DOE DRILLS HILL AUDITORS ON ENERGY CREDITS.

SUMMARY:

Summary

The Department of Energy believes that tax policies substantially influence investment decisions in the oil industry. DOE fully supports the oil and gas tax incentives proposed by the President and submitted to Congress earlier this year as part of the Administration's FY 1991 budget.

Domestic oil production has continued to decline during the past year, with the average rig count dropping to its lowest level in 50 years. Imports accounted for 42 percent of U.S. oil consumption in 1989 and are projected to increase to 54-67 percent by 2010. Although domestic natural gas production increased in 1989, average wellhead prices remain at low levels.

The General Accounting Office has recently issued a report titled "Additional Petroleum Production Tax Incentives Are of Questionable Merit." The Department strongly objects to the conclusions of the GAO report and to the methodology used in the GAO analysis. DOE rejects the view that producers of exhaustible resources should be subject to the same capital recovery rules as other industries.

The DOE also disagrees with GAO's view that U.S. producers have shifted a significant portion of their exploration activity abroad almost exclusively because of non-tax factors, primarily lower finding costs and more favorable geology. The Department of Energy believes that while geology and finding costs play an important role in the industry's investment strategies, the regressive U.S. tax system is also a factor. The U.S. system compounds the burden of declining prices by taking an increased share of income through revenue-based taxes and royalties, and through the AMT.

The President's proposed tax incentives are designed to encourage exploration for new oil and gas fields, and to encourage continued operation of existing fields. The five proposals, taken together, could add an estimated 172,000 to 196,000 barrels per day of domestic production. This additional production would represent a reduction in our trade deficit of $1.1 billion to $1.3 billion per year (assuming $18/bbl oil).

The President's proposals deserve Congressional attention because they will help to slow the steady deterioration of domestic production.

Statement of Vito Stagliano

MARKET CONDITIONS AND TRENDS

OIL

U.S. crude oil production continued to decline in 1989, falling 527,000 b/d below the 1988 average. Natural gas liquids production fell 79,000 b/d, reversing a two year trend of increased production. Since the lows reached in 1986, crude prices have increased and appear to be staying in the $17 to $20 per barrel range. Future oil price are expected to increase but remain volatile. This, coupled with relatively marginal prospects for large new discoveries, explain the expected decrease in U.S. production. Reduced U.S. exploration activity, combined with high abandonment rates, indicates that further production declines can be expected. The average U.S. rig count for 1989 hit its lowest point in almost fifty years. U.S. companies are now concentrating more of their exploration activities overseas where prospects tend to be more lucrative.

Alaskan production also has declined, indicating that the Alaskan North Slope, as presently developed, has passed its peak production. Proposals to open the coastal plan of the Arctic National Wildlife Refuge are on hold. Environmental concerns raised by oil spills have had a negative impact on plans for offshore oil development.

The U.S. imported 42 percent of its petroleum consumption in 1989, or over 7 million barrels per day. This figure is projected to increase in the next few years, as domestic production continues to decline. For the first 5 months of 1990, net imports have increased over 6 percent from the first 5 months of 1989.

Long term trends in U.S. oil imports are unsurprising given current market conditions, geologic prospects, and policy. The U.S. is the oldest developed oil province in this world and has been extensively explored. New reserve additions, in the form of major new fields, can only be expected from the Outer Continental Shelf (OCS) and the Alaskan Arctic.

EIA forecasts oil imports to increase from 7.2 million barrels per day (MMBD) in 1989 to between 10.4 and 14.9 MMBD in 2010, depending on oil price paths and U.S. economic growth. The EIA base case projects world oil prices to rise from $17.70 in 1989 to $36.90 in 2010 (in 1989 dollars per barrel), and assuming a GNP growth rate of 4.1 percent per annum. The highest historical level of annual net imports was reached in 1977, at 8.6 MMBD, or 46.5 percent of consumption. The EIA forecast for 2010 shows import dependence of 54 to 67 percent.

EXPLORATION AND PRODUCTION:

The President has decided to postpone oil and gas exploration in several environmentally sensitive offshore tracts. A broader moratorium is being considered by Congress. These leasing restrictions reflect increased concern about environmental and socio-economic impacts of OCS development. In the event of a foreign supply disruption, leasing of the prohibited areas could be allowed to resume for national security purposes.

The recent success of horizontal drilling has been an important development for the domestic oil industry. In many cases it has significantly increased recovery rates by allowing more of the oil reservoir to be exposed to the well bore. Production from enhanced oil recovery also continues to increase, albeit slowly, despite low oil prices. These improved recovery methods should help to slow the rate of decline in oil production during the 1990's, particularly if the increases in oil prices projected by EIA materialize.

NATURAL GAS

Domestic natural gas production increased from 16.0 trillion cubic feet (TCF) in 1986 to 17.1 TCF in 1989, thereby reversing an intermittent decline that had been occurring since 1973. Total oil and gas well completions for 1989 are estimated at 28,340, the lowest level since 1973 and dramatically below the 90,030 all time record high reached in 1981. Gas wells completed in 1989 numbered 9,500.

Natural gas consumption was nearly 19 TCF in 1989, an increase of 16% over 1986 consumption. This increase is due mainly to market conditions characterized by excess supply capacity and low wellhead prices. The average annual wellhead price, which was $2.57/MCF in the 1982-1984 period, fell to about $1.71/MCF in 1989. June 1990 natural gas spot prices averaged $1.39/MCF.

Future natural gas consumption prospects are tied to deliverability and demand, and are not constrained by the domestic resource base. A 1988 DOE study of the natural gas resource base concluded that the Nation has about a 35 year supply at wellhead prices of $3.00/MCF or less. Higher prices would expand the supply significantly.

The electric utility sector is expected to be the fastest growing market for natural gas, according to EIA forecasts. From 15% of natural gas use in 1989, the utility industry is projected to increase its consumption share to 28 percent in 2010 under most economic growth scenarios.

Over the same forecast period, EIA projects wellhead prices rising from $1.71 in 1989 to between $4.57 and $6.09 in 2010, with higher consumption producing the higher price. Imports from Canada are expected to increase during the forecast period from 76 TCF in 1989 to 1.53 TCF in 2010. LNG imports are also projected to rise from less than 100 billion cubic feet in 1989 to about 800 billion cubic feet in 2010, according to the EIA.

ROLE OF TAX POLICY IN DOMESTIC OIL PRODUCTION

Mr. Chairman, earlier this year, the General Accounting Office provided to the DOE an opportunity to comment on a draft report titled "Additional Petroleum Production Tax Incentives Are Of Questionable Merit." The Department strongly objected to the conclusions of the GAO report, which was released in final form this week, and to the methodology used in the GAO analysis.

The GAO raised a number of issues that are critical to understanding the structure of the oil and gas industry, and of the effects of tax policy on industry operations. I will discuss a number of these issues for the purpose of illuminating DOE's and the GAO's radically different perspectives.

The GAO asserts that the petroleum industry, and other producers of exhaustible resources, should be subject to the same capital recovery rules as other industries. DOE believes that oil and gas reservoirs are fundamentally different from the plant and equipment that constitutes capital for other industries, in that their replacement presents a higher degree of risk. New field wildcat wells resulted in dry holes in 86% of the cases in 1986-88, for example. Few other industries are required to make investments involving such a high degree of risk.

The GAO maintains that the current regular tax and alternative minimum tax (AMT) treatment of intangible drilling costs (IDCs) constitutes an overly generous tax preference for the oil industry. DOE disagrees. Any advantage gained by the IDC deduction, for regular tax purposes, is substantially reduced by the addback provision of the AMT. The AMT is paid by three fourths of all independent producers.

Another GAO contention is that the oil industry in general pays much lower effective marginal tax rates than other industries. But according to the 1988 Energy Information Administration Performance Profiles of Major Energy Producers, the average effective corporate income tax rates on the worldwide operations of U.S. energy companies continuously have exceeded those for Standard and Poor's 400 companies since 1974, except in 1988 when the rates were equal. EIA reports in the same publication that the effective income tax rate of the DOMESTIC petroleum industry production sector was 39% in 1988, including Federal and State income tax.

The EIA study focuses on major companies and on average tax rates, as calculated for financial accounting purpose. As pointed out by the GAO, average tax rates differ from marginal rates. However, we believe that a comparison of average tax rates, from actual data, is at least as instructive as GAO's comparison of marginal rates.

Finally, the GAO believes that producers have shifted a significant portion of their exploration activity abroad almost exclusively because of non-taxation factors, such as lower finding costs and more favorable geology. The Department of Energy believes that while geology and finding costs play an important role in the industry's investment strategies, the U.S. tax system is also a factor. Mr. Chairman, the matter of comparability of international tax policy is an important issue. We have been giving this matter considerable thought and will continue to analyze it in the months ahead. A number of factors are known about the U.S. system of "take" and about the systems used in some other countries.

When oil prices decline, the U.S. system compounds the burden on U.S. oil companies by taking an increased share of income. This results from two factors: the relatively greater U.S. reliance on a revenue-based taxation and royalty system, and the effect of the alternative minimum tax (AMT). Although royalty payments and State severance taxes are not under Federal control, they can constitute a larger share of cash flow than do income taxes, as shown in the graph at the end of my statement.

As a result of the AMT, the benefits of the tax treatment of IDC's, and their intended incentive effects are diminished. As a consequence, the oil industry may have become more cyclical and less efficient. It is for this reason that the President has proposed the elimination of 80% of the current AMT preference for exploratory IDCs.

Only in the U.S. do companies pay both a "royalty" to a landowner and a severance tax to State governments. Severance taxes range from 0.1% in California to 15% for parts of Alaska, and average 5.8% on a production-weighted basis. Some states have variable rates (Louisiana, Alaska); others have fixed rates regardless of production volume. Among the latter are Oklahoma, Texas and New Mexico. Noteworthy is the fact that NO state varies its severance tax rate to reflect changes in the price of oil.

By contrast, the Canadian tax and royalty system, for example, has made use of temporary royalty holidays and flexibility of rates to encourage new exploration and development. The Canadian Federal Government receives NO royalty payments, and the provinces set their royalty rates on the basis of production levels, current prices and well vintage.

The United Kingdom has rescinded the use of royalty payments on new leases in order to encourage exploration, and has placed a limit on the amount of petroleum revenue taxes (PRT) payable in order to promote new fields and efficient drainage of old fields.

The U.K. system also exempts from the PRT up to the first 77 million barrels of oil produced in each new field.

Norway's system of "take" is based solely on income and special profits taxes, with no revenue based taxes or royalties for new fields. Ecuador levies no royalties but collects its share of revenue from oil production, less reimbursed costs.

Another provision of the U.S. tax code that reduces the intended incentive for exploration, when oil prices are low, is the 50% net income limitation on percentage depletion for independent producers. This tax reduces benefits when they are most needed; that is, when income is low due to increased costs, falling production, or lower oil prices. This provision encourages early abandonment of marginal wells that, by definition, have low income.

The best evidence in favor of the President's energy tax proposals is industry's performance since the 1985 oil price collapse. Since 1985, U.S. exploration activity has declined far more rapidly, and has remained lower, than exploration in other countries. Since the relative difference in geology has not changed appreciably during this period, and since relative finding costs have actually DECLINED in the U.S., it is reasonable to assume that cost-effective tax changes can encourage an increase in U.S. oil exploration and production.

On the investment side, in response to rising oil price expectations in 1989, domestic exploration and development expenditures in 1990 are expected to be about $13.5 billion, an increase of about 7% over the previous year. Spending overseas by U.S. majority owned affiliates is expected to rise 25%, to nearly $8 billion. This recovery comes after the precipitous decline in exploration spending that occurred between 1981 and 1988, when crude oil lost over 60% of its value. In 1981, domestic exploration expenditures were nearly $40 billion, and overseas spending was nearly $10 billion. Cost-effective modifications of tax policy can play a role in improving the relative profitability of domestic investments.

Another indication of the relatively large decrease in domestic exploration is found by comparing domestic and international rig counts over the past 14 years. The U.S. rig count is far more sensitive to prices than the international rig count. Since 1981, when oil prices reached their peak, the rig count in the U.S. has dropped by 78 percent, while the international rig count has declined by 37 percent. The current system of "take" tends to magnify the effect of oil prices by imposing greater effective tax rates on low income producers than on high income producers. Thus, the combined State and Federal tax and private royalty payments may likely have discouraged U.S. exploration activity.

Historically, large increases in energy prices have spurred rapid growth in drilling investments. However, as the 1990 EIA Annual Energy Outlook points out, the oil price volatility that characterized the 1980's "has had a chilling effect on the responsiveness of investment to price changes." This is particularly true for independents who are far more reliant on external financing than are the majors. Prospects for increased drilling could nevertheless improve under the increased oil prices projected by EIA for the 1990's.

SUMMARY:

Many countries have responded to the drop in oil prices by reducing their "total take" in order to maintain a competitive oil and gas industry. Unlike the U.S., Canadian provinces offer progressive royalty rates that vary with price, production volume or costs. Norway has eliminated royalties on new licenses altogether. The United Kingdom allows no income taxes to be collected until all investment costs are repaid, thereby substantially decreasing investment risk.

The U.S. has taken no action in response to the decline in oil prices, other than to repeal the already useless Windfall Profits Tax. But the U.S. substantially reduced corporate tax rates in 1986.

THE PRESIDENT'S TAX INCENTIVES PROPOSAL

In February 1989, in order to begin the process of recovery in the U.S. oil and gas industry, the President submitted to Congress a number of tax incentives to encourage exploration for new oil and gas fields, and to encourage continued operation of existing fields. The program includes five proposals:

o Repeal of the prohibition on use of percentage depletion on certain transferred properties;

o A provision permitting independent producers to deduct from their income for alternative minimum tax purposes a larger portion of their exploratory drilling costs than currently allowed;

o An increase in the property net income limitation for the percentage depletion allowance;

o A temporary tax credit for certain exploratory drilling costs; and

o A temporary tax credit for new enhanced oil recovery projects.

The first proposal, repeal of the transfer rule, will aid in the preservation of existing production by extending the productive lives of numerous marginal wells, owned by major producers, and slated for abandonment because of high operating costs. Repeal would encourage the acquisition of marginal wells by independent producers, who could profitably operate the wells because of lower overhead costs and because of their access to the percentage depletion allowance.

The abandonment of existing wells is a critical problem. Over 18,000 wells are abandoned in the U.S. each year, making their remaining in-ground reserves virtually impossible to recover. It is important to recognize that only about one-third of the oil in existing fields is normally recovered. That leaves over 300 billion barrels still theoretically available, a volume which represents about twice as much oil as total U.S. cumulative oil production to date.

Once a well is abandoned, it is prohibitively expensive to unplug it and resume production with current technology. Furthermore, in many cases once the well ceases production, it is not possible to resume conventional production at any cost, due to infiltration of water into the reservoir. Repeal of the transfer rule, as well as the tax credit for new enhanced oil recovery projects and the proposed increase in the net income limitation, will help to discourage the premature abandonment of existing wells.

The second proposal is a modification of the treatment of exploratory intangible drilling costs (IDC's) for alternative minimum tax (AMT) purposes. Intangible drilling costs represent the portion of drilling costs with little or no salvage value. These costs usually amount to 75 to 85 percent of total drilling expenditures. Currently, independent producers can fully deduct IDC's when computing income subject to regular income taxes. However, an estimated three-fourths of all independents are now subject to the AMT. The AMT substantially reduces the advantage of deducting IDC's because a large part of IDC's is often added back to the producer's income in calculating the AMT.

The independent non-integrated producer is the most susceptible to swings in oil prices. If the proposal to modify IDC treatment were adopted, it would encourage additional exploratory drilling by independent producers, who historically account for an estimated 90 percent of all exploratory wells each year. The proposal would increase discoveries of new oil fields, which would add to our reserve base. The additional drilling induced by this proposal could eventually add an estimated 21,000 to 28,000 barrels per day of production.

The third proposal would benefit producers by allowing full use of percentage depletion by taxpayers with incomes that are low relative to their available depletion. The President's proposal recommends increasing the property income limitation. The advantage of this proposal is that the revenue specifically assists properties with low net incomes -- that is, marginal properties that may be close to abandonment.

The fourth proposal accelerates the recovery of capital outlays for exploratory drilling, reduces the net cost of finding oil and gas reserves, and provides a new source of funds which can be reinvested in domestic exploration. As a result of the credit, the overall level of geological and geophysical expenditures and development drilling will also increase.

The President's fifth proposal, which establishes a temporary tax credit for new enhanced oil recovery projects, would increase the level of new EOR production by approximately one-third.

The five proposals, taken together, could add an estimated 172,000 to 196,000 barrels per day of domestic production. This added production would reduce tanker traffic by approximately four large tankers (200,000 dead weight tons) per month. This added production would represent a reduction in our trade deficit of $1.1 billion to $1.3 billion per year (assuming $18/bbl oil).

Mr. Chairman, we believe that the President's proposals deserve Congressional attention because they will help to slow the steady deterioration of domestic oil production. We defer to the Department of the Treasury on the estimated budget impacts of these proposals, but believe they are cost effective.

This concludes my testimony and I shall be happy to answer any questions.

UNITED STATES ELEMENTS OF TOTAL TAKE

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