Tax Matters and Benefits

BOARDMAN ENERGY PARTNERS

 Exploration & production of oil and gas

The Independent American Producer


America’s determination to increase domestic reserves and be free of OPEC dependency has placed a tremendous need for capital on oil and gas companies. The burden is particularly heavy for independent producers whose funds are more limited than those of major oil and gas companies which fund their drilling activities with the sale of stock.


THE FOLLOWING WAS WRITTEN TO SUPPORT THE PROMOTION OR MARKETING OF OIL & GAS WORKING INTEREST AS ADDRESSED HEREIN. THE FOLLOWING WAS NOT INTENDED OR WRITTEN TO BE USED, AND IT CANNOT BE USED BY ANY TAXPAYER, FOR THE PURPOSE OF AVOIDING PENALTIES THAT MAY BE IMPOSED ON THE TAXPAYER UNDER U.S. FEDERAL TAX LAW. EACH TAXPAYER SHOULD SEEK ADVICE BASED ON THE TAXPAYER’S PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISER. EACH PROSPECTIVE PURCHASER IS ADVISED TO CONSULT HIS PERSONAL TAX ADVISOR WITH RESPECT TO THE UNITED STATES FEDERAL AND STATE INCOME TAX CONSEQUENCES OF SUCH PURCHASER’S PARTICIPATION.


Many provisions of current federal income tax law impinge on taxpayers who participate in the exploration for and production of oil and gas through direct investment in transactions like the Program. Certain of these, such as the option to deduct intangible drilling and development costs and the depletion allowance, are in the nature of incentives to production of domestic oil and gas, and confer tax benefits on participants in exploration and production ventures, which reduce the economic cost of participation. Other provisions, such as the alternative minimum tax on tax preference items, may adversely affect Participants. The federal income tax provisions impinging on participants in oil and gas exploration and production ventures are generally quite complex, and frequently are subject to substantial uncertainty in their application to specific transactions. The full implications of the federal, state and local tax laws which may affect the tax consequences of participating in the Program are too complex and numerous to be fully described herein. Also, the discussion which follows is necessarily general. EACH PROSPECTIVE PARTICIPANT SHOULD SATISFY HIMSELF AS TO THE INCOME AND OTHER TAX CONSEQUENCES OF PARTICIPATION IN THE PROGRAM BY OBTAINING ADVICE FROM HIS OWN TAX ADVISOR.

Participants should realize that the purchase of Units will not result in tax shelter benefits, and it is not possible to profit from an investment in oil and gas properties merely through the tax benefits that may be made available thereby. Each Participant must understand that unless he or she purchases a Unit with the intention of profiting from the economic return from it, exclusive of any ancillary tax benefits which may under certain circumstances result, then the Participant may be denied any tax benefits.

Set forth below is a summary and general discussion of some of the principal tax aspects and consequences of investment in the Program. The discussion, which is not intended to be exhaustive or to constitute an opinion of counsel or specific tax or legal advice, is directed primarily to individual cash basis taxpayers who are citizens and residents of the United States. Other prospective Participants in the Program, such as corporations, Companies, trusts, and resident aliens, should consult their tax advisors concerning special rules applicable to them before investing in the Program.

In construing the pertinent provisions of the Code, consideration was given to its legislative history, existing and proposed regulations promulgated by the Treasury Department, judicial decisions construing its provisions, and administrative rulings and practices of the Internal Revenue Service (“IRS”) in effect as of that date. The discussion is subject to amendment of the Code, issuance of new regulations, changes in judicial construction of the Code, and changes in IRS ruling positions and administrative practices, any of which may occur at any time. These developments may materially and adversely affect the tax aspects and consequences summarized below, and may be applied retroactively, so as to affect transactions previously entered into. In particular, provisions originating in the Tax Reform Act of 1986 (“the Act”) or subsequent acts may be interpreted by the Treasury Department, the IRS, or reviewing courts differently from the way such provisions have been interpreted by the Company. Participants should consider that it is likely that significant changes will occur to the Code.

Some Code provisions, which are discussed below, are subject, in some instances, to substantial uncertainty and controversy in their application. Moreover, their application depends, in some instances, on the resolution of factual issues about which reasonable persons could differ. Furthermore, certain of the tax consequences of investment in the Program are dependent upon the individual circumstances of Participants. No assurance can be given that the IRS will not challenge the tax consequences claimed by Participants, or that a reviewing court will not sustain the position taken by the IRS. In this regard it should be noted that the Company does not intend to obtain an IRS ruling regarding any of the tax consequences of investment in the Program.


TAX OPINION


The Company has not obtained an opinion from a public accounting firm, regarding the material tax consequences of an investment in any such Program.


TAX STATUS OF THE PROGRAM


Participants will be purchasing units of fractional undivided working interest in the Well(s). If the Program is not reclassified for tax purposes as a Company or an association taxable as a corporation, the sale of Units will establish among the Participants the relationship of co-owners of the Lease, or more specifically co-owners of the well-bore of the Well(s) and the exclusive operating rights granted by the Lease. Consequently, each Participant will be entitled to make with respect to his Units of Working Interest such elections as the Code permits participants in the exploration for and production of oil and gas, including the election to deduct IDCs and the election of a method of depreciation. Each Participant will be obligated to report on his personal income tax return his share of income, deductions, credit, and other tax items attributable to his ownership of Units in accordance with his taxable year, his method of tax accounting, and his elections. The IRS may attempt to reclassify the Program as either a Company or as an association taxable as a corporation. Were the Program to be reclassified for tax purposes as an association taxable as a corporation or as a Company, the tax consequences of investment in the Program would be materially affected.


Possible Reclassification as a Company.


The Company believes it possible that the execution of a joint operating agreement on behalf of the Company and the Participants, as is contemplated, may create an entity constituting a Company for tax purposes. However, members of an unincorporated association constituting a Company for tax purposes may under certain circumstances elect to be excluded from the Company provisions of the Code. This election is available to, inter alia, participants in the joint production, extraction, or use of property who own the property as co-owners, who reserve the right to separately take in-kind or dispose of their respective shares of any property produced or extracted, and who do not jointly sell services or any property produced or extracted, other than through delegation of authority for a period not in excess of the minimum reasonable needs of the industry, and in no event for more than one year. The Operating Agreement to be executed on behalf of the Company and the Participants conforms to these requirements and contains an election to be excluded from the Company provisions of the Code. However, if reclassification as a Company occurred, it would eliminate the Participant’s right to make their own elections regarding the tax consequences of the Program’s activities, and would subject the program and the Participants to the Company provisions of the Code.


Possible Reclassification as a Corporation.


Several pronouncements by the IRS serve as guidelines for when joint operating agreements of the type commonly entered into between co-owners of oil and gas properties will lead to classification of the venture as an association taxable as a corporation. Although such documents are old, prior to January 1, 1997, they appeared to still be relied upon by the IRS and the courts in determining issues relating to entity classification for oil and gas ventures. Reclassification as an association taxable as a corporation would deny to Participants the tax deductions attributable to their Units; the Program instead would be required, in accordance with its taxable year and method of accounting, to take such deductions against its gross income and to file a corporation income tax return and pay tax on its taxable income at corporate rates. Distributions of cash from the Program would be taxed to Participants under the corporate dividend provisions set forth in Subchapter C of Chapter 1 of the Code. Recent changes to the Regulations concerning classification of entities for federal income tax purposes now require joint undertakings such as the Program to make an affirmative election to be taxed as a corporation if the participants in the undertaking desire to be taxed as a corporation. Since no affirmative election is to be made, there should be little exposure for the Program to be taxed as a corporation.


Nature of Income and Losses (Restrictions on Passive Losses).


Revisions to the federal tax laws in recent years were enacted to reduce overall investment in “tax shelters.” The most important provisions intended to accomplish this purpose are the “passive activity” rules contained in Code Section 469. These rules basically operate by creating three classes of income and loss - “passive,” “active” and “portfolio” - and providing that passive losses can be applied to offset only passive income, but not active or portfolio income. For this purpose the term “passive activity” means any activity involving the rental of property or the conduct of a trade or business in which the taxpayer in question does not materially participate, and includes the interests of limited partners in limited Companies. Portfolio income is investment income, such as interest, dividends, and royalties, and active income and loss is income and loss which does not fall into either of the other categories. The effect of these rules is to prohibit the use of passive losses to shelter income from salaries, investments, and other non-passive sources, which substantially reduces the economic value of such losses.

Although oil and gas exploration ventures conducted through limited Companies constitute passive activities with respect to their limited partners, an exception is made for ventures like the Program: the term “passive activity” does not include any working interest in an oil and gas property which the taxpayer in question holds either directly or through an entity which does not limit his liability with respect to the interest, such as a general Company, regardless of whether the taxpayer materially participates in development of the property. Losses from such working interests, including those to be acquired by Participants in the Program, will not constitute passive losses, and thus can be used to offset active and portfolio income; conversely, income from such working interests will not constitute passive income and cannot be offset by passive losses. However, holders of such interests who do not materially participate in development, including Participants in the Program, will be subject to the investment interest rules, as amended by the Act, with respect to any debt incurred to acquire or carry their interests.

An individual’s planning with respect to application of the passive loss rules depends heavily on the amount and nature of the income and losses expected to be realized from existing activities and investments. Participants in the Program should consult their personal tax advisors concerning the application to them, and to their investment in the Program, of the passive activity rules.

Regulations concerning the application of the passive activity loss rules contain re-characterization provisions whereby certain income which would ordinarily be considered passive activity income is reclassified as active income. The Regulations provide that net income from oil and gas property which includes a well with respect to which a loss was deducted after 1986 pursuant to the working interest exception to the passive loss rules is to be classified as active income even if the income would otherwise be characterized as passive. For this purpose the regulations employ a novel definition of the term “oil and gas property,” under which the term includes any interest the value of which is directly enhanced by drilling, logging, seismic testing or other activities the costs of which were taken into account pursuant to the working interest exception. The examples under such temporary regulations appear to further define an oil and gas property for this purpose as a reservoir. Therefore, if a well drilled under the working interest exception (for which a loss has been deducted in a prior year) has enhanced the value of other locations in that reservoir, the net income from a subsequent well drilled into such reservoir will not constitute passive income even if the interest is held as a limited partner in a limited Company. Thus, the drilling of the Program’s Well(s) could conceivably affect the nature of income of a Participant from a separate oil and gas interest in the same reservoir, the value of which is directly affected by the drilling of the Program’s well, if such other well is developed after the development of the Program’s Well and is acquired through an entity, such as a limited Company, which causes the acquired interest ordinarily to constitute a passive activity. Participants may wish to consult their personal tax advisors concerning this matter, and the general application of the temporary regulations, before investing in the Program.


Intangible Drilling and Development Costs.


IDCs consist of costs incurred in connection with the development of a well with respect to items which in themselves do not have a salvage value, such as labor, fuel, repairs, and supplies. Such costs, which generally constitute a substantial portion of the costs of exploring for and producing oil and gas, normally constitute capital expenditures. Absent special provisions, such costs would be capitalized into the basis of the property to which they relate and recovered through the depletion allowance or, at the option of the payor, amortized over either (a) a ten-year period beginning with the year in which the expenditure is made or (b) ratably over a sixty (60) month period beginning with the month in which the IDC expenditure was paid or incurred. However, IDCs are subject to an election under Code Section 263, pursuant to which they may be deducted. The year in which IDCs are deductible depends on when they are paid, the year the work relating thereto is carried out, and the terms of the agreement under which they are paid. The availability of this election to deduct IDCs is the major favorable tax consequence of participation in the exploration for and production of oil and gas.

Once the IDC election to deduct or capitalize IDCs has been made, it is binding on a taxpayer for all properties owned by the taxpayer and for all subsequent tax years. Assuming that the Program is not reclassified as a Company or an association taxable as a corporation, each Participant will be entitled to make his own election concerning the treatment of IDCs attributable to his Units of Working Interest if he has not already made a prior year IDC election. However, if a prior year IDC election has been made by a Participant, such prior year election to capitalize or deduct is binding on such Participant with respect to the Well and all other oil and gas properties owned by such Participant. If a Participant elects or has elected to deduct IDCs, he may, subject to certain restrictions, deduct such IDCs in the year incurred, provided such costs are properly classified as IDCs, and do not in fact constitute organization or syndication costs or other nondeductible costs. However, the right to elect to deduct IDCs is subject to a number of limitations, and deduction of IDCs involves certain risks and may involve certain adverse tax consequences.

Treas. Reg. 1.612-4(a) provides that where a development project is undertaken in return for assignment of only a fractional working interest, only the IDCs attributable to such fractional working interest are eligible for the election to deduct. In such cases the remaining portion of IDCs must be capitalized as the payor’s cost of acquiring his fractional working interest, and recovered through depletion deductions. The IRS takes the position, as set forth in Rev. Rul. 70-336, 1970-1 C.B. 145, that the share of working interest held by the payor of IDCs during the “payout period” determines the portion of IDCs eligible for the election to deduct. Because Participants will own 100% of the Working Interest during Payout (assuming all Units are sold), and will pay 100% of all Drilling and Testing Costs and Completion and Equipping Costs, they will be entitled to deduct in the current year 95% of all IDCs they pay.

Upon the sale or other disposition of units of working interest, deducted IDCs are subject to recapture in a manner similar to the recapture of accelerated depreciation. The amount to be recaptured as ordinary income will be 100% of the IDCs deducted, without reduction for the amount by which the depletion deduction would have increased had such IDCs been capitalized.

“Excess” deducted IDCs, to the extent such “excess” IDCs exceed 65% of the taxpayer’s net income from oil and gas properties, may constitute an item of tax preference for purposes of determining the taxpayer’s alternative minimum tax liability. (See the “Alternative Minimum Tax” discussion below for a more detailed discussion of the “excess” deducted IDCs tax preference.)

The IDCs incurred by each Participant will be incurred and paid pursuant to the “Turnkey Contract” with the Company. The payments under the Turnkey Contract will also be allocable in part to items not constituting IDCs, such as casing, tubing, and other well equipment having a salvage value, and to an amount over and above actual anticipated costs as a “risk” factor to the Company for taking on the risk of the Turnkey Contract. In light of this, such payments will be required to be allocated between items constituting IDCs and items not constituting IDCs. The Company will provide each Participant an allocation of the payments made, and the Company will attempt to allocate the payments in conformity with standard industry practices and tax law requirements. However, no assurance can be given that the IRS will not challenge any such allocation, or that a reviewing court will not sustain any such challenge.

Additionally, the IRS has on occasion successfully challenged deductions of IDCs claimed by investors in transactions like the Program on the basis that the amounts paid under turnkey contracts exceeded reasonable costs of developing a lease, determining that the excess was thus allocable to leasehold acquisition or other costs not eligible for treatment as IDCs. Though the Company believes the costs being charged Participants under the Turnkey Contract are reasonable, and has represented to its accountant that the fees charged for the materials to be provided and the services to be performed by it under the Turnkey Contract does not materially exceed the fair market value of such materials and services, there is no assurance that the IRS will not disagree. The result of a successful challenge could be to reduce the tax benefits to Participants in this Program. Any costs which are reclassified would be deemed to be capital costs, and may or may not be recoverable through depreciation or amortization. The Company may contract out to third parties certain of its obligations. Any such assignment could give rise to extra scrutiny by the IRS relating to the valuation.


Geophysical Costs.


The cost of geophysical exploration must be capitalized as a Site Preparation Cost if a property is acquired or retained on the basis of data from such exploration. Geological and Geophysical Costs cannot be amortized over a period which exceeds twenty-four months. Otherwise, such costs may be deducted as ordinary expenses.


Operating Costs.


With the exception of any portion of the Operating Costs relating to the replacement of or addition to production equipment and certain work over expenditures which may qualify as IDCs, the costs of operating a well and obtaining production therefrom after completion of a well are currently deductible in the year paid by a cash basis taxpayer provided the expenditure is an ordinary and necessary expenditure which is reasonable in amount. It is not anticipated that any expenses incurred pursuant to the Operating Agreement will be excessive or unnecessary; therefore, it is anticipated such expenses will be deductible in the year paid. However, because of the factual nature of the proper characterization of such expenses and costs, no assurances can be given that the deduction of a particular item will not be successfully challenged by the IRS.


Depletion.


Owners of economic interests in oil and gas properties which produce income are entitled to deductions for depletion, which is similar to the depreciation deduction allowable with respect to tangible property. The depletion deduction permitted is the greater of “cost depletion” or “percentage depletion,” if the latter is available. Cost depletion is determined by reference to the capitalized cost, or “basis,” of the property in question, and the estimated units of recoverable oil or gas from the property; the allowable deduction in any year is the estimated per unit cost of the property (basis in the property divided by estimated number of units to be produced) multiplied by the number of units sold in that year. When the taxpayer’s basis in the property has been fully recovered through cost depletion deductions, no further cost depletion is allowable. The taxpayer’s basis in the property is generally his leasehold acquisition cost plus the portion, if any, of IDCs which have not been deducted or fully amortized.

The percentage depletion deduction is an arbitrary deduction of a specified percentage of the gross income of a depletable property and is limited to one hundred percent (100%) of the taxable income from the property. The percentage deductible with respect to oil and gas properties is generally fifteen percent (15%). Unlike cost depletion, percentage depletion may be claimed without regard to the basis of the property in question (though it reduces that basis) for so long as the property produces gross income. Under Code Section 613A, the availability of percentage depletion with respect to gross income from oil and gas wells now is substantially restricted, and its availability is largely dependent upon the personal circumstances of the individual owner of an interest in an oil or gas property. Set forth below is a brief summary of the current restrictions. The summary is by no means exhaustive, and the law regarding percentage depletion is subject to some uncertainty. Accordingly, each Participant should consult his own tax advisor concerning the availability to him of percentage depletion with respect to gross income from the Program before investing in the Program.

Percentage depletion is now available with respect to gross income from oil and gas wells only to “independent producers and royalty owners,” as defined in Code Section 613A, and then only with respect to a limited amount of production, being one thousand (1,000) barrels of oil per day (or equivalent amounts of gas). An independent producer is a person who neither refines crude oil in substantial quantities nor sells oil or gas at retail in substantial quantities, either directly or through a related person or business. Even if available, the percentage depletion deduction may not exceed sixty-five percent (65%) of the taxpayer’s taxable income for the taxable year in question. Any percentage depletion deduction disallowed because of the 65% of taxpayer’s taxable income limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the taxpayer’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

As stated above, the applicable percentage depletion rate, if percentage depletion is available, is generally fifteen percent (15%). However, a higher rate may be available for certain “marginal wells”. The potentially enhanced percentage rate for marginal wells is dependent upon the reference price for crude oil as determined under Code Section 29(d)(2)(c) [the Treasury Secretary’s estimate of average well head price] for the calendar year preceding the calendar year during which the taxpayer’s tax year begins. If the reference price exceeds twenty dollars ($20.00) per barrel, there is no enhanced percentage depletion. For an enhanced percentage depletion rate to be applicable, the subject reference price must be nineteen dollars ($19.00) or less. The fifteen percent (15%) percentage depletion allowance is increased one percentage point for each whole dollar by which twenty dollars ($20.00) exceeds the reference price for crude oil for the calendar year proceeding the tax year in which the taxpayer’s tax year begins. However, the enhanced allowance cannot exceed twenty-five percent (25%) even if the reference price falls to nine dollars ($9.00) per barrel or below. To qualify for the enhanced rate, a well must either produce heavy oil or be a “stripper well” producing less than an average of fifteen (15) barrel equivalents of oil and natural gas production per day. Stripper wells are tested by dividing the average daily production from all producing wells on the property. Whether wells on a property qualify as stripper wells is determined year by year based upon the production from such wells during that calendar year.

It should also be noted that depletion deductions generally constitute items of tax preference for purposes of determining alternative minimum tax liability, to the extent they exceed the taxpayer’s basis in the property to which they relate; however, the ‘92 Act largely repealed such item of tax preference for independent oil and gas producers (but not royalty owners). See the discussion of the alternative minimum tax below. With respect to properties acquired and placed in service after December 31, 1986, the Act requires that all depletion claimed which reduced the taxpayer’s basis in such a property be recaptured as ordinary income upon the taxpayer’s disposition of the property. This provision will have the same effects as the provision requiring recapture of excess deducted IDCs, which was discussed above.


Capital Costs.


The cost of pumping equipment, storage tanks, casing and tubing, and other tangible property cannot be deducted as incurred, but must instead be capitalized and recovered through depreciation in the manner permitted by the Code. Property acquired and placed in service will be subject to MACRS (Modified Accelerated Cost Recovery System). MACRS provides for depreciation of most equipment of the type to be acquired over a seven year period, using the 200% declining balance method and the half year convention, switching to straight-line at the point such switch becomes advantageous. The straight line method may also be utilized over either the MACRS period or certain alternate periods and the 150% declining balance method switching to straight line at the point where such switch becomes advantageous may also be used. The latter method is the method required to be utilized for computing alternative minimum tax taxable income. The adjustment arising from the excess of the depreciation allowance determined by utilizing MACRS (200% db) over the 150% declining balance method is similar to a tax preference item as it adjusts the taxable income upon which the alternative minimum tax is based. The method of depreciation to be utilized by Participants should be determined by their individual tax advisor.

Code Section 179 allows certain taxpayers to elect to expense (rather than depreciate) certain qualifying property. The taxpayers entitled to so elect are generally all taxpayers other than trusts, estates and certain non-corporate lessees. The property qualifying is generally property which would have qualified for the investment tax credit prior to its revocation and which is utilized in the conduct of an active trade or business. The IRS, through Revenue Rulings, had, prior to the Act, recognized undivided fractional interest oil and gas investments to be trade or business activities for purpose of Code Section 179. However, the Act added an additional requirement in that the property must now be used in the “active conduct of a trade or business.” The meaning of “active conduct of a trade or business” is not reflected in the legislative history for the amendment; however, regulations have been issued which clarify such usage. The regulations state that the active conduct requirement is to prevent a passive investor in a trade or business from deducting section 179 expenses against the income derived from that trade or business. The regulation further provides that “Consistent with this purpose, a taxpayer generally is considered to actively conduct a trade or business if the taxpayer meaningfully participates in the management or operations of the trade or business.” Although most oil and gas tax commentators appear to believe that property placed in service under a program such as this Program qualifies as qualifying property, it is questionable whether the activities of Participants will be sufficiently “active” to qualify the Program’s depreciable tangible personal property for the election. Each Participant should consult his own tax advisor concerning the availability of the Code Section 179 election with respect to the equipment contemplated to be purchased and placed into use by the Program.

Provided the equipment contemplated to be placed into service by the Program does qualify for the Code Section 179 election, the maximum dollar limitation of Code Section 179 property which may be expensed per year per investor is the lesser of (a) Dollar Limitation Amount or (b) the investor’s income for the tax year derived from the active conduct by the taxpayer of any trade or business. The Dollar Limitation Amount in the current calendar year is $105,000. Such limit is a per investor/taxpayer limit with the result that the investor’s share of the Program’s equipment must be aggregated with all other Code Section 179 property, then the limit applied to such aggregate Code Section 179 property. Unused Code Section 179 deductions which could not be taken due to the application of the net income allocation can be carried forward to succeeding taxable years.

Code Section 263A sets forth “uniform capitalization” rules. These rules apply to all property constituting inventory, and to real and tangible personal property produced by a taxpayer and used in a trade or business or held for the production of income. They require the capitalization (or inclusion in inventory costs, as the case may be) of the direct costs of producing such property, and of such property’s “proper share” of those indirect costs allocable to such property. They also apply to and require the capitalization of certain construction period interest costs, including those associated with real property.

There is an express exemption from the uniform capitalization rules for costs covered by the IDC election; however, other costs associated with the exploration and development of an oil and gas well which are not subject to the IDC election would appear to be subject to the uniform capitalization rules. There are special rules under 263A(f) relating to the capitalization of interest. The Regulations issued under such subsection expressly mention the drilling of an oil and gas well as being subject to the uniform capitalization rules. There is an exception to the requirement to capitalize interest if the property is either (a) constructed within 90 days or (b) the total costs in the property’s production do not exceed $1,000,000 divided by the number of days in the production period. It is not clear whether the Program’s Well(s) will qualify under either of those exceptions.


Limitations on Investment Interest Deductions.


The Code limits the amount of interest paid on funds borrowed to acquire or carry investment assets which may be deducted by a non-corporate taxpayer. In general, a non-corporate taxpayer may deduct such interest only to the extent it does not exceed such taxpayer’s net investment income for the taxable year. Excess investment interest is subject to an unlimited carryover and may be deducted in subsequent years, subject to the same general limitation. Investment interest includes interest attributable to indebtedness that is incurred to acquire an interest in an activity involving the conduct of a trade or business which is not a passive activity and in which the taxpayer does not materially participate. Interest attributable to indebtedness incurred by a Participant to purchase Units may constitute investment interest.


Syndication Expenses.


Costs associated with the offer and sale of Units may neither be deducted as incurred nor capitalized and recovered through amortization; however, it appears proper and permissible to add such costs to the leasehold cost and thereafter potentially recover such costs through cost depletion or as an abandonment loss. Such costs, which typically represent a substantial percentage of the amount of funds raised, include selling commissions and expenses and legal fees paid in connection with the offer and sale of units. Syndication expenses, other than selling commissions and due diligence fees, incurred in connection with the Program will be incurred by the Company. However, such commissions and fees will be paid from the Participants’ funds, and certain other expenses which arguably constitute syndication expenses may be paid from the funds. The Company will use its best efforts to properly determine the correct amount of syndication expenses borne by the Participants, but there is no assurance that the IRS will not challenge the Company’s determinations, or attempt to classify as syndication expenses costs classified and accounted for differently by the Company. Any such action, if sustained by a reviewing court, would reduce the tax benefits available to Participants.


Gains and Losses from Sale of Property.


Each Participant will be able to sell his interest in the Well, subject to restrictions otherwise discussed in the Memorandum. Upon a sale or other disposition of interest, a Participant will realize gain or loss equal to the difference between his adjusted basis in his interest in the Well at the time of sale or disposition, and the amount realized upon the sale or disposition. When a sale or other disposition occurs, all of the deducted IDCs, depletion deductions reducing basis, and cost recovery deductions taken pursuant to Code Sec. 168 will, to the extent of any gain, be subject to recapture and treated as ordinary income. Any gain in excess of recapture will constitute gain described in Code Sec. 1231 if the property sold or otherwise disposed of either was used in the Participant’s trade or business and held for more than one year, or was a capital asset which was held for more than one year and not held primarily for sale to customers. Under Code Sec. 1231, if the sum of the gains on sale or exchange of certain assets (generally, depreciable property other than inventory and literary properties, used in a trade or business and held for more than one year) and the gains from certain compulsory or involuntary conversions exceed the losses on such sales, exchanges and conversions, all such gains and losses will be treated as capital gains and losses. If such losses exceed such gains, however, all such losses and gains will be treated as ordinary gains and losses. If there is a net Section 1231 gain within five years after a net Section 1231 loss, the net gain is re-characterized from long term capital gains to ordinary income to the extent of the net Section 1231 loss. In effect, the loss is recaptured through re-characterizing what would otherwise be capital gain as ordinary income.


Abandonment Loss.


If it is later determined that the Well(s) is not capable of production in Commercial Quantities, the Well(s) will be plugged and abandoned. Under Treas. Regulation 1.612-4(b)(4), if a working interest owner has not elected to deduct IDCs, the working interest owner has an option to deduct the IDCs as an ordinary loss. Such election, if made, is binding on the taxpayer for all future wells and for all future years. To make such election, the taxpayer must make a clear statement of the election in the first tax year in which the taxpayer has a nonproductive well. If a taxpayer has not made such election or cannot make such election because the taxpayer has made the election to deduct IDCs, a taxpayer must deduct the taxpayer’s remaining basis in the well (lease) under Code Section 165. All taxpayers must utilize Code Section 165 to deduct the portion of nonproductive well costs which do not constitute IDCs. Under such Code Section, a taxpayer is entitled to deduct for federal income tax purposes any loss he sustains when a property he is holding for business purposes or for investment loses its useful value. Recently there have been several judicial decisions which limit or restrict the ability to claim abandonment losses under Code Section 165 for a plugged and abandoned well if any interest is retained in an oil or gas lease on which the well was drilled. Since the Participants would retain no interest in the lease if the Well was plugged and abandoned, the plugging and abandonment of the Well should be such a deductible loss. The amount of the loss is an amount equal to the abandonment cost and remaining unrecovered leasehold, IDCs, and equipment cost, less salvage recovered.

The loss allowable when an oil and gas property becomes worthless has traditionally been understood and held to be deductible as an ordinary loss although the property was a capital asset in the hands of the taxpayer. That doctrine was re-examined by the Tax Court during 1982 and there is now authority to the effect that a loss on abandonment of real property is a capital loss rather than an ordinary loss. Many commentators, however, continue to view a worthlessness loss (including a loss on abandonment of a mineral interest) as an ordinary loss on the theory that no “sale or exchange” has occurred, and Section 165(f) (dealing with capital losses) refers to “sales or exchanges of capital assets.” Moreover, in some cases, a loss from real property may be a Section 1231 loss, subject to the special rules of such section. It would appear, although it is not well established, that the lease and the equipment thereon are Section 1231 assets which do entitle Participants to an ordinary loss; however, due to the lack of recent precedent with respect to the characterization of the abandonment loss, the Company’s accountants are unable to opine with respect to the character (capital loss or ordinary loss) of the abandonment loss. The abandonment loss is not an item of tax preference; whereas, deducted IDCs are items of tax preference. Participants should therefore consult their individual tax advisors for the result most favorable for them, should the Well be determined to be nonproductive if a Participant has not made prior binding elections with respect to the deduction of IDCs and the write off of IDCs on nonproductive wells.


The Alternative Minimum Tax.


Code Section 55 imposes on taxpayers other than corporations an alternative minimum tax on certain “items of tax preference” (Code Section 56 imposes a similar tax on corporations). The alternative minimum tax (“AMT”) is intended to assure that high income taxpayers taking advantage of certain tax benefits pay some tax. The AMT is imposed on “alternative minimum taxable income” in excess of an exemption amount and is payable only if the AMT exceeds the taxpayer’s regular income tax liability. “Alternative minimum taxable income” (“AMTI”) means the taxpayer’s taxable income for the taxable year adjusted in certain ways as provided in Code Sections 56 and 58, then increased by certain “items of tax preference,” or “preferences”, and reduced by the exemption amount. The (2012) exemption amount is $45,000 for joint returns, $33,750 for single returns, and $22,500 for married separate returns; however, the exemption amount is subject to reduction by 25% of the excess of alternative minimum taxable income over $150,000 (joint returns), $112,500 (individual returns), or $75,000 (married separate returns). The rate on AMT is 26% on the first $175,000 of AMT for joint returns ($87,500 for singles) and is 28% of AMT in excess of $175,000 ($87,500 for singles). In the case of married individuals filing separate returns, alternative minimum taxable income is increased by the lesser of (a) 25% of the excess of alternative minimum taxable income over $165,000 or (b) $22,500. Thus, the effect of the AMT rules is essentially to impose a flat tax, at a rate of 26% to 28%, on a taxpayer’s taxable income computed without considering the benefits of his tax preferences, and to subject him to liability for that tax to the extent that it exceeds his regular tax liability.

The Program may produce two deductions which constitute preferences, excess deducted IDCs and depreciation deductions which exceed the deductions which would be allowable under the 150% declining balance method. “Excess” deducted IDCs (subject to potential reduction pursuant to an exception discussed below), to the extent they exceed 65% of the taxpayer’s net income from oil and gas properties, constitute an item of tax preference. “Excess” deducted IDCs are the IDCs deducted within a taxable year over the IDCs which would have been deductible had the taxpayer chosen to capitalize his IDCs and recover them under Code section 57 (i.e., over a 120-month period beginning with the month in which production from such well begins or under the cost depletion rules) (“the excess IDC preference”). However, under Section 59(e) of the Code, IDCs may be elected to be allowed as a deduction ratably over a 60-month period beginning with the month in which the IDC expenditure was paid or incurred. If such an election is made, no portion of such IDC deduction constitutes a tax preference.

Through a new exception to Code Section 57(a)(2) (the IDC tax preference paragraph of the Code), the tax preference for “excess” deducted IDCs has been effectively eliminated for most taxpayers other than integrated oil companies. The exception states that the IDC tax preference paragraph shall not be applicable to any taxpayer which is not an integrated oil and gas company but then limits the reduction in alternative minimum taxable income resulting from application of the exclusion to 40% of the tax year’s alternative minimum taxable income determined without regard to the exception and the alternative minimum tax net operating loss deduction. The effect of such exception will be to eliminate the IDC tax preference for most taxpayers who are not integrated oil and gas companies and to substantially reduce the IDC tax preference for the remaining taxpayers who are not integrated oil and gas companies.

The itemized deductions allowable in computing alternative minimum taxable income include charitable contributions, casualty and theft losses, medical expenses in excess of ten percent (10%) of adjusted gross income, qualified housing interest, and other interest expense to the extent of the taxpayer’s “qualified net investment income,” which is essentially the excess of investment income over investment expenses. In addition, it should be noted that net loss from a passive activity constitutes a tax preference item. Many other deductions constitute preferences which must be taken into account in determining alternative minimum tax liability. The effect of the AMT rules on the Program may be to reduce the value of the tax benefits of investment. Participants in the Program to whom such benefits are material should consult their personal tax advisors regarding the application to them of the AMT rules before investing.


The At Risk Rules.


Code Section 465 limits the amount of loss a taxpayer other than a non-closely held corporation can deduct in connection with, among other things, exploring for and producing oil and gas, to the amount the taxpayer has “at risk” in the activity as of the end of the taxable year in which such loss is incurred. The amount at risk in connection with a given activity includes only (a) the amount of money contributed by the taxpayer to the activity; (b) the adjusted basis of any property other than money contributed by the taxpayer to the activity; and (c) any amount borrowed with respect to the activity for the repayment of which the taxpayer is personally liable, or with respect to which he has pledged property not used in the activity, to the extent of the net fair market value of his interest in the property. However, a taxpayer is not at risk with respect to amounts borrowed from a person who has an interest in the activity other than that of a creditor, or who is a related party, and is not at risk with respect to any amount as to which he is protected against loss by a guarantee, stop-loss agreement, or similar arrangement. Losses permitted under the at risk rules, reduce a taxpayer’s amount at risk with respect to the activity generating the losses, as do cash withdrawals from the activity. If a taxpayer’s amount at risk with respect to an activity is reduced below zero, recapture of losses previously taken with respect to the activity at ordinary income rates is required to the extent the amount at risk is reduced below zero. It is not anticipated that any deductions attributable to the Program, which would otherwise be currently allowable, will be limited by the at risk rules.


Allocation of Costs.


As can be seen, the funds paid by Participants for the Units of Working Interest in the Program will be expended in a variety of ways, and the tax treatment and consequences of each of which will vary materially. For purposes of tax accounting, the funds must be allocated among the various items. In so doing, the Company will use its best efforts to make such allocations in a manner in accordance with the economic substance of the Program’s activities. However, there can be no assurance that the IRS will not challenge the allocations or that any such challenge will not be sustained by a reviewing court. Any reallocation could materially reduce the tax benefits expected to be available to Participants in connection with an investment in the Program.


Accuracy Related Penalties.


The Code contains provisions designed to discourage participation in tax-advantaged transactions. Code Section 6662 imposes an accuracy-related penalty of twenty percent (20%) on the portion of any income tax underpayment attributable to (a) negligence or disregard of rules and regulations, (b) a substantial understatement, (c) a substantial overvaluation statement under Chapter 1 of the Code or (d) certain pension and estate and gift tax matters. “Negligence” for purposes of this Section means any failure to attempt to comply with the Code. “Disregard” includes any reckless, careless or intentional disregard of the Code or Regulations. For purposes of this Code Section, an understatement means the amount by which any tax exceeds the excess of (a) the sum of (1) the amount shown as the tax by a taxpayer on his return plus (2) amounts not shown as tax that were previously assessed, less (b) the amount of rebates made. The term rebate means that portion of an abatement, credit, refund or other repayment as was made on the ground that the tax imposed was less than the excess amount shown as tax on a return and amounts not shown as tax that were previously assessed or collected over the rebates previously made. “Substantial understatement” for purposes of such Code Section means an understatement of tax liability which exceeds the greater of (a) five thousand and no/100 dollars ($5,000.00) ($10,000.00 for a corporation) or (b) ten percent (10%) of the required tax.

Code Section 6664 provides potential relief from the Section 6662 accuracy related penalty and the Code Section 6663 fraud penalty if the taxpayer is able to show that there was reasonable cause for the underpayment and that the taxpayer acted in good faith. In addition, under Code section 6662(d)(2), a portion of the understatement for purposes of the substantial understatement penalty can be eliminated in determining whether a substantial understatement has occurred if certain criteria are satisfied. Facts relevant to the tax treatment of the item must be adequately disclosed on the return and the taxpayer must have a “reasonable basis” for the tax treatment of the item. If the item causing the understatement is attributable to a “tax shelter” not only must there be substantial authority for the taxpayer’s position, but the taxpayer must also reasonably believe the position was “more likely than not” the correct position. In order for disclosure to be sufficient under the Regulations, the disclosure with respect to the questionable item must generally be made on Form 8275 or, if with respect to a position contrary to a Regulation, on Form 8275R. The Company, with the aid of its tax advisors, intends to suggest to Participants disclosures which should be made by them. However, there can be no assurance that the IRS will agree with the disclosures or the adequacy thereof. Therefore, should the IRS disagree with the positions taken on the Participants’ income tax returns, and be sustained, and disagree with the adequacy of disclosure, and be sustained, a penalty under Code Section 6662 could be imposed. Code Section 6663 imposes a 75% fraud penalty if any portion of an underpayment (not just the fraudulent portion) is due to fraud.


Tax Shelter Registration.


Code Sections 6111 and 6707 deal with the registration with the IRS of “tax shelters.” Code Section 6111 defines as a “tax shelter” any investment with respect to which it could reasonably be inferred from representations made in connection with the offer of interests in the investment that, as of the close of any of the first five years after the investment, the aggregate tax benefits available to an investor are more than twice the amount invested, and which meets certain other criteria. Any “tax shelter” investment is required to be registered with the IRS prior to the offer for sale of interests in the investment. Registration results in the assigning to the investment of an identification number, which must be provided by the promoter to each Participant, and must be included by each investor on his tax return for any year in which he claims tax benefits in connection with the investment. This provision is intended to assist the IRS in locating and examining tax shelters and the tax returns of persons who invest in tax shelters.

Section 6707 sets forth penalties for failure to comply with the requirements of section 6111. While those penalties generally are applicable to the promoter and its officers, employees, and agents, a penalty of $250.00 can be collected from any Participant who, without reasonable cause, fails to include on his return a required tax shelter identification number.

For purposes of determining whether an investment is a “tax shelter,” income earned from the investment is ignored. The temporary regulations take a comprehensive position with respect to “represented benefits” and do not require a projection within the offering of represented benefits; a simple mention is apparently sufficient. Therefore, the discussion contained within the tax matters portion of the memorandum is probably a representation for such purpose. However, the Company does not project the aggregate tax benefits over the first five (5) years of the Program to be more than two (2) times the investment in the Program. For these reasons, the Company does not intend to register the Program with the IRS as a tax shelter under section 6111. However, there is no assurance that the IRS will not challenge this position and seek to impose penalties against the Company and the Participants under section 6707. The imposition of any such penalty against the Company could damage it financially and reduce its ability to discharge its obligations to Participants.


Self-employment Tax.


All or a portion of a Participant’s share of income from the Well(s) may constitute “self-employment income” subject to self-employment tax. A prerequisite to the existence of self-employment income is the existence of a trade or business. In Hendrickson v. Commissioner, T. C. Memo. 1987-566, the Tax Court held that a minority working interest in a gas well did not constitute a “trade or business: and did not create self-employment income, where the taxpayer did not actively participate in management and was not experienced in oil and gas matters. However, in Coke V. Commissioner, 91 T. C. 222 (1988), and in other cases, the Tax Court held that the existence of a “trade or business” for self-employment tax purposes is determined at the Company level, and that a partner’s share of Company income may be self-employment income even if the partner does not actively participate in the trade or business of the Company.

Under Coke’s and other cases, if the Participants are deemed to be engaged in a trade or business, their earnings from the trade or business would be treated as earnings from self-employment. The factors that will apply in determining whether an investor is engaged in a trade or business for self-employment tax purposes will include, among other things, whether he acquires operating working interests in oil and gas properties as opposed to non-operating working interests; whether he acquires large enough percentage working interests to substantially affect management decisions; and whether he acquires numerous properties or just a few properties. There is therefore not a clear answer as to whether income from the Well will be treated as income subject to self-employment tax for Participants; however, no state law Company should be in existence nor should the interests be considered a Company for federal income tax purposes. Therefore, it would appear that the Participants should not be considered to be engaged in a trade or business for self employment tax purposes.

In view of the inherently factual and prospective nature of the relevant factors and the uncertain state of the law regarding what constitutes a trade or business, counsel can render no opinion, favorable or unfavorable, concerning whether the Participants will be engaged in a trade or business for self-employment tax purposes. Accordingly, counsel has rendered no opinion, favorable or unfavorable, concerning whether their earnings from the Well will be treated as earnings from self-employment. The self-employment tax rate on self-employment income is 15.3% on the benefit base amount and 2.9% on the excess over the benefit base amount. Wages earned in the same tax year reduces dollar for dollar the benefit base amount upon which self-employment taxes at the 15.3% rate are payable; however, all self-employment income in excess of the benefit base amount is subject to the 2.9% rate.

A Participant who is younger than age 70 and who is receiving social security benefits will suffer a reduction in his social security benefits if he has “excess earnings” for the year which ordinarily includes self-employment income. However, except for the first year in which a Participant becomes entitled to social security benefits, self-employment income derived from the Well (or other sources) will not constitute earnings for this purpose if such income is not attributable to services performed by the Participant after the first month he became entitled to social security benefits.


Possible Changes in Tax Laws.


Changes in specific provisions of the Code are certainly possible, and any such changes could apply to the Program and its Participants. As of the date of this Memorandum, Congress is considering further changes to the Code in connection with addressing the federal budget deficit. Any changes actually enacted could materially affect the tax consequences of investment in the Program. As the foregoing discussion demonstrates, the Act and subsequent acts have substantially changed federal tax law. Many of the new provisions are, pending administrative and judicial construction, uncertain in their application to specific transactions. Thus, to the extent that such provisions will or may apply to the Program and its Participants, the effect of passage of the new provisions has been to increase the uncertainty of the tax consequences of investment in the Program. Participants who deem the tax consequences of investment in the Program to be material to the investment decision are urged to consult their personal tax advisors before making that decision.


Conclusion.


This summary is not intended to substitute for consultation with personal tax advisors or detailed tax planning. Each Participant in any Program should consult his personal tax advisor concerning the effect on him/her of investment in the Program under the federal income tax law, applicable state tax laws, and the windfall profit tax, prior to invest in the Program.