CHAPTER 9 STRUCTURING TRANSACTIONS WITH THE NONCONVENTIONAL SOURCE FUELS CREDIT (SECTION 29 CREDIT)
| Jurisdiction | United States |
(Sep 1991)
STRUCTURING TRANSACTIONS WITH THE NONCONVENTIONAL SOURCE FUELS CREDIT (SECTION 29 CREDIT)
Deloitte & Touche
Dallas, Texas
The nonconventional source fuels credit (the I.R.C. Section 29 credit) has generated a great deal of discussion in the last several months. Although the Section 29 credit has generated substantial benefits and spurred drilling activity in various parts of the country (including the San Juan Basin in New Mexico, the Black Warrior Basin in Alabama, and parts of the Appalachian Basin), many producers have found that they are not in a position to use the credit themselves. This is due to the fact that many producers have either insufficient taxable income or because they pay alternative minimum tax rather than regular tax. Opportunities do exist to enter into transactions with parties that can utilize these credits. This presentation examines those structuring opportunities.
Background
A tax incentive for high cost gas was originally conceived when Congress enacted the Natural Gas Policy Act of 1978, which required producers to choose between price incentives and tax incentives that were to be passed later1 . In 1980, Congress did provide a tax incentive for high cost gas and other fuels in the form of the alternative source fuels credit2 . The fuels that qualify for the credit include, among others, oil produced from shale and tar sands, and gas produced from geopressured brine, Devonian shale, coal seams or a tight formation.3
Pursuant to the Natural Gas Policy Act of 1978, tight formation gas that was not committed or dedicated to interstate commerce in 1977 was deregulated starting at the beginning of 19854 . The Federal Energy Regulatory Commission (FERC) subsequently ruled that certain tight formation gas that also qualified as deregulated gas under another provision of the Natural Gas Policy Act of 1978 was to be treated as deregulated5 . Because of the deregulated "taint," it would follow that the tax credit would not be available. The FERC ruling was upheld by the Supreme Court in 19886 . As a result of these and other such rulings, the Section 29 credit was effectively eliminated for most tight formation gas. The Revenue Reconciliation Act of 1990 reinstated tight formation production as a qualifying fuel. It limits qualification for the tight formation credit to gas produced after December 31, 1990, on wells drilled after the date of enactment (November 6, 1990), or which were dedicated to interstate commerce as of April 20, 19777 . The
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Revenue Reconciliation Act of 1990 also extended the sunset provision of the credit to qualified fuels produced and sold before January 1, 2003 on wells drilled or placed in service by January 1, 1993.8
Although much of the discussion in 1988 through 1990 involved coal seam gas, in 1991 there seems to be a great deal of interest in tight sands gas due to the change in law in December.
Mechanics of the Credit
The credit is available for sales of qualified fuels to unrelated persons9 . The amount of the credit is generally $3 per barrel-of-oil equivalent and phases out as the average wellhead price of decontrolled domestic oil rises from $23.50 to 29.50, adjusted for inflation10 . With the inflation factor, oil prices would have to exceed almost $40 per barrel before the credit would begin phasing out.
The credit is computed following the end of each calendar year for production sold during such calendar year. For 1990, the credit was $.87 per MMBtu of gas produced and sold to an unrelated party11 . The credit for tight formation gas is not adjusted for inflation and is fixed at $.52 per MMBtu12 . Based on most economic projections, the credit is not anticipated to phase out due to high oil prices.
The AMT Problem
Most producers that hold acreage positions in Section 29 property are struggling to get out of the Alternative Minimum Tax (AMT) trap that they have been in for several years. The fact that most of the producers' fundamental deductions (depletion, intangible drilling costs, depreciation) are not fully allowable under AMT, means that this is a long term problem.
The credit allowed may not exceed the excess of the regular tax over the tentative minimum tax for any taxpayer13 . Therefore, if the producer is already paying AMT
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(tentative minimum tax exceeds regular tax) they obviously have no use for the credit. However, a portion of any unused credit may be carried forward as an increase in the minimum tax credit to offset future regular tax liability14 . The portion that may be carried forward is the amount of nonconventional fuels credit that was disallowed for the tax year solely due to the limitation based on the taxpayer's tentative minimum tax.
Economic Risk
In order to qualify for the Section 29 credit the taxpayer must have an economic interest in the property15 . An economic interest is defined generally in the Regulations16 as any interest in the mineral in place secured by any form of legal relationship. The investor must look only to the income derived from the extraction of the mineral for the return of his capital17 . Under this definition, various property interests are generally considered economic interests such as working interests, mineral interests, overriding royalty interests, certain net profits interests and production payments not considered mortgage loans18 .
There are various risks in the typical oil and gas venture. There is risk associated with finding reserves, drilling, producing the oil and gas, delivering the oil and gas and the risk of price decreases in the oil and gas sold from the well...
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