East Texas Oil & Gas

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1 East Texas Oil & Gas TAXATION AND DEDUCTIONS OPTIONS & ALTERNATIVES for OIL & GAS TANGIBLES and INTANGIBLES

2 Oil and Gas Federal Income Taxation 185 Chapter 10 Intangible Drilling and Development Costs 1001 Introduction 1002 History 1003 Definition of Intangible Drilling and Development Costs 1004 Geothermal and Carbon Dioxide Wells 1005 Intangible Drilling Costs and Dry Hole Elections 1006 Year of Deduction 1007 Drilling Arrangements 1008 Other Considerations 1009 Illustrative Examples 1001 Introduction In order to recognize the high risks involved in drilling exploratory and developmental wells, taxpayers are allowed to make a binding one time election to expense intangible drilling and development costs (IDC). This election generally permits an immediate write off of expenditures that would otherwise be capitalized and amortized. However, integrated oil are required to capitalize a portion of their intangible drilling costs even after making this election. Foreign intangible drilling costs paid or incurred after December 31, 1986, must be capitalized and written off under special rules History Although there was no specific provisions in the Code, prior to the 1954 code for the expensing of intangible drilling and development costs, the Treasury Regulations granting an election were held valid by the courts. In Ramsey v. Comm., the Tenth circuit explained the reason for their validity as follows:

3 This conclusion is strongly fortified by the fact that this regulation has been in existence for many years; Congress has repeatedly amended the revenue laws while this regulation was in full force and effect, and no effort has been made to do away with it. This is almost conclusive proof that Congress was satisfied with the construction put upon its language in the earlier acts. By repeated reenactments, Congress has ratified and approved this interpretation. However, the validity of the regulations was questioned in F.H.E. Oil Co. v. Comm. where the court commented to the effect that it was unnecessary to determine the validity of the regulations to properly dispose of the case at hand. As a result of the uncertainty created by this case, Congress, in House Concurrent Resolution 50, recognized and approved the existing regulations. Later, the statutory language which provides for the intangible drilling cost election was adopted..01 Early Regulation For all practical purposes, the option to expense or capitalize intangible drilling and development expenditures has existed since the first income tax statute. Judicial recognition of the existence of the option for the year 1916 appears in Shaffer v. Comm. where the facts were from March 1, 1913, until December 31, 1915, the taxpayer capitalized intangible drilling and development costs on her income tax returns. From January 1, 1916 until December 31, 1918, the taxpayer expensed such costs. When the taxpayer sold her oil and gas properties in 1919, the IRS refused to permit the taxpayer to consider the intangible costs after December 31, 1915 as part of the leasehold costs. The Board of Tax Appeals sustained the IRS and concluded that the Revenue Act of 1916 provided an option to capitalize or expense such items and the taxpayer was bound by her election..02 Obligation Wells Prior to the change in the regulations, effective only for tax years beginning after December 31, 1942, it was the IRS s contention, sustained by the courts, that intangible drilling and development costs incurred in the acquisition of a lease, or a part thereof, or incurred in connection with a lease under the terms of which the lessee was obligated to drill or lose acreage thereunder, should be capitalized. This was so even though the

4 taxpayer had properly elected to expense intangible drilling and development costs. These wells were referred to as acquisition wells or obligation wells Definition of Intangible Drilling and Development Costs.01 Deduction or Capitalization of Costs In connection with the drilling of oil and gas wells, a taxpayer has the option either to expense or to capitalize intangible drilling and development expenditures. The option is available only to the owner of a working or operating interest. The election to expense intangible drilling and development costs applies to all expenditures made by the operator for wages, fuel, repairs, hauling, supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for the production of oil or gas. The option applies only to those drilling and development expenditures that have no salvage value. Equipment of a character that is ordinarily considered as having a salvage value, whether it consists of production facilities or equipment necessary for the completion of a well, is depreciable. Its cost may be recovered only through the depreciation allowance. This includes the cost of casing, even though such casing is cemented in the well to such an extent that it has no net salvage value. The cost of installing salvageable items required to complete the well are also treated as intangible drilling and development costs subject to the election. The IRS has ruled that a producing well is completed when the casing, including the Christmas tree, has been installed. Expenses that relate to the installation of production and treatment facilities, such as storage tanks and pumping equipment, are not considered to be intangible drilling costs. The expenses of operating wells or other facilities for the production of oil and gas are deductible as ordinary and necessary business expenses.

5 Intangible and development costs include those costs incurred to: (1) drill, shoot, or clean a well; (2) prepare the site for drilling, including ground clearing, drainage, road construction, and surveying and geological work: and (3) construct the physical facilities necessary to drill and prepare the well for production Intangible Drilling Costs and Dry Hole Elections A taxpayer may elect either to deduct intangible drilling and development costs or to capitalize such costs as part of the basis of the lease or well equipment. If the taxpayer elects to capitalize intangible drilling costs, then an additional election is available to deduct as an ordinary loss those costs incurred in drilling a nonproductive well. The costs not represented by physical property are recoverable through depletion where no election is made. Those costs representing physical property are recoverable through depreciation. Physical property is considered to be amounts paid for wages, fuel, repairs, hauling, supplies, etc., used in the installation of casing and equipment and in the construction on the premises of derricks and other physical structures. Depletable costs would be all costs incurred in preparing the drill site, as well as the costs of drilling, shooting, and cleaning the well. If the well is drilled on a turnkey basis, an allocation between depreciable and depletable property is required. In order to deduct intangible drilling and development costs, the taxpayer must be considered an operator of the property. An operator is defined as one who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights. The taxpayer must actually undertake the economic risk of drilling at the time the drilling takes place. This is true regardless of whether the expenses are incurred by him prior or subsequent to the formal grant or assignment to him of operating rights..

6 Oil and Gas Federal Income Taxation 255 Chapter 12 Depletion Deduction General 1201 Overview 1202 Requirements for Depletion 1203 Other Considerations 1201 Overview.01 General The extraction of minerals reduces the capital investment of those having an interest in such reserves. As compensation for this reduction, a reasonable deduction for depletion is allowed in computing taxable income. In many respects, the depletion deduction is similar to the deduction allowed for the cost of goods sold in a manufacturing business. It is the depletion deduction that allows for the tax free return of capital consumed in the production of mineral income..02 Statutes Code Sec. 611 sets out the allowances for the depletion deduction and Code Secs. 613 and 613A contain the provisions for the computation of the deduction for percentage depletion. It may be safely stated that most of the litigation involving this deduction has been in connection with the percentage depletion computation in Code Sec. 613 and the corresponding provisions of prior law..03 Purpose of Deduction In O Shaughnessy, Inc. v. Comm. the Tenth Circuit expressed its belief that Congress granted the depletion deduction to avoid the taxation of capital:

7 It is clear it was the Congressional purpose to allow return of capital through statutory depletion from the date of the acquisition of the depletable interest, so long as gross income is realized dependent upon the production of oil and gas. The formula prescribed by Section 23(m) 114(b)(3), [I.R.C. (1939)], having direct relationship to gross income from sources within its scope (oil and gas wells), is exclusive in its applications and to that extent it is an arbitrary substitute for the fundamental rule against the taxing of gross income before recovery of capital cost..04 Burden of Proof The rule providing that a taxpayer must carry the burden of proof for a deduction applies equally to depletion. This rule extends to the maintenance of adequate records to support the deduction. An illustration of this may be found in F K Land Co v. Comm., where the facts showed that a tract of land owned by the taxpayer had a fair market value as of March 1, 1913, of $104,000. In 1930, the taxpayer leased the land and received $130,000 and claimed cost depletion in the amount of $104,000. The deduction was disallowed by the IRS and the taxpayer chose to litigate on the basis of the fact that no proof was made by the government as to the royalties expected to be received and that it was impossible to foretell production. In a Technical Advice Memorandum that addressed similar facts, the IRS held that the computation of a cost depletion deduction on lease bonus payments with respect to wildcat acreage must be based upon reasonable estimates of future expected royalty production from the mineral property. While Reg (a) allows a deduction for depletion in advance of production, the IRS held that it may not be construed to allow such a deduction without some reasonable expectation that a mineral deposit actually exists. The fact that a presumably knowledgeable lessee would pay a bonus in order to acquire rights under the lease appears to the IRS to indicate a reasonable expectation that the property will produce income and that royalties will accrue to the lessor. Therefore, a deduction, as cost depletion, of the entire amount of the basis in the mineral property is not permitted, based upon an estimate that future royalties to be received would be zero.

8 In Collums, however, the U.S. District Court allowed a sublessor of leases covering wildcat acreage to compute cost depletion on the cash bonus received in accordance with the formula provided by Reg (a)(1). The district court determined that any estimate of future production on any such wildcat lease in excess of zero would have been purely speculative and not based on any known fact nor good evidence. The effect of estimating future royalties to be received to be zero was to allow all the basis in the lease to be claimed as cost depletion in the year the bonus was received..05 Cost or Percentage Depletion Cost depletion and the statutory percentage depletion are basically the same, according to the Supreme Court. In Herring v. Comm., that Court, in discussing percentage and cost depletion in connection with a bonus stated: But the nature and the purpose of the allowance is the same in both cases, and we find neither statutory authority nor logical justification for withholding it in the one and granting it in the other. However, a taxpayer is not entitled to cost and percentage depletion on the same property in the same taxable period. Nevertheless, the test of the greater deduction, i.e., cost or percentage, is made as to each taxable period, the allowance of either in a taxable period not necessarily precluding the deduction of the other in subsequent taxable periods. As indicated in Code Sec. 6.13, if cost depletion exceeds percentage depletion, the former is the proper deduction. Cost depletion allocates the depletion basis in the property to the units of minerals sold during the tax year. Percentage depletion equates depletion to a specified percentage of the gross income from the property and is subject to a limitation that it not exceed 100 percent of the taxable income from the property. In the case of oil and gas, percentage depletion is further limited to certain quantities and to 65 percent of total taxable income (as adjusted).

9 Cost Depletion. The cost depletion for a tax year is determined in two steps. First, the depletable basis in the property is divided by the total of the recoverable units at the end of the tax year and the units of minerals sold during the tax year. The resulting amount (which represents cost per unit) is then multiplied by the units sold during the tax year to arrive at cost depletion. An alternative method to compute cost depletion is to divide the total of the recoverable units at the end of the tax year into the units sold during the tax year. The resulting amount (which represents the portion of the property produced and sold) is then multiplied by the depletable basis in the property. Some taxpayers prefer to compute cost depletion using both methods in order to get a feel for the reasonableness of the resulting amount of cost depletion on the property. Of course, both methods result in the same final answer. As noted above, if cost depletion exceeds percentage depletion, it represents the depletion deduction for the tax year. The depletable basis in the property is then reduced by the amount of cost depletion, claimed with respect to the property. Once a property s depletable basis has been completely absorbed, no further deductions for cost depletion may be claimed with respect to the property. Percentage Depletion. Percentage depletion is generally allowable at a rate of 15 percent of gross income from the property limited to the taxable income from the property. Numerous limitations are applicable to this general allowance based upon the status of the taxpayer, the status of the property, and the overall taxable income of the taxpayer. Code Sec. 613A(c)(6) may increase the 15 percent percentage depletion rate for marginal oil and gas production for tax years beginning after The depletion rate will be increased one percentage point for each whole dollar that the reference price for the preceding calendar year is below $20 per barrel. However, the maximum depletion rate increase is limited to 25 percent. Marginal production includes oil and gas produced from stripper well properties. Stripper well properties produce 15 or less equivalent barrels per day per producing well. Stripper well classification is redetermined annually based on total calendar year production from all producing wells on the property. The property for purposes of the stripper well classification is determined under section 614. Marginal production also includes production from a property substantially all of which is heavy crude oil.

10 Percentage depletion is allowable only to those who are entitled to cost depletion. In the Kirby case, the Fifty Circuit considered the controlling theory to be as follows: The allowance of percentage depletion is made only to the person who would be entitle to claim cost depletion on account of their ownership of a depletable capital asset, the fundamental theory of the allowance not having been altered by the provisions for percentage depletion. If percentage depletion exceeds cost depletion, it represents the depletion deduction for the tax year. The depletable basis in the property, if any, is then reduced by the amount of percentage depletion claimed with respect to the property. Unlike cost depletion, percentage depletion is not limited to the depletable basis in the property. It may be claimed as long as the property generates gross income.

11 SECTION 179 TAX DEDUCTIONS OPTIONS & ALTERNATIVES for OIL & GAS TANGIBLES Section 179 Deductions? - What are They and What You Really Need to Know About Writing-Off Tangibles in Oil & Gas! Most new business equipment (Example: oil & gas drilling and completion tangibles) can be either be (1) depreciated over their useful life or (2) expensed immediately under Internal Revenue Code Section 179. The maximum deduction is based on the following schedule for the date in which the tax year begins. Each 1040, whether Single or Joint, is limited to one maximum. Section 179 expenses passed through via K 1s from partnerships (1065), S corps (1120S), or trusts (1041) are limited at the 1040 level to the one maximum amount. A C corporation is able to deduct its own Section 179 expenses in addition to what is claimed on the 1040s of the owners. This is one of the many ways in which C corps can save thousands of dollars in taxes over S corps. The following table is of the Federal maximums. Many states have not matched these amounts and have much smaller allowable deductions. In those cases, it is critical to maintain two sets of depreciation schedules; one for IRS and another for the State. Since the basis of an asset may be different for each tax agency, the gain or loss on its disposal will similarly be different. For 2004 through 2009, the annual amounts are to be adjusted for inflation. Up until recently, the Section 179 election was only allowed on originally filed tax returns. People who overlooked it were not allowed to claim it on amended returns. This new law allows the Section 179 expensing election to be claimed or revoked on amended returns for 2003 through Tax Year Federal Maximum 2002 $24, $100, $102, $105, $108, , $112,000 + COLA 2009 $112,000 + COLA 2010 $25,000

12 Qualifying Property Generally, the types of business equipment that qualify for this expensing election are the same kind that qualified for the now defunct Investment Tax Credit. Most movable assets qualify. Permanent structures do not qualify. One of the most common questions I am still receiving is whether the Section 179 expensing election is only available for the purchase of brand new assets or whether things such as used vehicles qualify. The answer is still the same. The asset just has to be new to you. You can claim the deduction for items purchased from anyone other than yourself or an entity controlled by you, such as a closely held corporation. As of October 22, 2004, the maximum amount that can be claimed for SUVs weighing between 6,000 and 14,000 pounds is $25,000. The remaining $77,000 can be used for other kinds of business equipment, including vehicles weighing more than 14,000 pounds. To be eligible for the Section 179 deduction, the asset must be used at least 50% for business in the first year it is placed in service. The cost eligible for the deduction is the business usage percentage. Here are more details on qualifying and nonqualifying property, courtesy of the indispensable QuickFinder reference book. Qualifying Property: Tangible personal property (such as machines, equipment, furniture). Certain other tangible property used for specified purposes. Single purpose agricultural or horticultural structures. Certain storage facilities. Railroad gradings or tunnel bores. Some examples of qualifying property from the Depreciation QuickFinder Handbook: Airplanes. Automobiles. Billboards (if movable). Cattle dairy or breeding. Citrus trees. Computers. Emus. Fruit trees. Gas storage tanks. Goats breeding or milking. Greenhouses

13 Helicopters. Horses. Macadamia trees. Machinery and equipment. Mink and other fur bearing animals. Office equipment copiers, typewriters, fax machines, etc. Office furniture desks, chairs, file cabinets, book shelves, etc. Off the shelf computer software. Oil and gas well and drilling equipment. Orchards. Ostriches. Printing presses. Refrigerators. Sheep breeding. Signs. Sport Utility Vehicles (SUVs). Storage facility (e.g., peanut, hay, potato or tobacco). Store counters. Testing equipment. Tractors. Trailers (movable). Trucks. Vineyards. Water wells. Nonqualifying Property: Property held for the production of income (investment property, most rentals). Real property, including buildings and heir structural components, air conditioning and heating units. Property acquired by gift, inheritance or trade. Property purchased from certain related parties. Controlled group to controlled group transactions. Property used outside the United States. Property used in connection with furnishing lodging. Property used by tax exempt organizations and governmental units. Property used by foreign persons or entities. Property held by an estate or trust. Property used by a passive activity. Intangible property (including computer software).

14 Phase Out of Sec. 179 To prevent the evil rich, who buy a lot more new things than normal people, from receiving this tax benefit, there is a phase out of the allowable Section 179 deduction if too much new 179 qualifying property is purchased during the tax year. For each dollar of newly acquired qualifying property purchased during the tax year that exceeds the amounts established by our rulers in DC, the Section 179 deduction is reduced by a dollar; but not below zero. For 2003, that phase out begins at $400,000 For 2004, that phase out begins at $410,000 For 2005, that phase out begins at $420,000 For 2006, that phase out begins at $430,000 For 2007, that phase out begins at $450,000 Original article written by: Kerry M. Kerstetter Standard Depreciation Options for Oil & Gas Tangibles: Normally the cost of all tangible equipment for O&G is depreciated over 7 years with original year of the investment in the well being the 1st year of the seven. OR you can elect to take NONE of the tangible depreciation write offs in the first year, but then you must do a loss carry forward with equal (20% each) deductions for the fixed period of five(5) years immediately following the first year of the investment. OR you may elect to invoke Section 179 and expense 100% of the tangibles in the first year of investment (Please request the Section 179 Handout). Leasehold Costs: Costs in each program that relate to the acquisition cost of the lease property are written off when the well reaches the end of its commercial viability and is eventually plugged and abandoned. Although a very small percentage of the overall costs, it remains with the property throughout its useful life. *This is not to be construed as tax advice. We recommends the use of a Certified Public Accountant competent in oil and gas matters.

15 Reprint of: Tax Benefits of Oil & Gas Investments from Bull & Bear by Jodi Mersinger Tax Benefits of Oil & Gas Investments From Bull & Bear By Jodi Mersinger, CPA The Global Advisor As an alternative to real estate stocks, bonds and mutual funds, a working interest in an oil and natural gas joint venture or partnership can provide portfolio diversification with preferential tax treatment. The acquisition, exploration, and development of properties for the production of oil and natural gas require the investment of significant capital and often involve the assumption of higher levels of risk than many other investments. The U.S. government, however, has established favorable tax policies to encourage the development and production of oil and gas properties. The tax benefit considerations can materially affect the anticipated return to be realized on the investment and often determine the form and feasibility of the investment. The major portions of the expenditures paid by a working interest holder in drilling an oil and gas well are classified as intangible drilling and development costs ( IDC ). These costs include wages, fuel, repairs, hauling, suppliers, clearing of ground and geological work in preparation for the drilling, construction of derricks, tanks, pipelines, and other physical structures necessary for drilling and other items incidental to, and necessary for, the drilling of wells and the preparation of wells for the production of oil and gas. These types of expenditures are generally considered nondeductible capital expenditures. However, a working interest holder is granted the option of electing to deduct IDC. This benefit makes an oil and gas investment more desirable from a tax standpoint: a significant portion of the investment is written off upon initial investment as opposed to waiting until disposition of the interest as with other types of investments. The IDC deduction is an ordinary deduction sheltering income at the highest income tax brackets, as opposed to a capital loss offsetting largely only capital gains. (Note that in certain limited circumstances, the IDC deduction may create a preference item for alternative minimum tax purposes.) An election may also be made to ratably deduct the IDC over a five year period, allowing an investor the flexibility of timing the deduction to maximize the tax benefits available. Expenditures for tangible property, such as drilling tools, pipe, casing, tubing, tanks, engines, and machines are recoverable through depreciation allowance over a recovery period of five to seven years. In addition to depreciation allowances for the use of physical properties, there is an annual allowance for the depletion of the mineral reserves. The depletion allowance may be the greater of (1) an allocated portion of the adjusted basis of the depletable property (cost depletion); or (2) a statutory percentage of the gross income from the property (percentage depletion). The statutory percentage depletion allowance for independent gas producers is 15%. (Based on certain production criteria, the percentage depletion allowance may be limited for a particular year or may create a preference item for alternative minimum tax purposes.)

16 Another advantage of an oil and gas investment is a special exclusion from the passive activity loss limitations. Generally, deductions exceeding income from an investment in a business activity where the investor does not materially participate in the business are not deductible against other such as salary, interest, dividends, and active business income. The losses are considered passive losses, which are suspended and allowed only against passive income or when the investor disposes of his or her entire interest in the activity. However, a working interest is an oil and gas property, which the investor holds directly or through an entity which does not limit his or her liability with respect to such interest, is not considered a passive activity subject to these rules. Thus, an owner of such a working interest in an oil and gas property is permitted to deduct otherwise unallowable losses attributable to the working interest, whether or not he or she materially participated in the activity. In addition to the above tax advantages, deductions for a year end investment in an oil and gas well may be deductible in the year the expenditure is made, even though the well may be drilled in the subsequent year. The IRS has ruled that an investor may deduct prepayments of IDC in the year in which the payment is made where there exists a binding obligation to pay such costs, irrespective of whether the drilling has commenced in that year or the subsequent year. There is also a special rule for accrual method investors, which allows an IDC deduction when the payment is made. In general, economic performance has to have occurred with respect to the prepaid drilling expenses. For certain investors, economic performance is deemed to occur in the year of prepayment if drilling of the well commences within 90 days after the end of the year (commonly referred to as the 90 day spud rule.) Therefore, although an oil and gas program may not begin drilling operations until the following year, an investor may still be able to deduct his or her prepaid investment made in the current year. Owners of gas working interests have also mitigated some of the costs and risks through the joint development of properties. A Joint Operating Agreement is generally entered into, designating one party as the operator and providing for the development and operation of the property and the proportionate sharing of the costs of production. The investor is entitled to his or her proportionate share of the revenues from production of the well (after royalties) during the life of the well. The tax benefits described above can be quantified for a particular proposed oil and gas investment. These benefits certainly enhance the attractiveness of purchasing an investment in a crude oil and/or natural gas field drilling and development project. Editor s Note: Jodi Mersinger, CPA, is a Certified Public Accountant with the firm of Wolf & Company, LLP in Oak Brook, IL. Reprint of: Tax Benefits of Oil & Gas Investments from Bull & Bear by Jodi Mersinger