Petroleum Industry Overview Series - Complete Version - December 2008
Date: December 2008
"This document is not an official pronouncement of the law or the position of the Service and cannot be used, or cited, or relied upon as such."
Table of Contents:
A. Purpose of Industry Overview
B. The LMSB Intranet
C. General History of Industry Specialization Program (ISP)
D. History of Petroleum ISP
E. Industry Specialist Staffing (Technical Advisors in LMSB)
F. LMSB Industry Staffing
A. Federal Requirements
B. State Requirements
C. Local Requirements
A. Coordinated Issues
B. Emerging or Other Significant Issues
C. Recent or Pending Legislation
D. Specific Industry Related Tax Law
E. Important Revenue Rulings or Revenue Procedures
F. Important Court Cases
G. Technical Advice Memorandums - Field Service Advices
A. Trade Associations / WEB Sites
B. IRS and Other Training Courses/Videotapes
C. Trade Magazines and Newsletters
D. Industry Books
E. Internal Revenue Manual Citations
F. AICPA Auditing Standards and Publications
G. Audit Techniques Guides
This overview is designed to provide industry-related information to all Large and Mid-Size Business (LMSB). This is the first step in the effort of LMSB to develop a greater level of expertise in the industry or industries to which you will be assigned. This overview is one of a series of industry specific overviews. See the Appendix for a complete listing of available overviews.
Each Technical Advisor has established a web site on the LMSB Intranet. These web sites contain more detailed information on each Technical Advisor area. Topics that have been included in this Industry Guide are sometimes expanded upon and new topics may be added. Each web site also has a “Hot Topics” section where Technical Advisors can highlight the latest developments such as new court cases, new technical advice memorandums, new revenue rulings, etc.
|1952||The Service was restructured in 1952 into a highly decentralized organization consisting of seven regions and 58 districts. This reorganization was implemented in part to achieve greater sensitivity and responsiveness to pubic needs. District Directors were given wide latitude and authority in administering the Service's policies, procedures and programs. While decentralization of the Service proved to be a progressive action, communication between the regions and districts was made more difficult because of their quasi‑autonomy. Positions taken by the Service on industry issues could differ significantly from one region to another on the same issues.|
|1971||The Service implemented the Industry Wide Examination Program to concurrently examine the major taxpayers in a given industry, coordinate selected issues common to that industry and to resolve those issues uniformly and consistently among all the industry taxpayers. Under the direction of project coordinators (usually large case branch chiefs), the industry wide examinations were largely successful in achieving uniform and consistent treatment of issues. Industry wide examinations were conducted in several industries between 1971 and 1979 and the ability to communicate freely across district and regional lines proved to be invaluable to the success of these examinations.|
|1977||The Industry wide Examination Program had one major drawback. Since they existed for only two or three tax years and were then terminated, the program failed to provide continuity. To correct this situation, a major study group was created in 1977 to review the Service's Coordinated Examination Program. The study recommended that permanent positions be established for several Industry Specialists and a National Industry Coordinator. In addition, the study group identified basic industries to which it recommended specialists be assigned. The duties and responsibilities of the Specialists and the Coordinator were to be much broader than the former Project Coordinators whom they replaced.|
|1979||The recommendations of the study group were implemented greatly expanding the scope and depth of the Industry wide Examination Program. The term, Industry Specialization Program, eventually evolved as a name that could encompass the varied concepts of Industry Specialists, National Industry Coordinator, Coordinated Issues, and the many refinements suggested by the study group.|
|2000||As part of the Internal Revenue Service’s restructuring, the Industry Specialists were assigned to Pre-Filing and Technical Guidance which is part of LMSB, Headquarters. The “Industry Specialists” are now called Technical Advisors. Each of them was placed in one of the five industry areas and is managed by a Technical Advisor Manager.|
|Oil Pricing Program formed in Southwest Region|
|Delegation Order 153 Issued for Southwest Regional Commissioner on Crude Oil pricing|
|Petroleum Industry Program (PIP) formed in Southwest Region. PIP combines the oil pricing program and the Petroleum Industry Specialization Program.|
|Delegation Order 153 revised to include LMSB Director, Natural Resources|
|IRM rewritten to allow International Examiners to work Controlled Issues on behalf of the NRC Director|
|Name of Specialist||
F. LMSB Industry Staffing
|Keith Jones||Industry Director||Houston, Texas|
|Emile Robertson||Director, Field Operations-East||Houston, Texas|
|Katheryn Houston||Director, Field Operations-West||Houston, Texas|
|John Eiman||Petroleum Industry Counsel||Houston, Texas|
|David Carter||Technical Advisor Manager||Atlanta, Georgia|
Petroleum has a colorful history filled with colorful people. It has been a cyclical history full of booms and busts; all of them magnified by the huge scale of the fortunes won and lost.
Edwin Drake drilled the first commercial oil well in Oil Creek, Pennsylvania in 1859. Its production was considered staggering at the time, and the amount of kerosene it could produce changed the lamp oil market. The early history of the industry was a free for all as people rushed into the infant industry. In exploration, the lack of knowledge about geology caused great confusion. Some entrepreneurs found oil in the most unlikely places based on the most unlikely methods. Others used the most rational approaches but went broke.
Oil trading, refining, and sales also was chaotic. Products were not refined to uniform standards so using and storing petroleum fuels was dangerous. Even when they were safe, their performance was unpredictable. Government regulations did not exist. Competing companies seldom agreed upon product standards. Crude oil prices dropped precipitously when large new fields were found and soared when shortages were rumored. In that day of unbridled capitalism, sales tactics included everything imaginable, including many which would be criminal today.
One person saw this chaos and saw through it to the opportunities the new industry offered, if only order could be brought to it. John D. Rockefeller began investing in oil refining in Cleveland in 1863 and within nine years controlled 21 of the 26 refineries in Cleveland.
He saw that he could control the industry by controlling refining. Like the other industrialists of that era, he sought to integrate and control all phases of the business, eliminating wasteful duplication (and competition) in the process. He expanded his hold on refining as he expanded to other cities and states. He bought out his competitors then expanded into production, transportation, and marketing, consolidating his control over each one.
Rockefeller insisted that his products be made to specific standards that the public could depend on, and he proudly named his company the Standard Oil Company. The public preferred reliable products and his empire grew, eventually controlling 90 percent of oil refining in the United States by 1890
The Sherman Anti-Trust Act and federal litigation eventually broke up Rockefeller’s control of the industry, but by the time it did Standard Oil monopolized virtually every facet of the industry, from searching for crude oil to home delivery of kerosene
When the Standard Oil Company was broken up in 1911, it was broken into regional companies which remained vertically integrated but which the Rockefellers were forbidden to exercise control of. Those companies began competing with each other and expanding into each other’s territories. Today the ones that remain operate virtually worldwide. They no longer monopolize regions, but they are still vertically integrated.
As the big oil companies expanded beyond the United States, however, they found a different environment.
In the United States, every landowner controlled the minerals under his property. Every single one of them could drill oil wells if he wanted to. The refining industry, however, required specialized knowledge and a lot of money to build a refinery large enough to be efficient enough to be profitable. Only large corporations could do that.
In other countries, the rulers or governments controlled access to the minerals. Compared to the number of corporations in the world large enough to build a refinery, there were only a few rulers and governments. The control point for the international industry was thus crude production, not refining. For many years the seven largest international oil companies (the “Seven Sisters”) – five of them American -- controlled the world’s supply of crude oil by negotiating market share among themselves and by balancing production among the countries which had surplus oil to export.
In October 1972, though, this delicate balancing mechanism broke.
The principal exporting countries in the Middle East had been gaining wealth, power, and expertise from the enormous royalties they had been collecting since the first half of the 1900s. First, they formed the Organization of Petroleum Exporting Countries (OPEC) and began formally consulting each other on oil prices and policies. Several countries had tried to take control of their production and oil sales away from the Seven Sisters in the 1940s and 1950s, but they could not sell enough of their production to avoid severe economic problems. During 1970 and 1971, OPEC negotiated price increases with the Seven Sisters but was still not able to take control of their production.
In 1972, Libya dramatically nationalized its oil fields, took control of its own production, raised its prices, and was able to find its own buyers. The Seven Sisters’ reign was over. The other major exporters quickly followed Libya, and over the next few years, the Seven Sisters were reduced to being customers of the producing nations.
Since Libya broke the hold of the Seven Sisters, the concentration of power in the oil industry has continued ebbing. The national oil companies of the major exporting countries have been growing more vertically integrated, investing their profits from production in expanding into refining, transportation, and marketing.
The Western oil companies, meanwhile, have been retrenching, specializing in some functions and areas and giving others up. They continue to grow and be profitable, but the domination of the industry by the largest companies keeps ebbing. As this has happened, the large Western oil companies have been expanding into other areas such as chemicals, plastics, convenience store marketing, coal, and other energy sources.
Mergers, acquisitions and joint ventures continue in the petroleum industry at a record pace. Mergers are motivated by industry official’s desires to achieve synergies (benefits from the combined strengths of different companies), diversify their assets, reduce costs, enhance stock values, and respond to price volatility. According to a report issued by the GAO in May 2004, over 2,600 merger transactions have occurred since the 1990’s involving all three segments of the petroleum industry. Almost 85 percent of the mergers occurred in the upstream segment (exploration and production), while the downstream segment (refining and marketing of petroleum) accounted for about 13 percent, and the midstream segment, specifically pipelines (transportation), accounted for over 2 percent. The vast majority of the mergers—about 80 percent—involved one company’s purchase of a segment or asset of another company, while about 20 percent involved the acquisition of one company’s total assets by another so that the two became one company. Most of the mergers occurred in the second half of the decade, including those involving large partially or fully vertically integrated companies.
Many petroleum companies plan to expand exploration activities in the deepwaters of the Gulf of Mexico as drilling technology under difficult deepwater conditions continues to improve.
Market trends and fiscal policies to attract oil investment are causing the industry to invest an even greater proportion of limited exploration dollars outside the U.S. At the same time, there is a trend of greater ownership of U.S. refinery and downstream assets by foreign companies, including national government-owned companies. The potential impact of these trends on tax administration is great and includes questions of pricing (including foreign to foreign), income sourcing, and proper determination of extraction and non-extraction income. With the support from examiners and specialists in the field, the Petroleum Industry Program will continue to study changing market trends and develop positions for reasonable tax administration.
Definition or Explanation
|Abandonment Costs:||Once production from an oil or gas well becomes unprofitable it 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.|
|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.|
|Acquisition Well||A well drilled for a mineral interest in a property.|
|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 within the year. The payment is recoupable out of the future production.|
|AFE||Authorization for expenditures.|
|AFRA||Average Freight Rate Assessments. A measure of the cost of sea transportation incurred on crude oil and products.|
|Allowables||Most oil producing states have regulatory agencies, which 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 permitted within a given period. This may be stated in terms of producing days or a percentage of full production and is usually figured on the basis of the individual well. Thus, 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|
|API||American Petroleum Institute.|
|API Well Number||A 12 digit number assigned to every US well. The 12 numbers represent State (1-2),County/Parish (3-5) Well (6-10), Specific Conditions (11-12)|
|Area of Interest||The original project area which is then 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.|
|Assignment of Lease||A legal document transferring all or a portion of the operating rights of a lease.|
|Barrel (BBL)||A standard measure of volume for crude oil and liquid petroleum products; barrel means 42 U.S. gallons|
|BCF||Billion Cubic Feet (of gas)|
|BOE||Barrel of oil Equivalent. The amount of energy produced by gas usually equated as approximately six MCF of gas to one barrel of oil (i.e. “6:1”)|
A clean burning alternative fuel produced from renewable resources.
Biodiesal contains no petroleum but it may be blended with petroleum.
|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 they can be used for clean fuels|
|Bonus||The consideration received by the lessor or sublessor upon execution of an oil or gas lease.|
|Bottom-Hole Contribution||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|
|British Thermal Unit (BTU)||A measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit|
|Carried Interest||A fractional interest in an oil or gas property, most often a lease. Its holder has no obligation for operating costs. The owner or owners of the remaining fraction who reimburse themselves out of profits from production pay these. The person paying the costs is the carrying party, the other person is the carried party|
|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 160 acre tract owned|
|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 and those arising in leasing transactions, production payments are treated as loans|
|Casing||Steel pipe placed in an oil or gas well. Its main function is to prevent the well walls from caving and to protect the well bore and in-hole equipment. It also prevents oil from migrating into other porous zones.|
|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 the well as a dry hole.|
|Casinghead Gas||Gas produced from an oil well. The casinghead gas is usually taken off at a gas/oil separator.|
|Catalyst||A substance which affects, provokes, or accelerates chemical reactions without being altered itself|
|Catalytic Cracking||A method of cracking in which a catalyst is employed to bring about the desired chemical reaction|
|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|
|Christmas Tree||An assembly of valves mounted on the casinghead through which a well 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.|
|Coke||The carbon residue left in the still after a charge of reduced crude has been run to dryness.|
|Common Carrier||Any cargo transportation system that may be accessed by any appropriate shipper and each shipper is charged the same rate schedule. Many pipelines are common carriers|
|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|
|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.|
|Compression or Compressor||The act of boosting the pressure of the natural gas flowing from a well so that the gas will go into the pipeline or gathering system. Accomplished by using compressors, which are large machines located on the surface.|
|Condensate||A light hydrocarbon liquid, which is in a gaseous state in the reservoir, but which becomes liquid when temperature and pressure, is reduced.|
|Contiguous Property||Tracts which have common boundary. Tracts that touch only at a common corner are not contiguous.|
|Continuing Interest||An economic interest in an oil or gas property which 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 that the economic life of one or more of the properties which it burdens. See Treas. Reg. § 1.636-3(a) for definition of production payment.|
|COPAS||Council of Petroleum Accountants Society of North America.|
|Cracking||The refinery process of breaking down the larger, heavier, and more complex hydrocarbon molecules into simpler and lighter molecules.|
|Crude Oil||A mixture of hydrocarbons which 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.|
|D D & A||Depreciation, Depletion and Amortization|
|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.|
|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.|
|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 the lease becomes productive.|
|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.|
|Delineation Well||A well drilled to determine the boundaries of the field.|
|Depletion||Treas. Reg. § § 1.611 through 1.613A provide taxpayers with a deduction based upon the higher of an amount representing a portion of the cost of capital investment in the minerals in place (cost depletion) or a percentage of the gross receipts from the sale of the extracted minerals (percentage depletion).|
|Development Well||A well drilled for production in an area where proven reserves are located.|
|Discovery Well||The first oil or gas well drilled in a field revealing oil or gas deposits.|
|Distillation||This generally refers to vaporization processes in which the vapor evolved is recovered by condensation; and thus, a separation is effected between volatile fractions that vaporize at a specific temperature and those which do not.|
|Disposal Well||A well used for disposal of saltwater.|
|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.|
U.S. Department of Energy.
|DR&R||Dismantlement, Removal and Restoration. Generally what a lessee must perform to return a producing property to a condition suitable to the lessor. Can include such items as well plugging, equipment removal and soil remediation. Publicly traded companies must estimate these costs for financial accounting purposes, although they are often just included in a footnote.|
|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.|
|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.|
|Dry Gas||Natural gas composed of vapors with only small amounts of dissolved liquid. Dry gas generally is composed almost 100 of methane (CH4 ).|
|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.|
|Dry-Hole Contributions||Money or property paid by property owners to another operator drilling a well on property in which the payers 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.|
|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|
|E-85||85 percent ethanol mixed with 15 percent gasoline.|
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" is found in Treas. Reg. § 1.611-(b) 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).
|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.|
|Ethanol||A form of alcohol that some can be commercially produced from agricultural products, such as corn. In recent years blended with gasoline in major metropolitan areas to help reduce air pollution.|
|Excess IDC||Intangible drilling cost (IDC) paid or incurred in connection with producing wells, less the amount which 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 § 57(a)(2|
|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|
|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.|
|Expired Leases||A lease which is no longer in force due to either an expiration of a time limit or nonpayment of rentals.|
|Exploration Rights||Permission granted by landowners allowing others to enter upon their property for the purposes of conducting geological or geophysical surveys.|
|Exploratory Well||A well drilled in a nonproductive area in search of oil or gas deposits. Sometimes it is called a wildcat well.|
|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 transferor frequently retains some interest.|
|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.|
|Federal Energy Regulatory Commission (FERC):||The U.S. Agency which regulates interstate natural gas and oil pipelines|
|Feedstock||Crude oil or other hydrocarbons that are the basic input to a refinery, petrochemical plant, or intermediate processing units|
|Fee Interest||The ownership of both surface and mineral rights.|
|Field Price||Posted price of oil taken from a specific field.|
|Flow Line||Surface pipe through which oil or gas is pumped or flowed from the well to either processing equipment or storage facilities|
|Footage Drilling Contract||A well drilling contract which provides for payment at a specified price per foot for drilling to a certain depth|
|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 and gas wells; or, taxable income from the sale or exchange of assets used by the taxpayer in the business of extracting minerals from oil and gas wells.|
|Foreign Oil Related Income (FORI):||
|FPSO||Floating Production Storage and Offloading. A vessel that resembles both a barge and a tanker ship and which contains equipment that can convert the raw flow from wells into pipeline quality crude oil and natural gas. Unlike an offshore platform, wells are not located on an FPSO.|
|Fracturing||A fluid, usually oil, is forced through the perforations in the casings into the formation. This fluid enters the formation under high pressure and breaks it or fractures it. This allows the oil and gas, which is in the formation, to more easily enter the well.|
|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.|
|Gas Payment||A production payment payable out of gas.|
|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.|
|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 (e.g. 40). Heavy oils have a low API gravity (e.g. 20).|
|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 is usually the actual sales price. 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. § 1.613-3(a).|
|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.|
|Horizontal Well||A well that starts off being drilled vertically but which is eventually curved to become horizontal (or near horizontal) in order to parallel a particular geologic formation.|
|Hydrocarbon||Any of the compounds made up exclusively of hydrogen and carbon in various ratios.|
|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.|
|Hydroforming||A special catalytic hydrogen reforming process employed for upgrading straight run gasolines|
|Independent Producers and Royalty Owners Exemption||An exemption from the denial of percentage depletion provided in IRC § 613A(a). This exemption is provided in IRC § 613A(c) and is based on average daily production of oil and/or gas. Independent producers are defined in IRC § 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. This figured was changed to an average of 75,000 barrels per day for tax years ending after August 8, 2005. See page 37.|
|Injection or Input Well:||A well used to inject natural gas, water, carbon dioxide, LPG'S, or other foreign substances under pressure into a producing formation to maintain sufficient pressure to produce the recoverable reserves.|
|Intangible Drilling and Development Costs (IDC)||Those expenditures which do not have a salvage value and which are incurred in the drilling and deepening of an oil and gas well.|
|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.|
|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.|
|IPAA||Independent Petroleum Association of America|
|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 temperature and pressures.|
|Jobber||A buyer of oil products from refiners for resale to retail outlets.|
|Joint Operating Agreement||
|Lease Agreement||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.|
|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.|
|Lease Bonus||Consideration paid by the lessee to the lessor for executing the lease.|
|Leasehold Costs||Costs of acquiring and holding a lease.|
|Lifting costs||Costs of operating wells for the production of oil and gas (producing costs).|
|LNG||Liquefied 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.|
|Marginal Production||Domestic crude oil or natural gas which 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 § 613A(c)(6)(E).|
|Marginal Wells||A well of such low producing capacity that the profitability of future production is marginal.|
|MCF||Thousand cubic feet. The standard unit for natural gas volumes.|
|Mineral Deed||A lease instrument which conveys an interest in minerals on or under a tract of land.|
|Mineral Interests (Mineral Rights):||The ownership of the minerals and the right to remove them from the property.|
|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.|
|MMBTU||Million British Thermal Units. The measure of heat energy. The standard unit used in pricing natural gas.|
|MMCF||Million cubic feet.|
|MODU||Mobil Offshore Drilling Unit. A generic term for several classes of self-contained floatable or floating drilling machines such as jackups, semi submersibles, and submersibles.|
|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 which were carried to the surface by the mud.|
|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.|
|Natural Gas||Any hydrocarbon product (other than crude oil) of an oil or gas well if a deduction for depletion is allowable under IRC § 611 with respect to such product. Specifically natural gas refers to any hydrocarbon gas.|
|Natural Gas Liquids:||Natural gas liquids are the heavier hydrocarbon liquids produced along with natural gas, including butane, propane, natural gasoline and ethane.|
|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 § 613A(b)(3)(A).
|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.|
|Nonoperating Interest||An economic interest, which does not meet the definition of operating interest as, defined in Treas. Reg. § 1.614-2(b). A royalty, overriding royalty, or net profits interest is a nonoperating interest.|
|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).|
|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.|
|Offshore Platform||A structure from which serves as a base for drilling and producing wells in an offshore area. Such platforms can be rigidly fixed to the seabed with legs or float while held in location by anchors and/or cables.|
|Oil Payment||A production payment payable from oil.|
|Oil or Gas Property||Each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land.|
|Oil Shale||Generally refers to a sedimentary rock that contains solid, combustible organic matter in a mineral matrix. The organic matter, often called kerogen, is largely insoluble in petroleum solvents, but decomposes to yield oil when heated.|
|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 IRC § 614(d) and Treas. Reg. § 1.614-2(b).|
|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.|
|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.|
|Participation Agreement||An agreement between two or more parties to share in the cost and production of a well.|
|Payout||Recovery from the net proceeds of production of the entire cost of drilling, completing, and equipping a well.|
|Perforating||The piercing of the casing wall and cement to provide holes through which the hydrocarbons may enter the well bore.|
|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 See IRC §§ 613 and 613A and Treas. Reg. § 1.613-1(a).|
|Petrochemicals||Chemicals derived from petroleum feedstocks for the manufacture of a variety of plastics, synthetic rubber, etc.|
|Petroleum||A complex mixture of hydrocarbons with small quantities of other materials, such as sulphur (usually combined), nitrogen compounds, water, and silica.|
|Pool of Capital||Under this theory, 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.|
|Pooling||The term is used to denominate 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.|
|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).|
|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).|
|Primary Production||Oil production, which is recovered through the use of the natural energy source in the reservoir. Also called primary recovery|
|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.|
One who owns an economic interest in a well that produces oil or gas.
|Production Payment:||A share of the minerals produced from a lease, free of the cost of production, which, 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.|
|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.|
|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|
|Property||Each separate interest owned by a taxpayer in each mineral deposit in each separate tract or parcel of land. See IRC § 614(a) and Treas. Reg. § 1.614-8.|
|Pumping Unit||Sometimes referred to as a pump jack. Normally consists of an electric or gas motor that causes an elevated walking beam to reciprocate up and down.|
|Recompletion||A specialized kind of workover that normally results in the well producing from a different geologic formation or interval than before.|
|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.|
|Recoverable Reserves||The total recoverable units (e.g., barrels or thousands of cubic feet) of 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 page 21 for discussion on elective safe harbor allowed by Revenue Procedure 2004-19 for computation of recoverable reserves.)|
|Reforming||A catalytic process for converting low octane number naphthas or gasolines into high octane number products.|
|Regeneration||In catalytic cracking, removal of carbon from the catalyst in order to make it suitable for reuse.|
|Reservoir||A porous, permeable sedimentary rock containing commercial quantities of oil or gas.|
|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.|
|Retained Interest||A special nonoperating interest retained by the lessor when the lessor transfers the responsibilities for developing the property to another party.|
|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.|
|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.|
|Run Ticket||Evidence of receipt or delivery of oil issued by a pipeline or other carrier or purchaser.|
|SAE Viscosity||An arbitrary system for classifying motor oils according to their viscosities established by the Society of Automotive Engineers.|
|Wells used for disposal of saltwater that is produced along with oil or gas.|
|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 or another substance to drive the recoverable oil to producing wells.|
|Seismic Survey||Geophysical information on subsurface rock formations gathered by means of a seismograph.|
|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|
|Severance Taxes||See Production taxes.|
|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.|
|Shooting Rights||The right to make a geological survey on land.|
|Shut-in Wells||A producing well that has been closed down temporarily, or one that was never connected to a pipeline because of a very remote location.|
|Sidetrack||A secondary wellbore drilled away from the original hole. It is possible to have multiple sidetracks, each of which might be drilled for a different reason.|
|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.|
|Spud||To start the actual drilling of a well.|
|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|
|Stripper Well Property||A property where the average domestic crude oil and domestic natural gas produced during a calendar year divided by the number of such wells is 15 barrels or less.|
|Sweet Oil or Gas||Crude oil or natural gas which contains little or no sulphur or hydrogen sulfide.|
|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.|
|Tank Battery||Two or more tanks connected together on a property to store oil production prior to sale and/or removal.|
|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.|
|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|
|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.|
|Three Dimensional Seismic||A set of numerous closely-spaced seismic lines that provide a large amount data regarding the contours of subsurface geological layers. The resultant data set can be accurately viewed in any direction. 3D seismic data allows the construction of subsurface maps that are more accurate than those based on more widely spaced 2D seismic lines.|
|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|
|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|
|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.|
|Turnkey Well||A completed well, drilled and equipped by a contractor for a fixed price.|
|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 recovery programs.|
|Unit of Production Method||A method used to calculate depletion, depreciation, or amortization based upon quantities produced in relation to expected ultimate recovery of oil and/or gas. See Treas. Reg. § 1.611-2(a) for a description of the calculation for depletion of oil and/or gas wells.|
|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.|
|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 that readily vaporizes at comparatively low temperatures.|
|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.|
|Wellhead||Equipment used to maintain surface control of a well. See Christmas Tree.|
|Wildcat Well||A well drilled in an unproved area, far from a producing well; an exploratory well in the truest sense.|
|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.|
|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.|
|Yield||In petroleum refining, the percentage of product or intermediate fractions based on the amount charged to the processing operation.|
The link between financial accounting and tax accounting is the Schedule M-3 of the Corporate Income Tax Return, Form 1120. Examples of expenses that should be reviewed due to differences between financial and tax accounting includes:
Depletion (cost vs. percentage, tax basis vs. book basis)
Financial Product Transactions (Hedging, Interest Swaps, Gains/Losses, etc.)
Geological and Geophysical Expense
Indirect and Direct Costs Capitalized (Sec. 263A)
Intangible Drilling Cost
Interest Expense Capitalized (Sec. 263A)
Writedowns of Asset Values. FAS 121
The petroleum industry is generally divided into two broad segments: 1) Exploration and Production (the “upstream” segment) and 2) Transportation, Refining, and Marketing (the “downstream” segment). Some companies have both segments, and are known as “integrated companies”.
The Exploration and Production segment of the petroleum industry follows two methods for financial reporting: 1) the Successful Efforts Method, and 2) the Full Cost Method. The Successful Efforts method expenses all costs of exploring for and developing oil and gas properties except for those that are commercially successful. Successful oil and gas development is capitalized and amortized on a units of production basis (similar to cost depletion). The Full Cost Method capitalizes all of the costs of property acquisition, exploration, and development costs, even dry holes. These costs are then amortized on a units of production basis on a country-by-country basis (again, very similar to cost depletion).
Accounting for the downstream segment of the industry (transportation, refining and retailing) various among companies but is comparable to similar businesses outside of the oil industry.
The industry has made strides in developing systems which capture, sort, summarize, and store well-level information and fully integrating such information with the revenue, joint interest billing, accounts receivable, accounts payable, land lease records, and general ledger systems. Some of the companies which provide such software include (but are not limited to): Allegro Development, Andersen Consulting, Artesia, Inc., Avatar Systems, Oracle Energy, Paradigm Technologies, Petroware Systems Inc, PriceWaterHouseCoopers, Questa Software Systems, and SAP. SAP, in particular, has been embraced by several of the major oil companies.
The following operations are used in bringing the oil and gas to market:
Production Phase: Operations that deal with bringing the oil and gas to the surface and preparing them for transportation to the refinery or processing plant.
Transportation: Operations that deal with moving the oil and gas from the field to the refinery or processing plant. Transportation vehicles include inland barges, railway tank cars, transport trucks, oceangoing tankers, crude oil and products pipelines, and gas transmission pipelines.
Refining/Processing: Converting crude oil and gas in their raw state to marketable products. Oil refineries typically produce motor fuels, heating oil, lubricating oils, waxes, asphalt, and coke. Gas processing plants typically produce natural gas for end-user consumption and natural gas products such as propane, butane and LPG. Petrochemical plants typically produce base plastics.
Distribution System: Operations include storage and handling, transportation, and delivery to the end user. End users for motor fuels can be terminals, company owned service stations and other branded outlets, and independent middlemen (jobbers). Natural gas is usually distributed to end users by local distribution companies.
Petroleum companies have the same general regulatory filing requirements as most other corporations.
Publicly held petroleum companies are required to file with the Securities and Exchange Commissions. The reports include 8-K, 10-K, and other reports required by the SEC.
States require petroleum companies, which are operating in their state to file reports with the appropriate agency. The agency varies from state to state. For example in Texas, the Texas State Railroad Commission regulates petroleum companies.
Many localities require reporting by petroleum companies, especially in the area of environmental matters.
|Issue||Brief Summary of Issue|
|Estimated Dismantling and Removal Costs (pre-§ 461(h))||
Issue was decoordinated on May 5, 2008. See memo below:
May 5, 2008
FROM: Frank Y. Ng /s/ Frank Y. Ng
SUBJECT: Decoordination of Issue for Petroleum Industry: Estimated Dismantling and Removal Cost
The decoordination of the issue of Estimated Dismantling and Removal Cost has been approved effective the date of this memorandum.
In 1984, Congress enacted IRC Section 461(h) which added the economic performance test to the all events test of section 461. This change effectively eliminated this issue in regards to liabilities arising after July 18, 1984. For pre-461(h) examination years, the Appeals Settlement Guidelines allowed taxpayers to amortize over 25-years the estimated dismantling and removal costs relating to jacket-type platforms located in the Gulf of Mexico or along the coast of California in less than 500 feet of water. The Coordinated Issue Paper (CIP) was kept primarily to track this settlement on affected taxpayers’ subsequent years.
On August 31, 2007, Appeals decoordinated this issue due to no activity. There has been no examination activity on this issue in recent history. While a potential issue might exist when a taxpayer disposes of pre-461(h) assets, the current CIP has no effect on the correct resolution of the issue. Accordingly, this issue is being decoordinated. However, it should be noted that the decoordination of this issue does not result in a change in the Service’s position, but merely removes it from the formal coordination process.
If you have any questions, please contact me, or a member of your staff may contact Ken Telchik, Petroleum Technical Advisor, at (972) 308-1582.
|Cost Depletion – Recoverable Reserves||
Issue # 1: Whether a taxpayer is required to include in the original reserve estimate proved undeveloped and probable reserve categories in the total number of recoverable units for the purpose of computing cost depletion under IRC § 611(a).
IRS Position: Proved developed, proved undeveloped, and “probable and prospective” reserves are regularly estimated using methods current in the industry. For purposes of computing cost depletion, the taxpayer is required to include all recoverable units of minerals in the total number of recoverable units at the end of the year. Recoverable units include both proven reserves (developed and undeveloped) and, under appropriate circumstances, additional reserves.
Issue # 2: Whether a taxpayer is permitted to revise the original reserve estimate based solely on changes in economic factors.
IRS Position: For purposes of cost depletion, the taxpayer is not permitted to revise its reserve estimate based solely on changes in economic factors, without operations or development work indicating the physical existence of a materially different quantity of reserves than originally estimated to purchase the property or develop the property.
Recent Litigation: Martin Marietta Corp. v. United States, 7 Cl. Ct. 586, 85-1 USTC 9284 (Cl. Ct. 1985)
Status: Appeals settlement guidelines approved February 27, 2008.
On March 8, 2004, Revenue Procedure 2004-19 was issued. The revenue procedure provides an elective safe harbor that the owner of domestic oil and/or gas properties may use in determining the property’s recoverable reserves for purposes of computing cost depletion under § 611 of the Internal Revenue Code. The safe harbor allows taxpayers and the Service to avoid complex factual arguments over what constitutes the appropriate quantity of probable or prospective reserves for purposes of computing cost depletion. Under the safe harbor, the Internal Revenue Service will not disturb a taxpayer’s estimate of an oil and/or gas property’s total recoverable units where that estimate is equal to 105 percent of the property’s proved reserves as defined in the Security and Exchange Commission Regulations (17 C.F.R. section 210.4-10(a) of Regulation S-X) remaining as of the taxable year.
When a taxpayer does not elect to use the safe harbor provided in Rev. Proc. 2004-19 for all of its domestic oil and gas properties, examiners should follow the Petroleum Industry Coordinated Issue Paper on Cost Depletion - Recoverable Reserves dated January 13, 1997.
For taxable years ending prior to March 8, 2004, examiners should request assistance of the Petroleum Industry Technical Advisors in resolving the issue. See NRC Field Directive on Cost Depletion - Determination of Recoverable Reserves.
Issue # 1: What is the meaning of “minority interest” as used in the North Sea IDC transition rule?
IRS Position: Although the transition rule does not define “minority,” income tax regulations promulgated for other purposes have defined that term to mean an interest of less than 50%. See section 1.332-5 of the Income Tax Regulations (“Distributions in liquidation as affecting minority interests”) and section 1.337-5 of the regulations (“Special rules for certain minority shareholders’). There is no suggestion that Congress intended to have a different meaning than this usual one.
Issue # 2: When is a minority interest for development acquired for purposes of the North Sea IDC transition rule?
IRS Position: The transition rule requires that a United States company acquire a minority interest in a North Sea development license on or before December 31, 1985. A minority interest in a North Sea development “license” is established when specific authority to develop the offshore production license is obtained from the appropriate governmental agency.
Issue # 3: Does the transition rule override the amendments to IRC § 291(b) made by the TRA, so that the change from mandatory capitalization of 20 % of intangible drilling costs (“IDC”) over 36 months to capitalization of 30% of IDC over 60 months would not apply to foreign IDC described in the transition rule?
IRS Position: The transition rule overrides the amendments to I.R.C. 291(b) made by the TRA. A company meeting the transition rule may continue to capitalize 20% of its foreign IDC over 36 months.
Status: Appeals settlement guidelines approved April 2, 2002.
|Capitalization of Delay Rentals||
Issue: Whether delay rentals paid or incurred under an oil and gas lease are subject to capitalization under IRC § 263A as costs of producing property?
IRS Position: For tax years beginning after December 31, 1993, delay rentals incurred under an oil and gas lease are required to be capitalized to the depletable basis of the property to which they relate pursuant to IRC § 263A if the lease is held for development or if development of the lease is reasonably likely at some future date. A taxpayer that performs geological and geophysical surveys (G&G) on acquired leaseholds or files a plan of development with an appropriate governmental agency has demonstrated an unequivocal intention to develop the leasehold in the future. Even in the absence of such unequivocal steps, it can be presumed that taxpayers in the business of producing oil and gas acquire leasehold interests with the intent to develop them. Therefore, unless the taxpayer can establish by credible evidence that the leasehold was acquired for some reason other than development, the taxpayer must capitalize the delay rentals incurred with respect to that leasehold.
IRC § 263A, its legislative history and the temporary regulations all indicate that carrying charges, such as delay rentals, are subject to capitalization under IRC § 263A. Accordingly, it is not reasonable for taxpayers/lessees to rely on Treas. Reg. § 1.612-3. See Proposed Regulation (REG-103882-99) that would conform the regulations on delay rental to the requirements of IRC § 263A.
For tax years beginning before January 1, 1994, a taxpayer must take a “reasonable position” on its federal income tax return when applying IRC § 263A to delay rentals. Some examples of reasonable positions include (1) capitalizing delay rentals on leaseholds that the taxpayer (i) had a plan to produce, (i.e., to develop) or (ii) acquired and thereafter gathered G&G data and (2) capitalizing delay rentals on leaseholds in amounts equal to the taxpayer’s historical percentage of actual leasehold development. In any event, capitalization of zero delay rentals is not a reasonable position. See TAM 9602002, which holds that deducting delay rentals is not a reasonable position under the temporary regulations.
Recent Litigation: John J. Reichel v. Commissioner, 112 T.C. No. 2, No. 23143-97 (January 7, 1999) and Von-Lusk v. Commissioner, 104 T.C. 207 (1995)
Status: Appeals settlement guidelines were approved April 2, 2003. Successful settlements have been reached at the examination level with little examination time expended by using Delegation Order 4-25 procedures. It is recommended you contact Terry Loendorf, Petroleum Industry Technical Advisor, at 972-308-1578, to request implementation of this delegation order.
Underground Storage Tanks at Gasoline Retail Locations
Issue: Whether the costs incurred to (i) remove and replace underground storage tanks, (ii) clean-up soil contaminated by releases from the tanks, and (iii) install monitoring systems, wells, or other equipment associated with groundwater clean-up are capital expenditures under IRC §§ 263(a) and 263A or currently deductible under IRC § 162?
IRS Position: Costs incurred to remove and replace underground storage tanks are capital expenditures under IRC §§ 263(a) and 263A. These costs must be capitalized to the basis of the new tank. Costs incurred to remove underground storage tanks and remediate the soil, in cases where the tanks will not be replaced, are deductible under IRC § 162, where the costs are incurred by the same taxpayer that contaminated the property. This does not apply in cases where the costs are incurred to adapt the property to a new or different use.
Costs incurred to clean-up the soil are deductible as business expenses under IRC § 162, where such costs are incurred by the taxpayer who contaminated the property.
Costs of installing monitoring systems, wells, or other equipment associated with the remediation and clean-up of the contaminated area, including direct and allocable indirect costs under IRC § 263A, must be capitalized to the basis of the equipment. These costs may be recovered over the appropriate period determined under IRC § 168.
See Revenue Ruling 2000-7, 2000-9 IRB 1 (February 8, 2000) The Service ruled that the costs of removing an asset to replace it does not have to be capitalized under IRC § 263(a) or 263A as part of the cost of the replacement asset. The Service cautioned, however, that its analysis did not apply to the removal of a component of a depreciable asset, the costs of which are either deductible or capitalized based on whether replacement of the component is a repair or improvement.
Status: The coordinated issue paper was revised to conclude that the underground storage tank is a part of the fuel distribution system and not a separate asset for depreciation purposes. As a component of the fuel distribution system, the removal costs of the underground storage tanks are not within the scope of Rev. Rul. 2000-7 and are capital improvements.
Appeals settlement guidelines are pending.
|Issue||Brief Summary of Issue|
|Above Ground Storage Tanks||
Issue: Should above ground storage tanks (ASTs), used for marketing petroleum products and placed in service after 1986, be depreciated over 15 years under MACRS asset class 57.1 (inherently permanent property), or should they be depreciated over 5 years under MACRS asset class 57.0 (tangible personal property)?
Many petroleum company taxpayers have petroleum product storage tanks located at bulk plant terminal facilities and other locations. Petroleum products are held in those tanks for distribution to the taxpayer’s customers or to the taxpayer’s retail outlets. Petroleum products must be stored during the distribution process, and steel above ground storage tanks play a major role in such storage. Field-erected tanks are generally large in size and built to remain in one location. Shop-built tanks are shipped to the site for installation. Taxpayers claim above ground storage tanks should be depreciated over 5 years under MACRS asset class 57.0.
Three asset classes of Rev. Proc. 87‑56 are pertinent in classifying a taxpayer's storage tanks. The asset classes include the business activities set out in (i) asset class 57.0, "Distributive Trades and Services,” ( ii ) asset class 57.1, "Distributive Trades and Services . . . Petroleum Land Improvements,” and, (iii) asset class 00.3, ”Land Improvements," a specific asset class.
Asset class 57.0 includes assets used in wholesale and retail trade, and personal and professional services. It also includes IRC § 1245 assets used in marketing petroleum and petroleum products. In pertinent part, asset class 57.1 includes depreciable land improvements, whether IRC § 1245 property or IRC § 1250 property, used in the marketing of petroleum and petroleum products. It excludes all other land improvements.
Asset class 00.3 includes improvements directly to or added to land, whether such improvements are IRC § 1245 property or IRC § 1250 property, provided such improvements are depreciable. However, that asset class does not include land improvements that are explicitly included in any other class. Because assets used in the marketing of petroleum or petroleum products are included within assets classes 57.0 or 57.1, they cannot be included within asset class 00.3.
Status: In a recent decision (PDV America Inc., et al. v. Commissioner, T.C. Memo. 2004-118) (United States Tax Court), Tax Court Judge L. Paige Marvel held that the above ground storage tanks of CITGO Petroleum Corp. were not permanent structures, according to the six-factor test of Whiteco Indus. v. Commissioner, 65 T.C. 664 (1975), and are in MACRS asset class 57.0 and treated as five-year property under section 168 (e) (1). It is recommended that you contact the Petroleum Technical Advisors prior to working this issue.
|Reclassifying Refinery Assets as Chemical Assets||
An oil refinery converts crude oil into products, which it then distributes and markets.
Taxpayers assert that certain refinery plant assets should not be classified as MACRS Guideline Class 13.3 relating to refining for depreciation purposes. Taxpayer argues that the assets at issue are not used in “refining crude petroleum into gasoline or the components of crude petroleum.” They claim these assets fall under MACRS Guideline Class 28.0 relating to the manufacture of chemical products.
Assets used in the following processes are those claimed to be chemical assets:
On April 8, 2002, a LMSB Field Directive on MACRSs Asset Categories for Refining Assets was issued. It is recommended that examiners take the following positions:
The Directive was exemplified in Technical Advice Memorandum (TAM) 200629031 issued on March 10, 2006. The Service ruled in the TAM that process units used to produce gasoline and other products of crude petroleum were properly included in the asset class 13.3 petroleum refining because all the units were integral parts of a highly integrated refinery. The TAM stated in part:
In terms of the functional use of any one of the Units, the product(s) of the Unit and the use of the product(s) determine whether the asset is used in Petroleum Refining activity or Manufacture of Chemical activity. Applying this use-driven functional standard, the Units were dedicated to producing gasoline and other petroleum products and were an integral part of this function. At Facility, Taxpayer was engaged in only this industrial activity; thus, its primary and only use was the production of gasoline and other petroleum products.
|LIFO Inventory – Definition of an “Item”||
This is the primary LIFO inventory issue being pursued by examiners of petroleum companies. Substantially all petroleum companies account for crude oil as one item. They also account for each grade of gasoline as one item.
The National Office has issued ruling letters relating to item definition of gasoline requiring the taxpayers to account for each grade and major type of gasoline they manufacture as a separate item. In some cases, a taxpayer many have as many as 25 different grade types.
While there has been acceptance of the definitions for gasoline, taxpayers raised a number of concerns regarding defining separate crude oil items. For instance, by virtue of the fact that crude oil is a naturally occurring substance composed of a variety of hydrocarbon molecules rather than a substance which is man-made and produced according to a precise formula, the API gravity and sulfur content of crude oil even within the same field of origin are not necessarily uniform throughout the field. Also, in addition to the variations in the physical characteristics of crude oil occurring within one field, crude oil sold under a particular commercial name is often itself a mixture of crude oils from two or more separate fields. A Crude Oil Study prepared by the Petroleum Industry Program provided a classification system that allowed for the grouping of like-kind crude oils of similar API and sulfur content. The National Office has issued ruling letters allowing taxpayers to “group” grades of crude oil into categories by API and sulfur content. The groupings are separated into 10 API categories and 5 sulfur content categories. Although there are 50 potential item categories, taxpayers generally have well under 50 that actually apply.
|Section 43 – Enhanced Oil Recovery Credit||
Section 43 of the Internal Revenue Code provides an enhanced oil recovery (EOR) credit equal to 15 percent of the qualified costs paid or incurred by the taxpayer in regards to qualified EOR projects. Qualified projects must employ certain types of tertiary recovery methods and be reasonably expected to result in an increased recovery of crude oil. The projects must be located in the United States and have commenced after December 31, 1990. The types of costs which will qualify for the EOR tax credit generally consist of:
Two major issues have arisen to date – the “significant expansion issue” and the “tertiary injectant costs issue”.
A significant expansion is meant to relate to a reservoir volume that was not being affected by the EOR project already in existence at the beginning of 1991. The EOR credit is meant to apply to projects that were “new” as of 1991 or for the ‘significant expansion” of EOR projects that were already in existence at that time. Issues are being raised when it appears that the qualified costs are applicable to projects in existence at December 31, 1990 that did not result in a significant expansion to the reservoir volume. TAM 103300-05 (issued as PLR 200535028 on May 5, 2005) addressed this issue.
Tertiary injectant expenses include costs related to the use of a tertiary injectant, as well as expenditures related to the acquisition of the injectant. However, qualified tertiary injectant expenses do not include costs that a taxpayer paid or incurred in the development or operation of mineral property if an enhanced oil recovery project had not been implemented with respect to the property. Nor does it include costs related to the use of a tertiary injectant that are also related to other activities, such as primary and secondary recovery. These related costs must be reasonably allocated among the tertiary injectant and other activities to determine the amount of tertiary injectant expenses paid or incurred by the taxpayer on the qualified project. See Revenue Ruling 2003-82. Issues are being raised when it appears taxpayers are not making this reasonable allocation to primary and secondary recovery activities.
Additional guidance on the EOR credit is available in section 126.96.36.199.4 of the IRM Oil and Gas Handbook.
The EOR tax credit was designated as a Tier II issue, and the Industry Director for Natural Resources and Construction issued a directive on May 7, 2007 for examiners to follow.
|Dealer Incentive / Image Upgrade||
Most major oil companies have image upgrade programs which reimburse independently owned gasoline stations for certain approved expenditures. In most cases, these expenditures are for upgrading the independents' facilities so that they meet the majors' image and appearance standards. The majors commonly reimburse the independents for costs incurred in purchasing equipment, making building improvements, and purchasing advertising, uniforms, and signs.
Under most image upgrade programs, an independent operator enters into a marketing contract for 3 to 8 years or agrees to buy a certain quantity of gasoline. The largest reimbursements generally go to those independents which purchase the largest volumes of gasoline.
There are two issues regarding image upgrade payments: (1) whether the payers should capitalize and amortize the payments; and (2) whether the recipients should include the payments in income. The argument for capitalization by payers is straightforward. The payers make the payments to the independent retailers in order to increase revenue by upgrading the retail facilities. This upgrading has the effect of stimulating sales by encouraging old customers to continue to patronize a major's brand and attracting new customers. The enhanced marketability represents an intangible asset which can reasonably be expected to have value extending beyond the taxable year. Furthermore, there is usually a direct connection between the obligation to make image upgrade payments and the signing of a long-term marketing contract.
On the second issue, I.R.C § 61 defines gross income as all income from whatever source derived, unless excluded by law. Many recipients take the position that the image upgrade reimbursements are excludible from income because they are loans. This is premised on the fact that many of the image upgrade agreements call for repayment of the reimbursements if a recipient fails to buy a certain quantity of gasoline. The Tax Court rejected this theory in Colombo v. Commissioner, T.C. Memo. 1975-162. The Service also concluded in TAM 9308001 (Nov. 9, 1992) that the reimbursements constitute taxable income.
In the recently tried Erickson Post Acquisition, Inc. v. Commissioner, T.C. Memo. 2003-218 (July 22, 2003), the Tax Court held that a gas station corporation received a loan and not deferred compensation, and that the loan wasn't includable in the corporation's income.
The Service thinks that the Tax Court erred in finding that the $ 175,000 payment to petitioner was a loan. In form, the parties did cast the transaction as a loan.: Amoco and the petitioner executed a note secured by a duly recorded mortgage. However, the evidence strongly suggests that the payment was not really a loan in substance. To constitute a loan, at the time an amount is transferred, the recipient must intend to repay the amount and the transferor must intend to enforce repayment. Beaver v. Commissioner, 55 T.C. 85, 91 (1970). The record establishes that neither the petitioner nor Amoco expected that the money would be repaid. Petitioner treated the advance as deferred income, not a loan, for both book and tax purposes. Petitioner characterized the advance as a loan only after the Service challenged deferral. If the advance had been a true loan, petitioner would have deducted interest and reported forgiveness of debt income once a year on its book and returns.
The Service considers the opinion in Karns Prime & Fancy Foods, Ltd. vs. Commissioner, T.C. Memo. 2005-233, the better analysis. On facts very similar to this case, the court focused on the substance of the transaction and found it an advance payment of income. Karns is consistent with the analysis in other cases addressing the loan versus advance payment issue. See Westpac Pacific Foods v. Commissioner, T.C. Memo. 2001-175, and Columbo v. Commissioner, T.C. Memo. 1975-162. (The Westpac decision was reversed by the 9th Circuit Court of Appeals. Counsel is currently reviewing the decision.)
Status Update: In an action on decision, the IRS recommended a Non-acquiescence, No Appeal. The Service disagreed with the holding in Erickson Post but did not appeal because it was essentially a factual determination. However, the Service will continue to litigate this issue in cases where taxpayers attempt to avoid tax by characterizing payments or business services as nontaxable loans.
Issue: Whether gas gathering pipeline system assets should be classified, for depreciation purposes, under MACRS class life 46.0, Pipeline Transportation, or MACRS asset class life 13.2, Exploration for and Production of Petroleum and Natural Gas Deposits?
Asset Class 13.2, Exploration & Production of Petroleum and Natural Gas (7- year life), includes gathering pipelines and related storage facilities used by petroleum and natural gas producers to drill wells or produce gas.
Asset Class 46.0, Pipeline Transportation(15-year life) includes assets used in the private, commercial, and contract carrying of petroleum, gas, and other products by means of pipes and conveyors.
In Duke Energy Natural Gas v. Commissioner, 172 F.3d 1255 (10th Cir. 1999), rev’g 109 T.C. 416 (1997), the Tenth Circuit held that natural gas “gathering systems” are property includible in asset class 13.2 and must be depreciated over a 7-year period.
In Saginaw Bay Pipeline Company, 338 F.3d 600 (6th Cir. 2003), rev’g and rem’g 124 F. Supp. 2d 465 (E.D. Mich. 2001) the 6th Circuit Court of Appeals ruled that a company's underground natural gas pipelines should be depreciated over a seven-year period as a gathering pipeline, even though the pipeline owners aren't producers of natural gas.
This was followed by the 8th Circuit Court of Appeals decision in Clajon Gas Company LP., v. Commissioner, 354 F.3d 786 (8th Cir. 2004), rev’g 119 T.C. 197 (2002) that Clajon primarily used the gathering system in a manner that falls within the description of asset class 13.2. The court stated Clajon’s use was primarily for gathering pipelines and that asset class 13.2 provision's language did not require that the producer be the owner of the gathering system assets.
The uncertainty regarding the appropriate recovery period of natural gas gathering lines resulting from the above litigation was settled by the enactment of the Energy Policy Act of 2005, House Bill Section 1326 – Natural gas gathering lines treated as 7-year property. (Primary Code Section 168(e)(3)(C)(iv).
The new legislation established a statutory seven-year recovery period and a class life of 14 years for natural gas gathering lines the original use of which commenced with the taxpayer and placed in service after April 11, 2005. In addition, new qualified gathering lines were not subject to alternative minimum tax.
A natural gas gathering line was 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. a gas processing plant,
b. an interconnection with an interstate transmission line,
c. an interconnection with an intrastate transmission line,
d. a direct interconnection with a local distribution company, a gas storage facility, or an industrial consumer.
Status: Gas gathering pipeline system assets should be classified, for depreciation purposes, as MACRS asset class life 13.2, Exploration for and Production of Petroleum and Natural Gas Deposits, and depreciated over 7-years. The Technical Advisors recommend that examiners continue to verify that the alternative minimum tax computation on gathering lines placed in service prior to April 11, 2005 is being correctly computed.
Geological and Geophysical Cost
The major tax issue regarding exploration cost in the oil and gas business is whether such cost is ordinary and necessary business expense or capital in nature. Generally, the distinction between capital expenditures and business expenses is made by looking to the extent and permanency of the benefit derived from the outlay. That is, an expenditure is considered capital in nature if it is for permanent improvements or betterment that increases the value of the property. (Sec. 263(a) and Reg. Sec. 1.263(a)-1) Geological and geophysical exploration expenditures are made for the objective of acquiring and collecting information that will serve as a basis for the acquisition and retention of properties for purposes of oil and gas recovery or to reject an area as unworthy of development.
In recent years, there has been a steady shift in geophysical activity from conventional exploration to the development of known reservoirs. This shift has been caused by advancements in 3D and 4D technology. Taxpayers have begun to classify certain G&G costs as intangible drilling costs relating to either 1) determining the location to set an offshore producing platform and/or 2) determining well-site locations. This is currently one of the most contested areas between the Service and taxpayers. Although there is a broad difference from taxpayer to taxpayer on when it is proper to treat G&G as IDC, an aggressive interpretation is that all G&G acquired subsequent to obtaining the lease should be treated as IDC. Generally, the Service requires that the G&G project is tied to a specific well or wells and that the determination to drill such well must have been made prior to the G&G project for such project to qualify for IDC. If the project were of such scope as to delineate the entire structure, the Service generally would hold that the project was more in the nature of exploration and capitalize the costs to the leasehold account.
Prior to the enactment of new energy legislation noted below, the IRS position on geological and geophysical expenditures was Rev. Ruls. 77-188 and 83-105.
The Energy Policy Act of 2005 now permits G&G cost incurred in the United States to be amortized ratably over 24 months. This 24-month amortization provision applies to all domestic exploration cost paid or incurred for tax years beginning after August 8, 2005. If the property is abandoned, the remaining unamortized G&G must continue with its original 24-month amortization and cannot be expensed in the year of abandonment. For all foreign exploration costs and those domestic exploration costs incurred in tax years beginning prior to August 8, 2005, the tax rules for handling G&G continue to be set forth in Revenue Rulings 77-188 and 83-105.
The G&G deduction for major integrated oil companies was further amended by the Tax Prevention and Reconciliation Act signed on May 17, 2006. Major integrated oil companies are required to substitute 5 years for the 24 month amortization period. A major integrated oil companies is described as a producer of crude oil
|Intangible Drilling And Development Costs incurred by non operators||
Issue: Whether amounts deducted by an individual on Schedule C or by a partnership for intangible drilling and development costs (IDC) under § 263(c) of the Internal Revenue Code qualify to be currently deducted
Two factual patterns have emerged. First an individual is solicited to participate in an oil and gas venture. Typically the individual has no prior oil and gas experience. The materials from the promoter indicate the promoter has oil and or gas wells that they wish to develop. In exchange for contributing to the wells, the individual can claim an IDC deduction and at some point, an interest in the wells will be transferred to them. The individual sends a check to the promoter of the investment.
A review of the facts indicates that prior to the time of investment the wells had already been drilled by the promoter.
In the second pattern an individual is solicited and invests cash into a partnership. That is formed to acquire and drill oil and gas wells.
A review of the facts indicates that prior to the time of investment the wells had already been drilled by the promoter.
Treasury Reg. § 1.612-4 permits an "operator" (one who holds a working or other operating interest in an oil and gas property) to elect to deduct intangible drilling and development costs ("IDC") in the case of oil and gas wells, in lieu of capitalizing such costs.
The taxpayer must hold the interest when the IDC is incurred in order to elect to take a deduction. In these patterns the wells were already drilled and thus the IDC had already been incurred.
See Revenue Ruling 75-304.
U.S. taxpayers producing oil and gas outside the U.S. have been required since 1975 to characterize income as Foreign Oil and Gas Extraction (FOGEI) or Foreign Oil Related Income (FORI), and allocate foreign income taxes between these income sources. The Tax Reduction Act of 1975 enacted Code section 907 and the FOGEI/FORI allocation requirement.
FOGEI includes taxable income or loss derived from sources outside the U.S. and its possessions from the extraction of minerals from oil and gas wells, and the disposition of assets used by a taxpayer in the trade or business of extracting these minerals. FOGEI is defined as the fair market value of the oil or gas in the vicinity of the well. FORI includes taxable income or loss from the processing of oil or gas into their primary products, from the transportation or distribution and sale of oil and gas and their primary products, and from the disposition of assets used in these activities.
Section 907 was enacted to combat a theoretically simple problem. Supposedly, the oil industry was generating excess foreign tax credits on FOGEI activities because foreign governments were disguising royalty payments as taxes. In drafting section 907, Congress was concerned with taxpayers’ ability to cover U.S. tax on other foreign activities (FORI and other Non-Oil Related Income (NORI)) normally taxed at a lower rate, with the high taxes on FOGEI. Consequently, a special limitation on the amount of oil extraction taxes that could be claimed against U.S. tax was enacted. Section 907(a) seeks to prevent the excess foreign taxes on FOGEI from offsetting U.S. tax on other foreign source income. The limitation imposed by section 907(a) is the maximum U.S. tax rate applied to a taxpayer’s FOGEI. Since the limitation applies only to foreign taxes paid on extraction activities and not other oil related activities, the determination of FOGEI is important.
Since the enactment of Section 907 in 1975 Congress has made changes to section 907, but the statutory demarcation of FOGEI as taxable income from extraction and FORI as taxable income from processing, transportation and distribution has remained constant.
The separate limitation imposed by section 907(a) on the use of FOGEI taxes causes petroleum taxpayers to seek tax-planning opportunities to reduce the impact of this separate limitation. All planning opportunities used by a taxpayer would have at their core a desire to move income and taxes out of FOGEI or to lower the effective tax rate on FOGEI. These tax-planning opportunities can take a number of forms including:
Allocation To Transportation Income
An extraction or production company will allocate its income and taxes between FOGEI and FORI to recognize the income contribution from the transportation of crude oil from the wellhead (a FOGEI activity) to a port or distribution location (a FORI activity). This planning opportunity is desirable if the effective tax rate in the foreign country is high. The allocation of income and taxes to FORI removes this highly taxed income from the impact of the separate section 907(a) limitation.
Unlike oil and gas production in the U.S., oil and gas produced overseas often must travel some distance through pipelines to a port or distribution facility. The foreign government will establish a price for the oil and gas extracted within their country for purposes of calculating taxes to be paid in that country. These prices are generally a port price that may not be comparable to the "fair market value" in the vicinity of the well.
In order to arrive at a price for determining FOGEI taxpayers will attempt to value the contribution of the pipeline or other transportation activity that moved the oil or gas from the wellhead to the port. This valuation may be made using various formulas that impute value to the transportation assets (proportionate profits, rate of return on assets, etc.). The valuation process used will be fact intensive, and the taxpayer must establish that the fair market value of the oil or gas in the vicinity of the well is different than the value at the port or distribution facility. Usually the taxpayer will value the transportation assets and merely netback to obtain the value of the oil or gas at the wellhead. A common sense reading of Section 907 and the applicable regulations indicates that the fair market value of the oil or gas should be determined first before trying to value the transportation element.
Low Taxed FOGEI
Taxpayers will look for FOGEI that is not taxed by a foreign government or taxed at a low effective tax rate. Through the identification of lightly taxed FOGEI an opportunity is presented to have this untaxed FOGEI absorb other FOGEI taxes on highly taxed income to minimize the impact of the section 907(a) limitation. In evaluating a taxpayer's classification of income as FOGEI attention should be paid to FOGEI that is not heavily taxed to ensure it has be correctly classified.
Allocation of Expenses
The allocation of expenses under regulation 1.861-8 provides an avenue to allocate expenses away from FOGEI to other classes of foreign income. If the allocation of expenses under regulation 1.861-8 is not performed correctly expenses that should be reducing FOGEI in the determination of taxable income can be shifted to reduce other foreign income thereby increasing FOGEI for U.S. tax purposes and lowering the effective foreign tax rate on this income.
Status: On October 12, 2004, Field Directive on IRC § 907 Evaluating Taxpayer Methods of Determining Foreign Oil and Gas Extraction Income (FOGEI) and Foreign Oil Related Income (FORI). This memorandum is intended to provide direction to effectively utilize resources in evaluating taxpayer methods of determining under IRC § 907 FOGEI and FORI income. Agents are encouraged to obtain a copy of this memorandum from www.irs.gov or request a copy from the Technical Advisors.
|IDC Deduction on Installation Costs of “Subsea Assets”||
Taxpayers are allowed to deduct Intangible Drilling Costs (IDC) even though they represent a capital investment. IDC is normally limited to items such as labor, rig time, and services to drill and complete a well or construct on offshore drilling platform. In recent years as producers have moved their offshore operations to deeper and deeper water depths, the use of subsea flowlines and umbilicals have become more common. These assets connect remote wells which have their wellhead (aka christmas tree) on the seabed to a host platform. Some taxpayers have been deducting as IDC the installation cost of these assets even though the well has already been drilled and completed, and is ready for its assigned purpose of producing oil and gas.
This issue is usually limited to large oil and gas companies due to the size of the expenditures involved in subsea operations. Due to the very technical nature of the issue, a referral should be made to obtain the assistance of an IRS petroleum engineers
Summary and Impact of Legislation
The President signed into law the American Jobs Creation Act of 2004 (P.L. 108-357), on October 22, 2004, and 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:
Effective for fuel sold or used after 12/31/04
AJCA § 302: Biodiesel Income Tax Credit
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 biodiesel blend. A common fuel blend would be 20% bodiesel/80% petroleum diesel.
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).
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.
For Expenses incurred after 12/31/02.
AJCA § 338: Expensing of Capital Costs Incurred in Complying with EPA regulations.
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.
Expenses Incurred After 12/31/02.
AJCA § 339: Credit for Production of Low Sulfur Diesel Fuel.
|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.|
For Production in Taxable Years beginning after 12/31/04.
AJCA § 341: Oil and Gas From Marginal Wells
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
Incentive Provision Effective for Property Placed In Service after 12/31/04.
AJCA § 706: Certain Alaska Natural Gas Pipeline Property Treated As 7-year Property.
|This provision amends Section 168(e) (3) (C) (defining 7-year property) to include any Alaskanatural 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.)|
Incentive Provision Effective For Costs Paid or Incurred after 12/31/04.
AJCA § 707: Extension of EOR Credit to Certain Alaska Facilities.
|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 Btus 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.|
Effective to Taxable Years Beginning After 12/31/03.
WFTRA § 314: Taxable Income Limit On % Depletion for Oil and Gas From Marginal Wells.
|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|
|The President signed into law the Energy Policy Act of 2005 (P.L. 109-58) on August 8, 2005. Income tax provisions affecting the domestic petroleum industry are summarized below:|
|Effective for Property Placed In Service After 8/8/2005.||EPA § 1323: Temporary Expensing for Equipment Used in Refining of Liquid Fuels||Primary Code Section 179C. 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.|
|Effective for Property Placed In Service After 4/11/2005.||EPA § 1325: Natural Gas Distribution Lines Treated as 15-year Property||Primary Code Section 168(e)(3)(E)(viii), The new legislation establishes a statutory 15-year recovery period (previously 20-years) and a class life of 35 years for distribution lines put in service after April 11, 2005.|
|Effective for Taxable Years Beginning After 8/8/2005.||EPA § 1326: Natural Gas Gathering Lines Treated as 7-year Property.||Primary Code Section 168(e)(3)(C)(iv). 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.|
|Effective for Taxable Years Ending After 8/8/2005.||EPA § 1328: Determination of Small Refiner Exception to Oil Depletion Deduction.||Primary Code Section 613A(d)(4). 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.|
|Effective for Costs Paid In Taxable Years Beginning After 8/8/2005.||EPA § 1329: Amortization of Geological & Geophysical Expenditures.||Primary Code Section 167 (h). 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.|
|Effective to Fuel Sold or Used After 12/31/2005 and before m,/31/2008,||EPA § 1346: Renewable Diesel.||Primary Code Section 40A. 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.|
|The President signed HR 4297, Tax Increase Prevention and Reconciliation Act (TIPRA) of 2005 (P.L. 109-222), on May 17, 2006. The income tax provision affecting the domestic petroleum industry is summarized below:|
|Effective on Amounts Paid After 5/17/2006.||
TIPRA § 503:
5-Year Amortization on Geological And Geophysical Expenditures for Certain Major Integrated Oil Companies.
|Primary Code Section 167(h). Extends the two-year amortization period for G&G costs to five years for certain major integrated oil companies. Applies only to integrated oil companies that have an avg. 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.|
|The President signed into law the Tax Relief And Health Care Act of 2006 (P.L. 109-342)) on December 20, 2006. Income tax provisions affecting the domestic petroleum industry are summarized below:|
|Effective to Taxable Years Beginning After 12./31/2005.||TRHC § 118: Taxable Income Limit on Percentage Depletion for Oil and Natural Gas Produced From Marginal Properties||Primary Code Section 613A. 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.|
|On December 19, 2007, the President signed into law the “Energy Independence and Security Act of 2007 (P.L. 110-140).” The income tax provision affecting the domestic petroleum industry is summarized below:|
|Effective for Amounts Paid or Incurred after 12/19/2007.||EISA § 1502: 7-year Amortization of G&G for Certain Major Integrated Oil Companies||
Under pre-Energy Act law, major integrated oil companies amortized their geological and geophysical expenditures over five years (instead of the 24 month period that applied for other taxpayers).
Effective for amounts paid or incurred after December 19, 2007, major integrated oil companies must amortize their geological and geophysical expenditures over seven years. (Code Sec. 167 (h) (5), as amended by Energy Act § 1502.) This provision applies only to integrated oil companies that have an avg. daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, gross receipts in excess of $1 billion for its last taxable year ending during calendar year 2005, and an ownership interest in a crude oil refiner of 15 percent or more. All other taxpayers will continue to amortize their geological and geophysical expense over a 24 month period.
|On December 29, 2007, the President signed into law the “Tax Technical Corrections Act of 2007 (TTCA) (P.L. 110-172).” The Act made technical and clerical corrections to certain provisions of the Internal Revenue Code of 1986. The amendment related to the American Jobs Creation Act of 2004 (AJCA) affecting the domestic petroleum industry is summarized below:|
Effective for Expenses Incurred After 12/31/02.
TTCA § 7: Interaction of rules relating to credit for low sulfur diesel fuel.
Small business refiners are allowed a tax credit for the production of low sulfur diesel fuel under Code Section 45H. Revenue Procedure 2007-69 outlines the procedure under which small business refiners may obtain from the Service a certification that satisfies the certification of the costs related to a production facility. (The TTCA redesigned the certification requirements from section 45H (f) to section 45H (e).)
Under AJCA Provision 339, Code Section 45H allowed a credit at the rate of 5 cents per gallon for low sulfur diesel fuel produced at certain small business refineries. The aggregate credit with respect to any qualifying refinery was limited to 25% of the costs of the type deductible under Code section 179B. Section 179B allowed a deduction for 75% of certain costs paid or incurred with respect to these refineries. The basis of the property was reduced by the amount of any credit determined with respect to any expenditure (sec. 45H (d). Further, no deduction was allowed for the expenses otherwise allowable as a deduction in the amount equal to the amount of credit under Code section 45H (sec. 280C (d).
TTCA amended provision 339. Under the TTCA, deductions are denied in an amount equal to the amount of credit under section 45H, and the provisions of the AJCA reducing basis and denying a deduction are repealed.
Taxpayers will need to file amended tax returns for prior returns affected by sections 179B and 45H to reflect the correct treatment.
Effective Date: The amendments are effective as if they had been originally included in the provisions of the American Jobs Creation Act of 2004 to which they relate.
Summary and Impact of Law
|Credit for Producing Fuel From A Nonconventional Source,|
|Enhanced Oil Recovery Credit|
|Intangible Drilling Costs|
|Geological and Geophysical expense needs to be capitalized. See Rev. Rul. 77-188 and 83-105.|
|Carrying charges, such as delay rentals, are subject to capitalization under IRC § 263A.|
|Allowance of deduction for depletion.|
|Basis for Cost Depletion|
|Limitations on Percentage Depletion in Case of Oil & Gas Wells|
|Definition of Property|
|Income Tax Treatment of Mineral Production Payments|
|Tax creditability of levies where dual capacity taxpayer has received a specific economic benefit, generally with regard to natural resources. Also, where tax laws modified for natural resources companies.|
Tax years begin after 12/31/82
|Determination of the amount and limitation of creditable taxes on income from foreign oil and gas extracted income (FOGEI).|
|Income of a foreign controlled corporation not deferred if foreign base company oil related income.|
Date Opinion Issued
Name of Court Case and Citation
Summary of Importance of Court Case
|June 16, 2008||Texaco, Inc. v. United States, 528 F.3d 703 (9th Cir. 2008)||Ninth Circuit followed Pennzoil-Quaker State appellate decision and concluded that payments made to Department of Energy for violations of crude oil pricing were barred from relief under section 1341 by the inventory exception of section 1341(b) (2).|
|Jan. 1, 2008||Pennzoil-Quaker State v. United States, 511 F.3d 1365 (Fed. Cir. 2008)||Federal Circuit reversed Court of Federal Claims and concluded that antitrust settlement payments were barred from relief under section 1341 by the inventory exception of section 1341(b)(2).|
October 28, 2004
|Pennzoil-Quaker State vs. Comm., 62 FED.Cl 689||
Court concluded that antitrust settlement payments satisfied the elements of § 1341(a) and not barred by the inventory exception.
Reversed on appeal. See case above.
May 12, 2004
|PDV America v. Commissioner, T.C. Memo 2004-118||Court held that above ground storage tanks were not inherently permanent structures and qualified as 5-year property under MACRS Asset Class 57.0 rather than as 15-year property under MACRS Asset Class 57.1. (See page 24 for status of issue.)|
Jan 12, 2004
|Clajon Gas Co., v. Comm.., 354 F3d 786||Eighth Circuit Court of Appeals reversed the Tax Court, 119 T.C. 197, and held that gathering systems were production assets, subject to a seven-year depreciation period.|
July 30, 2003
|Saginaw Bay Pipeline v. United States, 338 F.3d 600||Sixth Circuit Court of Appeals reversed the United States District Court for the Eastern District of Michigan ruling, 88 A.F.T.R.2d 2001-6019, and held that every natural gas pipeline which functions as a “gathering pipeline” in the methane gas production process by transporting raw natural gas from the field wellheads to a cleansing processing facility qualifies as a “gathering pipeline” subject to a seven-year life, irrespective of the primary business of the owner of that pipeline.|
|July 22, 2003||
Erickson Post Acquisition, Inc. v. Comm. TC Memo. 2003-218
|Tax Court held that advance from oil company was a loan, and not gross income to service station owner/operator. (See page 26 for explanation and status of issue. The Commissioner announced nonacquiescence in 2006-24 I.RB. 1039.|
|Mar. 10, 2003||Exxon Mobil v. United States, 253 F. Supp.2d 915 (N.D.Tex. 2003)||Percentage depletion was not allowed with regard to two natural gas contracts. The taxpayer failed to prove that the contracts would qualify as “fixed contracts.”|
|May 23, 2002||Iowa 80 Group v. United States, 203 F.Supp.2d 1058||The Court held that a “retail motor fuels outlet” could not encompass several buildings for purposes of § 168.|
Oct. 12, 2001
Shell Petroleum v. United States, 50 Fed.Cl. 524
|The Court held that Shell failed to show that they used enhanced oil recovery techniques prior to April 2, 1980, and the oil could not have been produced from tar sands under the § 29 tax credit.|
|Oct. 12, 2000||HB&R Inc. v. United States, 86 AFTR2d 2000-5383||A company is not liable for FICA tax withholding on any part of airline tickets provided employees for commuting between their work site and their homes.|
|May 3, 2000||
Exxon Mobil Corp. v. Commissioner, 114 T.C. 293 (2000)
|Estimated dismantlement, removal, and restoration (DRR) costs for oil production equipment in Prudhoe Bay is not fixed and determinable enough to be accruable under the all-events test of IRC §1.461-(a)(2).|
Dec. 2, 1999
|Exxon Corp. v. United States, 84 AFTR 2d ¶99-5588, 2000-1 USTC ¶50,116||Representative market or field price for oil transported away from premises before being sold may exceed actual sale price.|
Nov. 22, 1999
|AOD CC-1999-017||Service issued nonacquiescence to Duke Energy Natural Gas Corp. v. Commissioner, 172 F.3d 1255 (10th Cir., 1999)|
|Nov. 2,1999||Exxon Corp. v. Comm. 113 T.C. No. 24||U.K. Petroleum Revenue Tax ruled creditable because it was not paid for specific economic benefits.|
|Apr. 13, 1999||
Duke Energy Natural Gas Corporation v. Commissioner, 172 F.3d 1255 (10th Cir. 1999).
|The 10th Circuit Court of Appeals reversed the Tax Court decision , 119 TC 416, and ruled that gathering systems were assets used in exploration for and production of petroleum and natural gas deposits, and could be depreciated over seven years pursuant to Asset Class 13.2 under MACRS.|
|Apr.5, 1999||Texasgulf, Inc. v. U.S. Fed. Cl.,83 AFTR 2d 1784 CA2, affg. 107 TC 51, 84 AFTR 2d ¶99-5433, 99-2 USTC ¶50,915||Ontario Mining Tax ruled creditable because it satisfies the net income requirement of '901.|
Mar. 23, 1999
|True Oil Co. v. Comm., 83 AFTR2d Par. 99-537; No. 97-9029||The Tenth Circuit affirmed a Tax Court decision holding that a well-category determination under section 503 of the Natural Gas Policy Act of 1978 is a prerequisite to obtaining the IRC § 29(a) tax credit for gas produced from a tight formation.|
|May 21, 1998||Union Texas International Corporation v.Commissioner 110 TC 321.||The Tax Court recognized the agency relationship between two subsidiaries preserving the independent producer status of one of the subsidiaries.|
Mar. 11, 1998
|Amoco Corp. v. Commissioner, 138 F3rd 1139 (CA 7)||The 7th Circuit Court of Appeals ruled that Egyptian tax creditable since a compulsory tax not refunded and not a subsidy.|
Dec. 8, 1997
|Mary Herbel v. Commissioner, 80AFTR2d 97-5655 CA 5.||Take or pay settlement payment is income to the recipient in the year received.|
|Oct. 17, 1996||
Texaco Inc. et al. v Commissioner
98 F3d 825 (5th Cir. 1996)
|No IRC § 482 reallocation of crude oil pricing income for the “Aramco Advantage”. Saudi law controlled Texaco and Exxon Prices.|
July 27, 1993
|Phillips Petroleum Co. v. Commissioner, 101 T.C. 78 (1993),||Income from the sale of Alaskan liquefied natural gas to Japan was sourced as part foreign.|
|Feb. 6, 1992||Shell Oil Company v. Commissioner, 952 F.2d 885||Overhead must be allocated to (IDC) in capitalizing IDC and in calculating percentage depletion.|
|Dec. 31, 1975||Whiteco Indus. v. Comm., 65 T.C. 664.||Court held that outdoor advertising signs constitute ‘tangible personal property’ within the meaning of § 48(a) (1) (A).|
PLRs AND TAMs ARE ADDRESSED ONLY TO THE TAXPAYERS WHO REQUESTED THEM. FSAs ARE NOT BINDING ON EXAMINATION OR APPEALS, NOR ARE THEY FINAL DETERMINATIONS. FURTHERMORE, SECTION 6110(k)(3) PROVIDES THAT PLRs, TAMs, AND FSAs MAY NOT BE USED OR CITED AS PRECEDENT.
|Geological and Geophysical Cost|
|Source of interest under IRC § 864(e)|
The following Internet sites may be helpful in obtaining information regarding the Petroleum Industry:
American Petroleum Institute - This is the home page for the American Petroleum Institute (API). API is the major national trade association representing the entire petroleum industry: exploration and production, transportation, refining, and marketing. With headquarters in Washington, D.C., and petroleum councils in 33 states, it is a forum for all parts of the oil and natural gas industry to pursue priority public policy objectives and advance the interests of the industry.
Interstate Oil and Gas Compact Commission - The Interstate Oil and Gas Compact Commission is an organization of states which promotes conservation and efficient recovery of domestic oil and natural gas resources while protecting health, safety and the environment. The IOGCC web site provides articles on current events, links to state regulatory agencies, training information, and an index of publications and videos relevant to the petroleum industry
Natural Gas Supply Association. - The Natural Gas Supply Association represents U.S.-based producers and marketers of natural gas on issues that affect the natural gas industry, including the residential and industrial consumers who rely on the fuel for a myriad of purposes.
Texas Independent Producers and Royalty Owners Association - The Texas Independent Producers and Royalty Owners Association is committed to promoting the interests and welfare of independent oil and gas operators, working interest owners, royalty owners, and businesses which provide services for the energy industry. Specifically, TIPRO strives to provide its members with legislative and public representation, access to valuable information and opportunities to develop business relationships. The web site publishes TIPRO's current activities.
Offshore Technologies - This web site provides coverage of international and domestic offshore oil and gas projects, and links to companies, organizations, and conferences.
Oil.com Web Directory - This web site is a comprehensive news site for the oil and gas industry.
Other significant oil and gas industry web sites include the following:
These web sites contain information about the purpose of the society, current events, and links to other areas.
|Name of Site|
|American Association of Professional Landmen (AAPL)|
|American Institute of Chemical Engineers|
|Association of American State Geologists|
|Federal Energy Bar Association|
|Geological Society of America|
|International Association of Drilling Contractors (IADC)|
|Mineral Information Institute|
|Organization of Petroleum Exporting Countries|
|Orleans Geological Society|
|Permian Basin Geophysical Society|
|Permian Basin Landmen's Association|
|Rocky Mountain Mineral Law Foundation|
|Society of Exploration Geophysicists (SEG)|
|Society of Independent Professional Earth Scientists|
|Society of Petroleum Engineers (SPE)|
|Society of Professional Well Log Analysts|
|Society of Women Engineers|
|South Texas Geological Society|
|Texas Association of Professional Geoscientists|
|West Texas Geological Society|
INDUSTRY-RELATED PROJECTS AND SERVICES
Sites for INDUSTRY-RELATED PROJECTS AND SERVICES
|Name of Site|
|Baker Hughes Rig Counts|
|Harts E&P net|
|International Centre for Gas Technology Information|
|Oil.Com web directory for oil and gas industries|
|Oil Industry News Service|
|Oil-N-Gas.com educational forum|
Name of Course
Developer of Course and Procedures to Secure Material
|Oil and Gas Taxation||3203||Computer||MicroMash – Contact Local Education Branch (Pre-requisite to take Oil and Gas Unit 2)|
|Oil and Gas Examinations Unit 2||3186||Classroom||IRS – Contact Petroleum Industry Specialist Staff|
Frequency of Publishing
Summary of Purpose/Information Included/Availability
|Oil &Gas Journal||Weekly||Petroleum news and technology on a weekly basis. A leading information source for the industry. Provides top quality articles and graphics on oil and gas industry concepts.|
|Oil & Gas Energy Quarterly||Quarterly||Formerly the O&G Tax Quarterly it is now broader in scope. It has a good quarterly review of significant tax cases and revenue rulings. It is academic in nature.|
|International Petroleum Encyclopedia||Annual||Annual publication with outstanding maps, production statistic and articles on trends.|
|Petroleum Intelligence Weekly||Weekly||A leading industry newsletter.|
|Petroleum Economist||Monthly||International market reports from an economist’s point of view are provided. Good quality overview of world oil and gas production figures is provided.|
|Platts Oilgram News||Daily||A leading daily newsletter for the industry.|
|Transfer Pricing||Weekly||A standard reference reports on transfer pricing. Oil and gas industry transactions are frequently reported.|
Date of Latest Edition
Summary of Contents
|2008||Oil and Gas – Federal Income Taxation||Annual publication of CCH. . It gives detailed rules of federal income taxation for oil and gas operations; primarily upstream operations.|
|1999||Income Taxation of Natural Resources||Annual publication by KPMG accounting firm. It gives detailed rules of federal income taxation for natural resources.|
Principles, Procedures & Issues (4th Edition)
|Publication is designed to provide accurate and authoritative information and explanation in regard to U.S. petroleum financial accounting principles and practices prior to publication.|
|1993||Oil and Gas Taxation in Nontechnical Language||Explains the essence of oil and gas taxation without the legal jargon. It is for the use of a person that is knowledgeable about the oil and gas industry.|
|1991||The Prize: The Epic Quest for Oil, Money, and Power||The book provides an explanation of the role that oil played in many of the world's major conflicts over the past century. It also gives backgrounds and highlights of the key personalities who played a role in the history of oil.|
|1998||Titan: The Life of John D. Rockefeller, Sr.||The book describes the life and times of John D. Rockefeller, history’s first recorded billionaire. Standard Oil--which he always referred to as the result of financial "cooperation," never as a "cartel" or a "monopoly"--controlled at its peak nearly 90 percent of the United States oil industry.|
Summary of Information Included
|IRM 4.4.1||Oil and Gas Handbook||The Oil and Gas Handbook has been prepared to assist examiners in the examination of income tax returns of taxpayers involved in the oil and gas industry.|
|4810, ch 16||Oil Pricing Reports||Reports required for transfer pricing|
|42(15) 0||Del. Order 13||Delegation Order for Controlled issues and PIP functions|
The following “Statement of Financial Accounting Standards” (FAS) affect the financial accounting for the petroleum industry.
|No. 19||Financial Accounting And Reporting For Oil and Gas Producing Companies|
|No. 25||Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies|
|No. 34||Capitalization of Interest Costs|
|No. 69||Disclosures About Oil and Gas Producing Activities|
|No. 95||Statement of Cash Flows|
|No. 109||Accounting For Income Taxes|
|No. 121||Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of|
|FASB Current Text, Sec. Oi5||Integration of currently effective accounting and reporting standards promulgated by the AICPA and the FASB. The Oi5 section is drawn from FAS 19, 25, 69, 95, 109, and 121.|
G. Audit Techniques Guides
There are two audit technique guides that affect the petroleum industry.
- The first, Oil and Gas Industry, focuses on the exploration and production or "upstream" portion of the industry.
- The second, Retail Industry, specifically the section on Gasoline Service Stations, provides an overview of a portion of the downstream segment of the industry.