable to infill drilling that could have been classified as proved if closer statutory spacing had been approved at the time of the estimate.

  1. This scenario is similar to SPE Factual Scenario Number Four in that, if certain steps are taken, the taxpayer is likely to recover some additional quantity beyond proved reserves from the assured portion of the deposit. This scenario differs in that it contemplates a change in the regulatory environment. The factual scenario does not indicate whether changes to statutory spacing are routinely approved by the appropriate conservation agency. There is some chance, albeit remote, that the taxpayer may never be able to recover the incremental reserves without a change in the statutory spacing. Examiners/engineers should not include these reserves until they have resolved these uncertainties for this type of activity.

  2. Amount of Reserves to include: If the examiner/engineer succeeds in resolving the uncertainties to his or her satisfaction, then the incremental reserves attributable to infill drilling quantity should be included in the cost depletion computation. Taxpayers are likely to maintain estimates of this category of probable reserves if they have substantial onshore holdings. Whether a well is an infill well is a question of fact.

  3. Subject to the foregoing, for this type of activity, the appropriate time to include the estimated quantity is the earlier of: 1), 2), 3) or 4), as described above in Scenario No. One section c).

Scenario No. Four: Reserves attributable to improved recovery methods that have been established by repeated commercially successful applications when (a) a project or pilot is planned but not in operation and (b) rock, fluid, and reservoir characteristics appear favorable for commercial application.

  1. In many instances companies implement improved recovery projects to recover some additional quantity beyond proved reserves from the assured portion of the deposit. The examiner/engineer should include probable reserves associated with these improved recovery projects in the cost depletion calculation

  2. Amount of Reserves to include: The quantity most likely to be recovered by the improved recovery project. The examiner/engineer may determine this quantity by multiplying the quantity expected to be recovered by successful application of the improved recovery method by the probability of success of the project. Taxpayers are likely to maintain estimates of this category of probable reserves.

  3. Whether a pilot or project is planned is a question of fact. It shall be considered to have occurred at the earlier of: 1), 2), 3) or 4), as described above in Scenario No. One section c). Once the engineer has determined the pilot or project is planned, the probable reserves estimated should be included.

Scenario No. Five: Reserves in an area of the formation that appears to be separated from the proved area by faulting and the geologic interpretation indicates the subject area is structurally higher than the proved area.

  1. Separate fault blocks within the same geologic formation are common. While a separate fault block can sometimes be technically classified as a separate reservoir, it is not generally considered an entirely different and separate zone from the known producing zone. The type of well described by the SPE is reasonably analogous to an exploratory step-out. These are step-outs to a producing mineral deposit located at a considerable distance from the producing wells. See generally Rev. Rul. 77-136, 1977-1 C.B. 167. Therefore, IRS engineers consider a separate fault block as a "new body or mass" of the existing mineral deposit.

  2. Whether the existence of a new body or mass is indicated by geological surveys or other evidence to a high degree of probability is a question of fact. The ability to map a separate fault block with enough certainty to plan a well location is usually evidence of such existence. The fact that the taxpayer describes the reserves contained in the fault block as probable is further evidence of such existence. Accordingly the examiner/engineer should include probable reserves associated with these formations in the cost depletion computation.

  3. Amount of Reserves to include: The quantity most likely to be recovered by the testing of the behind pipe formations. The examiner/engineer may determine this quantity by multiplying the amount anticipated to be recovered from a successful well completion by the anticipated probability of success of the completion. Taxpayers are likely to maintain estimates of this category of probable reserves.

  4. For this type of activity, the appropriate time to include the estimated quantity is the earlier of: 1), 2), 3) or 4), as described above in Scenario No. One section c).

Scenario No. Six: Reserves attributable to a future workover, treatment, re-treatment, change of equipment, or other mechanical procedures, where such procedure has not been proved successful in wells which exhibit similar behavior in analogous reservoirs.

  1. This is also similar to SPE Factual Scenario Number Four dealing with improved recovery methods because the taxpayer will have to take proactive steps and make expenditures to recover the reserves. However, the nature of the expenditure in this case is more closely related to operations than to development activity. If the described procedures are commercially employed in the industry, then the examiner/engineer may include the associated reserves if a reasonably prudent operator would pursue them. Whether these conditions have been met are questions of fact. As a result of these uncertainties, examiners/engineers should only include these probable reserves until after having resolved them.

  2. Amount of Reserves to include: If the examiner/engineer succeeds in resolving the uncertainties to his or her satisfaction, then the quantity most likely to be recovered by the application of the procedure should be included in the cost depletion computation. The examiner/engineer may determine this quantity by multiplying the amount anticipated to be recovered from a successful procedure by the anticipated probability of success of the procedure. Taxpayers do not normally maintain estimates of this category of probable reserves.

  3. For this type of activity, the appropriate time to include the estimated quantity is the earlier of: 1), 2), 3) or 4), as described above in Scenario No. One section c).

Scenario No. Seven: Incremental reserves in proved reservoirs where an alternative interpretation of performance or volumetric data indicates more reserves than can be classified as proved.

  1. This is similar to Factual Scenario Number Three because some additional quantity beyond proved reserves may be recovered from the assured portion of the deposit. This scenario differs in that, in some situations, the additional recovery may occur regardless of whether the taxpayer conducts additional development activities. An estimate of proved reserves made early in the life of a reservoir may be conservative since only limited performance data is available to predict future production levels. The examiner/engineer should include probable reserves associated with these assured deposits.

Exhibit 4.41.1-27  (02-19-2008)
Working Families Tax Relief Act of 2004 Income Tax Provisions

The President signed into law the Working Families Tax Relief Act of 2004 (P.L. 108-311), on October 4, 2004. Income tax provisions affecting the domestic petroleum industry are summarized below:

  1. Sec. 314 – Taxable Income Limit on Percentage Depletion for Oil and Gas Produced From Marginal Properties

    1. The Act amended subparagraph (H) of section 613A(C)(6) extending the temporary suspension of taxable income limit with respect to marginal production through calendar year 2005 (December 31, 2005). Without the amendment, the temporary suspension of taxable income limit with respect to marginal wells would not have been available for the 2004 tax returns.

    2. The provision is effective to taxable years beginning after December 31, 2003.

    .

Exhibit 4.41.1-28  (02-19-2008)
American Jobs Creation Act of 2004 Income Tax Provisions

The President signed into law the American Jobs Creation Act of 2004 (P.L. 108-357), on October 22, 2004. Income tax provisions affecting the domestic petroleum industry are summarized below:

  1. House Bill Section 302, Primary Code Section 40A - Biodiesel Income Tax Credit and revised Code Section 38(b) – General Business Credit.

    1. The Act creates Code Section 40A – Biodiesel Used as Fuel, providing an income tax credit reportable as a General Business Tax Credit for Biodiesel. Biodiesel is an alternative fuel produced from domestic renewable resources; for example, soybean oil or recycled cooking oils. Biodiesel contains no petroleum but can be blended with petroleum diesel into a bio-diesel blend. A common fuel blend would be 20% biodiesel/80% petroleum diesel.

    2. There are two parts to determining the credit. First, a credit of $.50/ gallon is allowed for each gallon of biodiesel used in the production of a qualified biodiesel blend that is sold by the taxpayer for use as a fuel or is used as a fuel by the producing taxpayer. Second, a credit of $.50/gallon is allowed for each gallon of biodiesel not in a mixture which is used by the taxpayer as a fuel or is sold at retail by the taxpayer directly to the fuel tank of the customer. The law raises the credit to $1.00/gallon if the biodiesel is agri-biodiesel (produced from first-use oils)

    3. Taxpayers must secure certification for the biodiesel from the producer or importer to claim a credit. The biodiesel credit must be reduced by any excise tax credit claimed under Code Section 6426 or 6427(e). In general, if a credit is claimed and subsequently, any person separates the biodiesel or uses the mixture other than as a fuel there is a tax imposed on such person equal to the credit claimed.

    4. The provision is effective for fuel sold or used after December 31, 2004 and before January 1, 2007.

  2. House Bill Section 338, Primary Code Section 179B – Expensing of Capital Costs Incurred in Complying with Environmental Protection Agency Sulfur Regulations.

    1. The Act creates Code Section 179B – Deduction for Capital Costs Incurred in Complying with Environmental Protection Agency Sulfur Regulations. The provision permits small business refiners (a taxpayer in the business of refining petroleum products who employs less than 1,500 employees and has less than 205,000 barrels per day (average) of total refining capacity) to claim an immediate deduction for up to 75 percent of the qualified costs paid or incurred when complying with EPA’s highway diesel fuel sulfur control requirements. Qualified costs include expenditures for the construction of new process units or the dismantling and reconstruction of existing process units to be used in the production of low sulfur diesel fuel, associated adjacent or offsite equipment (including tankage, catalyst, and power supply), engineering, construction period interest, and sitework. The percentage of costs allowed is reduced for amounts in excess of 155,000 barrels a day of total refinery capacity.

    2. The provision is effective for expenses incurred after December 31, 2002. As a result, examiners will need to be alert for potential claims that may be filed for tax years ending after this date.

  3. House Bill Section 339, Primary Code Section 45H – Credit for Production of Low Sulfur Diesel Fuel

    1. The Act creates Code Section 45H – Credit for Production of Low Sulfur Diesel Fuel. The provision provides a general business credit to small business refiners equal to 5-cents for each gallon of low-sulfur diesel fuel produced during the taxable year that complies with EPA sulfur control requirements. The total production credit claimed by the taxpayer cannot exceed 25% of the qualified cost incurred to comply with the EPA’s highway diesel fuel sulfur control requirements. Basis in the property is reduced by the amount of credit claimed. To obtain the credit, the taxpayer will have to secure certification that the qualified costs will result in compliance with EPA regulations.

    2. The provision is effective for expenses incurred after December 31, 2002. As a result, examiners will need to be alert for potential claims that may be filed for tax years ending after this date.

  4. House Bill Section 341, Primary Code Section 45I – Oil and Gas from Marginal Wells

    1. The Act creates Code Section 45I – Credit for Producing Oil and Gas from Marginal Wells. The provision creates a new $3 per barrel credit for qualified crude oil production and 50 cents per 1,000 cubic feet of qualified natural gas production. The term qualified production means domestic crude oil or natural gas produced from a qualified marginal well. The credit is not available to production when the reference price of oil exceeds $18 and the price of natural gas exceeds $2. The credit is reduced proportionately as the reference price ranges between $15 and $18 for crude oil and $1.67 and $2 for natural gas. The credit will be treated as a general business credit. In case of production from a qualified marginal well which is eligible for the credit allowed under section 29, no credit shall be allowed under this section unless the taxpayer elects not to claim the section 29 credit with respect to the well.

    2. This credit is available for production in taxable years beginning after December 31, 2004. With the current price of crude oil and natural gas, this section will not have an immediate effect on examinations.

  5. House Bill Section 706, Primary Code Section 168 – Certain Alaska Natural Gas Pipeline Property Treated as 7-Year Property

    1. This provision amends Section 168(e) (3) (C) (defining 7-year property) to include any Alaska natural gas pipeline. The term ‘Alaska natural gas pipeline’ includes the pipe, trunk line, related equipment, and appurtenances used to carry natural gas (but does not include any gas processing plant) located in the State of Alaska which has a capacity of 500 trillion BTU of natural gas per day and is placed in service after December 31, 2013. If the system is placed in service prior to January 1, 2014, the taxpayer may elect to treat the system as placed in service on January 1, 2014 to qualify for the 7-year recovery period. (If placed in service prior to January 1, 2014 and the election is not made, taxpayer would have a 15-year recovery period. If elected, depreciation would not begin until after 2013.)

    2. This incentive provision is effective for property placed in service after December 31, 2004. Examiners should not see any effects of this provision in the near future.

  6. House Bill Section 707, Primary Code Section, Primary Code Section 43 – Extension of Enhanced Oil Recovery Credit to Certain Alaska Facilities

    1. This provision amends Code Section 43(c)(1) (defining qualified enhanced oil recovery costs) by adding any amount paid or incurred during the taxable year to construct a gas treatment plant capable of processing two trillion BTU of Alaskan Natural Gas per day into a natural gas pipeline system. To qualify, the gas treatment plant must also produce carbon dioxide for re-injection into a producing oil or gas field.

    2. This incentive provision is effective for property placed in service after December 31, 2004. Examiners should not see any effects of this provision in the near future.

Exhibit 4.41.1-29  (02-19-2008)
Energy Policy Act of 2005 Income Tax Provisions

The President signed into law the Energy Policy Act of 2005 (HR 6) on August 8, 2005. Income tax provisions affecting the domestic petroleum industry are summarized below:

  1. House Bill Section 1323. Temporary expensing for equipment used in refining of liquid fuels - Primary Code Section 179C.

    1. Under present law, petroleum refining assets are depreciated over a 10-year recovery period using the double declining balance method.

    2. The new provision provides a temporary election to expense 50% of the cost of qualified refinery investments. Any cost so treated is allowed as a deduction for the taxable year in which the qualified refinery property is placed in service. The remaining 50% is recovered under present law.

    3. Qualified refinery property includes assets, located in the United States, used in the refining of liquid fuels:

      • the original use commences with the taxpayer and is placed in ser-vice before January 1, 2012;

      • which meets all applicable environmental laws in effect on the date such portion was placed in service;

      • which increase the capacity of an existing refinery by at least 5 percent or increase the throughput of qualified fuels (as defined in section 45K(c)) by at least 25%.

      • with the respect to the construction of which there is a binding contract before January 1, 2008 (Note: in the case of self-constructed property, the construction of which began after June 14, 2005, and before January 1, 2008).

    4. The five percent capacity requirement refers to the output capacity of the refinery, as measured by the volume of finished products other than as-phalt and lube oil, rather than input capacity as measured by rated capacity.

    5. The expensing election is not available with respect to identifiable refinery property built solely to comply with Federally mandated projects or consent decrees. For example, a taxpayer may not elect to expense the cost of a scrubber, even if the scrubber is installed as part of a larger project, if the scrubber does not increase throughput or increased capacity to accommodate qualified fuels and is necessary for the refinery to comply with the Clean Air Act. This exclusion applies regardless of whether the mandate or consent decree addresses environmental concerns with respect to the refinery itself or the refined fuels.

    6. As a condition of eligibility for the expensing of equipment used in the refining of liquid fuels, the provision provides that a refinery must report to the IRS concerning its refinery operations, (e.g. production and output).

    7. Effective Date: The provision is effective for property placed in service after August 8, 2005, the original use of which begins with the taxpayer, provided the property was not subject to a binding contract for construction on or before June 14, 2005.

  2. House Bill Section 1325. Natural gas distribution lines treated as 15-year property - Primary Code Section 168 (e)(3)(E)(viii)

    1. Gas distribution lines must be depreciated over 20 years under present law.

    2. The new legislation establishes a statutory 15-year recovery period and a class life of 35 years for distribution lines put in service after April 11, 2005. The provision amended Code Section 168(e)(3) to allow 15-year treatment to any natural gas distribution line the original use of which occurred after April 11, 2005 and before January 1, 2011. The provision does not apply to any property which the taxpayer or related party had entered into a binding contract for the construction thereof or self-constructed on or before April 11, 2005.

    3. Property not meeting the qualified criteria would continue to be depreciated over 20 years.

    4. Effective Date: Effective for property, the original use of which begins with the taxpayer after April 11, 2005, which is placed in service after April 11, 2005 and before January 1, 2011. The provision does not apply to property subject to a binding contract on or before April 11, 2005.

  3. House Bill Section 1326. Natural gas gathering lines treated as 7-year property - Primary Code Section 168(e)(3)(C)(iv).

    1. The uncertainty regarding the appropriate recovery period of natural gas gathering lines has resulted in litigation between taxpayers and the Service.

    2. The new legislation establishes a statutory seven-year recovery period and a class life of 14 years for natural gas gathering lines. In addition, no adjustment will be made to the allowable amount of depreciation with respect to this property for purposes of computing a taxpayer’s alternative minimum taxable income. The provision does not apply to any property which the taxpayer or related party had entered into a binding contract for the construction thereof on or before April 11, 2005, or in the case of self-constructed property, has stated construction on or before such date.

    3. A natural gas gathering line is defined to include any pipe, equipment, and appurtenance that is:

      1. determined to be a gathering line by the Federal Energy Regulatory Commission, or

      2. used to deliver natural gas from the wellhead or a common point to the point at which such gas first reaches:

        • a gas processing plant,

        • an interconnection with an interstate transmission line,

        • an interconnection with an intrastate transmission line,

        • a direct interconnection with a local distribution company, a gas storage facility, or an industrial consumer.

    4. Effective Date: Amendments made by this section shall apply to any natural gas gathering line the original use of which commences with the taxpayer and placed in service after April 11, 2005.

  4. House Bill Section 1328. Determination of small refiner exception to oil depletion deduction - Primary Code Section 613A(d)(4).

    1. Oil and gas producers are classified as either independent producers or integrated companies. A producer is an independent producer only if its refining and retail operations are relatively small. Under present law an independent producer may not have refining operations the runs from which exceeded 50,000 barrels on any day in the taxable year during which independent producer status is claimed. A refinery run is the volume of inputs of crude oil (excluding any product derived from the oil) into the refining stream.

    2. The bill increases the current 50,000-barrel per day limitation to 75,000. In addition, the bill changes the refinery limitation claiming independent status from a limit based on actual production to a limit based on average daily production for the taxable year. Accordingly, the average daily refinery runs for the year may not exceed 75,000 barrels. For this purpose, the taxpayer calculates average daily refinery runs by dividing total refinery runs for the taxable year by the total number of days in the taxable year.

    3. Effective Date: This provision is effective for taxable years ending after August 8, 2005.

  5. House Bill Section 1329. Amortization of geological and geophysical expenditures - Primary Code Section 167(h).

    1. Courts have held that geological and geophysical expenditures (G & G costs) are capital, and therefore are allocable to the cost of the property acquired or retained. Revenue Rulings 77-188 and 83-105 provided further guidance regarding the definition and proper tax treatment of G & G costs.

    2. The new legislation allows geological and geophysical costs amounts in connection with oil and gas exploration in the United States to be amortized over two years. In the case of abandoned property, the remaining G & G basis may no longer be recovered in the year of abandonment of a property as all G & G basis is recovered over the two-year amortization period.

    3. G & G costs incurred prior to August 8, 2005 are not covered in this provision. The provision also does not cover foreign G & G costs. These costs will continue to be capitalized and allocated to the property acquired or retained.

    4. Effective Date: The provision is effective for geological and geophysical costs paid or incurred in taxable years beginning after August 8, 2005.

  6. House Bill Section 1346. Renewable Diesel - Primary Code Section 40A.

    1. The Act amends Code Section 40A (relating to biodiesel used as fuel) by extending its provisions to renewable diesel. It provides for an income tax credit reportable as a General Business Credit for renewable diesel used as a fuel in a trade or business, or sold at retail to another person and put in the fuel tank of that person’s vehicle. Renewable diesel will be treated in the same manner as biodiesel except that:

      • the rate of credit with respect to renewable diesel will be $1.00 per gallon sold or used rather than 50 cents.

      • Subsections (b)(3) and (b)(5) in regard to agri-biodiesel shall not apply.

    2. Biodiesel is an alternative to petroleum-based diesel fuel and is made from renewable resources such as vegetable oils or animal fats. Biodiesel contains no petroleum but can be blended with petroleum diesel into a biodiesel blend. A common fuel blend would be 20% biodiesel/80% petroleum diesel.

    3. The term "renewable diesel" means diesel fuel derived from biomass or any product thereof using a thermal depolymerization process which meets EPA and the American Society of Testing and Materials requirements.

    4. The term ‘"biomass" means any organic material other than oil and natural gas (or any product thereof) and coal (including lignite) or any product thereof.

    5. Thermal depolymerization (TDP) is a process for the reduction of complex organic materials (usually waste products of various sorts, often known as biomass) into light crude oil.

    6. Effective Date: The effective date for this amendment shall apply with respect to fuel sold or used after December 31, 2005 and before December 31, 2008.

Exhibit 4.41.1-30  (02-19-2008)
Tax Increase Prevention and Reconciliation Act (TIPRA) Income Tax Provisions

The President signed HR 4297, Tax Increase Prevention and Reconciliation Act of 2005 (P.L. 109-222), on May 17, 2006. The income tax provision affecting the domestic petroleum industry is summarized below:

  1. TIPRA Code Section 503: 5-Year Amortization on Geological and Geophysical Expenditures for Certain Major Integrated Oil Companies

    1. Primary Code Section dealing with this provision is 167(h). The provision extends the two-year amortization period for G & G costs to five years for certain major integrated oil companies. It applies only to integrated oil companies that have an average daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, gross receipts in excess of $1 billion in the last taxable year ending during calendar year 2005, and an ownership interest in a crude oil refiner of 15 percent or more.

Exhibit 4.41.1-31  (02-19-2008)
Tax Relief And Health Care Act of 2006 Income Tax Provisions

The President signed into law the Tax Relief And Health Care Act of 2006 (HR 6111), on December 20, 2006. Income tax provisions affecting the domestic petroleum industry are summarized below:

  1. Sec. 118, Primary Code Section 613A – Taxable Income Limit on Percentage Depletion for Oil and Natural Gas Produced From Marginal Properties

    1. The provision extends for two years the present-law taxable income limitation suspension provision for marginal production (through taxable years beginning on or before December 31, 2007).

    2. The provision applies to taxable years beginning after December 31, 2005.

    .


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