CRS Report: -

Abstract

A depression in petroleum prices during 1998 and into the winter of 1999 brought calls for Congressional action to ameliorate some of the effects on U.S. independent oil and gas producers. Congress debated a number of policy responses. Ironically, much of this debate took place against the backdrop of a sharp recovery in oil prices, underscoring the complexity of addressing the perceived needs of troubled industries whose capacity and infrastructure cannot be quickly rebuilt after a sustained period of low prices.

This report reviews the Congressional debate over an oil and gas loan guarantee program (which became public law), tax provisions to help some producers (included in the Taxpayer Refund and Relief Act, H.R. 2488, vetoed by the President), and a plan adopted to replace oil sold earlier in the 1990s from the Strategic Petroleum Reserve (SPR) with royalty-in-kind payments from federal leases. Import quotas and tariffs, debate over rules changing how oil is valued for federal royalty purposes, allegations of oil dumping, and concern over the consequences of oil company mergers and consolidation are also discussed.

This report will be updated as new legislation and events occur.

A depression in petroleum prices from late 1997 until the spring of 1999 brought calls for congressional action to ameliorate some of the effects of low oil prices on independent oil and gas producers in the United States. Congress has debated a wide range of policy measures proposed to help small domestic crude oil and natural gas producers. This debate took place against a backdrop of a sharp recovery in oil prices. This underscored the challenge to policy makers to help troubled industries whose capacity and infrastructure cannot instantly rebound after a sustained period of low prices.

The most significant legislative proposal enacted was a loan guarantee program to provide up to $500 million to producers and to oil field service companies. The measure was signed (P.L. 106-51, H.R. 1664) on August 17, 1999.

Producers have also sought a number of tax benefits. The Taxpayer Refund and Relief Act of 1999 (H.R. 2488), passed by Congress but subsequently vetoed by the President, would have helped smaller domestic producers by allowing net operating losses for oil and gas properties to be carried back 5 years, instead of the current 2 years. Producers have also been concerned about a revision to the way oil produced on federal leases is valued for determining royalties owed by producers to the Treasury. Conferees on the Interior Appropriations bill (H.R. 2466) agreed that the General Accounting Office would study the rule.

The Department of Energy began accepting deliveries of oil for the Strategic Petroleum Reserve (SPR) in April 1999 as an "in-kind" royalty payment for production on federal leases. While the program was not expected to raise prices, it represented the first large-scale taking of royalties-in-kind, long sought by producers.

In late June 1999, a group of oil producers, Save Domestic Oil Inc. (SDO), filed antidumping and countervailing duty petitions with the U.S. Department of Commerce. The petitions contended that Saudi Arabia, Mexico, Venezuela and Iraq were selling oil in the United States below fair value and that producers and exporters in these countries were benefiting from government subsidies. The Department rejected the petitions August 9, 1999; the coalition has appealed the decision.

Not all producers seek government intervention. Some have sought cost-cutting measures, including mergers and other consolidations. But the merger trend raises policy questions, including the effect on competition and the viability of small oil enterprises. Some companies would rather move production to lower-cost regions abroad. Others are better positioned to wait for their circumstances to improve. Some have suggested considering options that address declining U.S. oil production directly rather than dealing with price volatility alone.

From 1997 to the end of 1998, refiner acquisition cost of crude oil fell from an average $23.59/barrel (bbl) to a low of $9.84/bbl.1 The price decline into 1999 was a factor contributing to a fall in domestic production of more than 500,000 barrels per day (b/d).

Other measures of reduced activity in the sector have been reported during 1999. The American Petroleum Institute (API) found during the period from late 1997 to early 1999 that the number of active rotary rigs drilling wells dropped from 371 to III. A survey conducted by Salomon Smith Barney showed a decline in domestic exploration and production spending from 1998 to 1999 of 23% among surveyed independents and 19% by fifteen major U. S. producers. Meanwhile, the Independent Petroleum Association of America (IPAA) reported in early February 1999 that 136,000 domestic oil wells were shut in between November 1997 and early 1999.2

Producers normally maintain facilities, even when crude prices decline to levels near or below the cost of production, on the expectation that prices will recover. However, if the decline is prolonged and deep enough, marginal production may be capped, maintenance may be cut back, new exploration suspended, and skilled employees eliminated. The result can be a loss of output and output capacity that may not be reconstituted when prices recover. Independent producers may be especially vulnerable during this sort of downturn because, more often than larger firms, they have onshore properties with relatively low output.

By late 1998, there were calls on Congress and federal agencies to assist the domestic oil and gas industry to weather the slump in prices that seemed to have little prospect of ending soon. While low oil prices benefit the nation's economy, some producers argued that they were beginning to have adverse impacts on the industry infrastructure from which there would be no quick recovery when and if prices recovered. In the meantime, some producers contended, the United States would become even more dependent upon imported oil.

A number of possible responses were debated during the first session of the 106 Congress. These included:

Low prices also revived discussion of oil import fees, tariffs and quotas. A petition was filed in June 1999 by a coalition of independent producers alleging that four major exporting countries — Saudi Arabia, Venezuela, Mexico, and Iraq — had dumped crude into U.S. markets at below-market prices. Though the Department of Commerce rejected the petition on August 9, 1999, the matter heightened attention to the oil and gas sector while also having some repercussions on U.S. trade relations and policy while the petition was pending. The decision is being appealed.

After the Organization of Petroleum Exporting Countries (OPEC) announced a production cutback in the late spring of 1999, prices rose sharply. But interest in policy measures to help the domestic oil industry continued. A program to provide RIK oil to the SPR was not expected to have much bearing on price, but it was, from the industry perspective, a welcome and long-sought demonstration of the possibilities for RIK payment. The guaranteed loan program had a momentum not altogether tied to current oil prices because it was part of legislation (H.R. 1644) that also included a guaranteed loan program for the U.S. steel industry.4 In addition, some have argued that having policies and programs in place would make it possible to respond more quickly to possible future extended slumps in the volatile oil market.

The increase in crude prices also became a theme in Congress. It was referenced in the Senate in late September in the face of a filibuster over a controversial amendment to the FY2000 Interior Appropriations bill that would have delayed, for another fiscal year, a rule from the Minerals Management Service (MMS) that would revise the method for valuing oil for royalty purposes. Opponents of the delay cited losses to date to the Treasury of $88 million and prospectively, an additional $66 million. Supporters of the amendment suggested that a boost in the royalty valuation could raise the price of gasoline further. The amendment was passed, but the conferees agreed to delay the rule for 6 months, pending study and analysis by the General Accounting Office (GAO). It is not clear to what extent the price environment affected the outcome.5

When OPEC reconvened in Vienna on September 22, 1999 to review its production quotas, crude was approaching $25/bbl. As was generally anticipated, the ministers agreed to maintain output quotas at current levels until March 2000. OPEC argued that worldwide stocks had not declined sufficiently to merit a production increase and that the OPEC nations still had the considerable revenues they needed to recoup from the sustained price collapse.

A few days earlier, anticipating the OPEC ministers' decision, and expecting that retention of the OPEC production ceiling would put additional pressure on prices when the weather turned colder, Senator Schumer wrote the Clinton Administration to request that the President authorize a sale of SPR oil to blunt a further rise in oil prices. Home heating oil price and supply are an historic concern in the Northeast part of the nation, where its use is more common. The Administration sent varying signals on the matter initially, but has generally distanced itself since from any sale at this time.

Worldwide, falling petroleum demand and essentially stable output resulted in depressed prices on world crude markets during 1998. U.S. oil output fell along with prices, and stood in late summer 1999 at 5.9 million barrels per day (mbd), a level last seen in 1946. As domestic output has fallen, demand has increased. Oil imports have risen from 1985's unusually low level of 3.2 mbd to 9.7 mbd in 1999. Net imports now comprise 51% of all petroleum used in the nation. The year 1998markedthe first in which net imports exceeded half of U.S. consumption, averaged over the entire year.6 Onshore production in the lower-48 states, the operating locale for many independent producers, has fallen by 40% since 1980; these producers ' current-dollar revenues are only one-fourth of 1980 levels when crude prices were at their height.

The turn in petroleum prices beginning in the spring of 1999 has been dramatic. Figure 2 outlines price developments during the past 14 months. It includes gasoline prices as a point of reference because prices at the gas pump have such high public visibility. Together, these two figures illustrate the recent volatility and dramatic recovery of oil prices. From September 1998 to September 1999, crude oil prices increased by 61%; gasoline prices increased by 23%.7

OPEC was founded in 1960 to maintain crude oil prices on behalf of its members. Eleven countries presently make up the Organization of Petroleum Exporting Countries (OPEC). They produce 40% of the world's oil, hold 77% of proved oil reserves, and control most of the unused capacity capable of producing more oil.

Despite presenting a seemingly powerful market force, OPEC has an uneven record of establishing and maintaining prices, holding its members to individual production quotas, and dealing with price declines. When, for example, prices collapsed in early 1986, OPEC's members failed to adhere to the production quotas which were necessary to keep control — or maintain substantial influence — over prices. With a few short-lived exceptions, OPEC was unable to stabilize prices for a significant period until late 1996. By then, growing demand from a strong world economy, producer self-interest, and the absence of Iraq from the world marketplace enabled the cartel to balance supply with demand. In 1997, when declining global economic activity reduced demand, OPEC members reacted by exceeding production quotas in order to make up for the fall in revenues as prices declined.

With prices dropping and production increasing, the OPEC "basket" of eight kinds of crude oil averaged only $12.28 per barrel during 1998, the lowest annual average since OPEC began calculating. This was nearly $9/bbl below $21.00/bbl, the publicly stated target that OPEC was attempting to hold and maintain by adjusting member nation quotas.

To remedy the price situation and restore member nation oil revenues, OPEC, joined by key non-OPEC producers — Mexico, Norway, Russia and Oman — met in March 1999 and negotiated production cuts for the group. The quotas they agreed upon were intended to raise prices to an average of$21.00/bbl for the full calendar year. Some producers responded to the quotas tentatively, but the initial success encouraged wider compliance. By the time OPEC reconvened in Vienna in September 1999, production cuts totaled 4.1 mbd. Higher export revenues had reinforced the resolve of the participating OPEC countries, and they agreed to maintain current output levels until March 2000.

Prices reached $25/bbl shortly after the September meeting. However, the average price for the "basket" was only $15 through mid-September 1999. Given OPEC's objective to achieve an average per barrel price of $21 for calendar 1999, the implication was for prices higher than $21/bbl during the fall of 1999 to offset the lower prices that prevailed earlier in the year. It may well be that prices will remain above the $21 target for all or part of the 1999-2000 heating season, but it is difficult to venture any predictions. Winter weather and other factors will influence prices before OPEC meets next in March 2000. The winter of 1998-99 was abnormally warm in both North America and Europe; a heating season closer to normal should quickly eliminate any overhanging inventory.8

At an average of $21/bbl, and current production levels set at about 23 million barrels per day, the ten participating OPEC members (Iraq, whose crude receipts are paid to the U.N., is excluded) would realize about $175 billion at an annual rate. During 1998, these ten OPEC producers produced about 25.7 mbd valued at $115 billion. Under these assumptions, the ten could realize $60 billion greater revenue by producing 2.7 mbd less oil, illustrating the incentive for sticking with assigned production caps. Non-member quota participants reap similar rewards.

Many foreign producers that have been adversely affected by low oil prices had petro-dollar fueled budget surpluses during the 1970s and 1980s and can regain former prosperity by adherence to OPEC production discipline. In the case of Venezuela, an OPEC founding member that over-produced greatly during 1998-99 and experienced economic adversity as a result, recently-elected President Hugo Chavez announced a year 2000 budget based on his nation's September quota of 2.72 mbd. He pledged that impoverished Venezuelans would see some of the extra petro- dollars in the form of salary hikes and social program spending. President Chavez predicted 2.2% real growth in year 2000 as a result of enlarged oil receipts, in contrast to a 6.6% contraction in 1999.9

Whether the recent recovery in oil prices will be a long term development or a transitory market fluctuation is not yet clear. OPEC's cohesion on limiting supply in order to maintain prices appeared to be holding into the fall of 1999. But, is it not readily apparent that OPEC will be able to adjust to changing market conditions and hold a target price over time. Thus, the future path of oil prices is always a matter of some speculation, and predicting that path is extremely difficult.

The especially low oil prices that prevailed during 1998 and early 1999 have been cited as the chief cause of adverse impacts on domestic crude output and producers. Even the historically robust supply from Alaska is likely to continue to decline. Many of the policy options discussed here aim to stem the losses in U. S. production capacity and infrastructure. These policy options have the potential or the direct goal of raising prices or lowering producer costs, with the volatility of oil prices underscoring the complexity of the issue. A number of questions might be considered, beginning with whether policymakers should take action during periods of sustained low prices. How long would low oil prices persist before a response is activated? How much price support would be required, and how much lost production might be protected or regained?

On the other hand, low oil prices benefit consumers and the overall U.S. economy. In early 1999, consumers enjoyed the lowest real-dollar pump prices in history (even after steadily increasing federal, state and sometimes local taxes are considered). The performance of the economy has been enhanced by years of declining commodity prices, including those based on petroleum. Any policy debate would include consideration of how higher oil prices resulting from intervention in markets would affect economic conditions, especially in the current situation of declining commodity prices and extremely low inflation. There are macroeconomic consequences as well as impacts upon consumers when the price of oil rises.10

Through much of this debate, the Administration has acknowledged that the plight of the producers is very real, but has been guarded about possible actions. In late February 1999, testifying before a House appropriations subcommittee, Secretary of Energy Richardson indicated that his Department wanted to help the oil industry, but did not "want to tamper with the markets," or to do anything "that affects oil prices." He indicated that tax policy and emergency loans were under discussion but were not at that time "administration policy."11 Advocates of assistance for the domestic oil industry might argue that neither the loan guarantee program subsequently passed by Congress and enacted into law, nor the scale of the tax provisions included in tax relief legislation sent to the President, constitute direct interference with prices or a significant bailout to the industry. However, others would argue that policies favoring the oil and gas industry are at cross-purposes with environmental policy objectives, calling for an even more sensitive balancing of policy objectives.12

Given the volatility in oil prices, proponents of government action might suggest a broader debate to include policies that can address not just persistently low petroleum prices, but which can be sufficiently flexible and responsive in the face of volatility in prices. There are others, however, who believe that the best economic course is to allow the market to function without further government intervention.

One of the most contentious issues addressed in conference on the FY2000 Department of Interior Appropriations bill (H.R. 2466) was a rider affecting promulgation of a rule by the Minerals Management Service (MMS) that would affect the valuation of oil produced from federal lands for determining the royalty the producer owes to the government. Royalty payments are computed as a percentage of the value of the commodity as it is removed from the lease. Establishing that value in situations other than those where the hydrocarbons are sold in arm's length, third- party transactions has been a source of controversy. Current regulations provide for a 5-step valuation process which ultimately imputes a price providing a best approximation of a market price.13 This process may be applied to transactions which are intra-corporate (e.g., a producer transferring the oil to its refining arm). Here, the hydrocarbon has not actually been sold, but a market value must be ascribed in order to compute a royalty payment. In situations where transport costs from lease- to-market are a factor, value for royalty computation may be adjusted to reflect the cost of transporting the oil to market.

Royalty payments are generally computed as a percentage of the value of oil appraised at posted prices, prices that are established by oil producers in the field. The fact that producers set this price themselves has led to a number of lawsuits disputing the fairness of posted prices as measures of the value of the oil. Many of the disputes involved states suing for their share of royalties from production on state as well as federal lands. In recent years, a number of lawsuits were settled for amounts totaling $5 billion,14 including a $3.7 billion settlement in Alaska.

Critics of the current valuation system contend that the settlements themselves are evidence that oil is being regularly undervalued in computation of royalty payments. They are especially concerned about situations where the crude is used in refineries owned by the producing firm, but the value of the oil is determined by the producer alone. Producers fear that the new rule may value the crude at some point away from the wellhead and not allow companies to deduct marketing and transportation costs.15

For nearly 3 years, MMS has been working on a new valuation rule. MMS proposed issuing final valuation regulations in 1998 that base value on a series of benchmarks for each field. The benchmarks would be computed from oil traded on public markets, with transportation, location and quality differentials factored in. The new rules would likely result in higher royalty collections. Promulgation of the rule during FY1999 was blocked in that year's Interior Appropriations and for the two years proceeding.

Producer opposition to the new rules has been strong. Senator Hutchison introduced an amendment to the FY2000 Interior Appropriations bill (H.R. 2466) extending the appropriation ban for another year. In debate, the proposed regulations were characterized as a tax increase imposed on producers. Senator Murkowski, for example, described the regulations as "another tax, a value-added tax, on oil produced in the United States on Federal leases."16

Senators who believe that royalty collections should be higher mounted a filibuster led by Senator Boxer. Cloture was voted (60-39) on September 23. Senator Hutchison's amendment banning final regulation implementation was then passed by a 51-47 vote. The conferees agreed to postpone release of a final rule pending a six- month study by GAO. Representative Carolyn Maloney criticized the conferees' decision, pointing out that she and Senator Boxer had previously requested a GAO report, which was released in August 1998 and concluded that MMS had been thorough.17 Some revision to the proposed rule is expected in any case.

In late March 1999, Senator Domenici introduced a proposal for an oil and gas loan guarantee program that was added as a rider to the Emergency Supplemental Appropriations Act (H.R. 1411), but the language was stripped from the bill for separate consideration. The proposal was included in H.R. 1664, an emergency supplemental appropriations bill for military purposes. A larger loan guarantee program proposed for the steel industry was included in the same measure. Opponents of the loan guarantee programs sought to block consideration of the bill, but on June 15, 1999, the Senate invoked cloture (71-28), clearing the way for debate to proceed on H.R. 1664. The Senate amended the proposal on June 17, 1999, and passed the bill the following morning (63-34). On August 4, 1999, the House agreed to the Senate amendments (246-176) and the President signed the measure into public law (P.L. 106-51) on August 17, 1999.

The stated purpose of the loan guarantee program is to stem farther losses in jobs and capacity in domestic oil and gas production. The loans will support small domestic independent oil and gas companies adversely affected by prolonged depression in oil and gas prices. To be eligible, a firm must be (1) an independent oil and gas company as defined by the Internal Revenue Code 18 or an oil field service company that qualifies as a small business concern under the Small Business Act 19 and (2) "have experienced layoffs, production losses, or financial losses since the beginning of the oil import crisis, after January 1, 1997."

Under the program, a total of $500 million in loans can be outstanding at any one time. (The program for the steel industry is $1 billion.) The maximum loan would be $10 million; a minimum threshold loan level of $250,000 was dropped by the Senate as likely to exclude many smaller firms the program was intended to help that want to borrow less. The borrowers pay a service fee of 0.5% of the outstanding principal to the Treasury. A reviewing board will approve or deny the applications for loan guarantees.

These guarantees will be issued by a Loan Guarantee Board on loans to qualifying companies for which "credit is not otherwise available to the company under reasonable terms or conditions sufficient to meet its financing needs." However, the board must believe that the company's "prospective earning power" and collateral provides "reasonable assurance" of repayment. The rate of interest must be reasonable and the company must agree to submit to General Accounting Office (GAO) audit. Loans guaranteed under the program would have to be repaid by the end of calendar 2010.

The original proposal provided that the board would be chaired by the Secretary of Commerce and include the Secretaries of Labor and the Treasury. As amended by the Senate on June 17, 1999, the chairs of the Federal Reserve System and the Securities and Exchange Commission would serve in place of the Secretaries of Labor and Treasury. The Chairman of the Federal Reserve was designated to be the chair of the Loan Guarantee Board.

The Senate made two other significant changes. Some opponents of the program argued during debate on the cloture motion that loan guarantee programs have not been effective in the past and that the government has had to absorb significant defaults. In particular, a 77% failure rate was frequently cited for a steel industry loan guarantee program instituted in the late 1970s.20 An amendment to the proposal offered by Senator Stevens reduced the loan guarantee from 100% to 85%, the argument being that there was no incentive for a lender to press for collection of a loan that was guaranteed at 100% by the federal government.

The other major argument against the program focused upon the budgetary scoring of the program's expense. Though the legislation included a spending offset, it also lent an emergency designation to expenditure of the funds. Opponents argued that this would mean that expenditures would not be counted against spending caps. Consequently, critics argued, any offset savings achieved would be spent anyway and come out of the Social Security surplus.21 The Senate struck the "emergency" designation.

Senator McCain, opposing the program, argued that it was inappropriate for the Senate to approve the proposal before it had been reviewed by an authorizing committee. He offered an amendment that would have precluded the expenditure of any funds for the program until such spending had been authorized by the appropriate committee. The amendment was tabled. The bill as passed by the Senate appropriates $122.5 million to cover anticipated losses on guaranteed loans to the oil and gas industry during the life of the program.22

Some of the support for H.R. 1664 may have been related to another proposal (S. 395), which would have protected the domestic steel industry by imposing import quotas. Some argued that existing quotas have already boosted the price of steel alloys and drill pipe, on which the oil and gas industry is dependent, and that any stiffening of the quotas to further protect steel would worsen the effects on the oil and gas sector.23

A loan guarantee program may be less of an intrusion into the marketplace than are import quotas, price controls, or import fees. However, many opponents believe that the most economically efficient policy response would be to take no action at all and allow the market to determine the allocation of resources without intervention. Proponents of the program argued that it could serve as an effective financial bridge for small oil and gas producers and field service companies through a difficult period. The loans that might not be obtained without federal guarantee could be used as capital to pay for well makeovers, well reopenings, and meeting payroll — applications that would tend to preserve both industry capital and labor — and for meeting and/or restructuring interest payments.

As enacted, the program may still present practical questions as to how it will achieve its stated purpose. These include [ I ] whether the stated qualifying conditions are workable; [2] whether the program will keep marginal wells producing, and maintain the oil and gas service industry infrastructure; and [3] whether there are equally or more effective and efficient measures that would achieve the same purpose. Independent of these questions, opponents of the program might argue that economic interests and efficiencies would be best served by doing nothing and allowing the market to operate without granting loan guarantees.

There are other considerations. Oil prices have increased sharply since introduction of the program, likely reducing the potential call on guaranteed loans as provided by the proposed program. While some may argue that there would be advantages in having in place a loan guarantee program in the event that the need materializes,25 opponents argue that a board composed of government officials has no special qualification to second-guess the financial sector's assessment of capital to be placed at risk.26 In any event, in the case of this government credit assistance program, the ability of borrowers to repay may well be more dependent upon a commodity price that is determined in a world market than upon the managerial abilities of its owners and/or managers.

Among the broader economic considerations are whether there are market failures or national security issues that justify government intervention. The questions are whether output losses, layoffs, financial losses, and oil industry contraction are a normal market response to recently low oil prices, and whether dependence upon imported oil poses a risk serious enough to warrant government intervention.

Market Failures. The sort of failures that in theory may be cited to justify government intervention in markets include failures of competition that create barriers to entry into markets. Intervention may also be justified by "externalities" or spillovers; these are benefits or costs to society experienced by firms or individuals that are not parties to the particular transaction or activity, and are not reflected in the prices buyers and sellers pay. In these cases, buyers and/or sellers do not pay the full cost to society of their transaction, or do not receive full return. It does not appear that crude oil markets are operating imperfectly and therefore justify on grounds of economic efficiency alone loan guarantees to small oil and gas producers.

Whether loan guarantees are an appropriate instrument also depends upon how the unimpeded operation of capital markets is perceived. Oil and gas producers face unusually large risks (compared with other industries) from sudden and sharp oil price fluctuations. Producers have access to capital generally but may have to pay a higher interest rate on loans and face more restrictive terms than less risky industries, particularly during an industry downturn due to low oil prices. This is not discrimination, but a reflection of the way in which financial markets allocate capital to its most valued use. When crude oil prices and industry profitability decline, capital markets interpret this as a signal to allocate less capital to crude oil production.

National Security. National security is one type of social cost that may justify government intervention in the oil markets. Many agree with the argument that substantial oil imports and dependence on foreign oil may pose both energy security and national security risks if such imports significantly increase the probability of supply disruptions and sharp price spikes.27 However, this does not justify loan guarantees on economic grounds alone. Low oil prices lead to reduced U.S. production and greater overall demand. This tends to increase dependence, but the risk to national and energy security also depends upon (1) the level of imports related to total oil demand, and (2) more importantly, the level of imports from unreliable or unfriendly foreign suppliers, as a share of total demand. Some argue that the United States is not necessarily more secure if it produces more oil domestically and imports less, but depletes its domestic resources faster.

Experience during the 1970s and 1980s suggests that the greatest and most direct social cost of import dependence may be the sharp price spikes that accompany a supply disruption. However, as long as U.S. oil markets are open, they will be subject to world market price pressures unrelated to the degree of import dependence. Considerable adverse macroeoconomic effects can result. On the other hand, the world market is much more competitive today than it was during the disruptions and oil price shocks of the 1970s. The likelihood of such disruptions may have decreased. The increment of security or price protection that loan guarantees may provide in the current geopolitical climate (and were it to continue) could well be too small to measure with any confidence.

Tax policy options suggested to help domestic oil and gas producers can be divided into four general categories: 1) expanding existing oil and gas industry tax incentives; 2) creating exceptions for the oil industry from provisions of the general income tax laws that apply to other industries; 3) offering new oil and gas tax incentives; and 4) reducing existing tax penalties, fees, and other costs. The Taxpayer Refund and Relief Act of 1999 (TRRA, H.R. 2488), which was approved by the Congress on August 5, 1999, includes provisions from the first two categories. However, on September 23, 1999, the President vetoed the measure.

Whether the provisions in TRRA would be included in a compromise measure, or whether a free-standing measure of tax policy options not necessarily confined to those already in the TRRA might be enacted is a matter of much speculation in tax policy circles. For this reason, other policy options that have been introduced or debated by Congress are described below in addition to the proposals included in the TRRA.28

While intended to benefit domestic producers, tax policies (particularly additional federal tax incentives) that reduce production costs of marginal wells and ostensibly increase profitability also create incentives to produce more oil. This could put downward pressure on petroleum prices. This would exacerbate the industry's problems, or at least reduce the extent of the benefits. On the other hand, demand for imported petroleum would be reduced.

Three major existing tax incentives that subsidize the domestic oil industry might be liberalized or broadened as a way of reducing production costs and enhancing profitability. They are: expensing of intangible drilling costs (IDCs), the percentage depletion allowance, and the tax credit for enhanced oil recovery costs.29

Expensing. Expensing allows firms engaged in the production of domestic oil and gas to deduct in the year paid or incurred certain intangible costs of drilling and development, such as amounts paid for fuel, labor, supplies and repairs associated with a site. This is an exception to general tax rules, which require capitalization of such costs. Integrated oil companies can only expense 70% of IDCs, and the excess of the expensed over the capitalized value is a tax preference item to the extent that it exceeds 65% of the net income from the property. Independent producers can expense 100% of their IDCs and do not have to report them as tax preference items.

Thus, one option for assisting the oil industry would be to remove any one or more of the restrictions on the claiming of the deduction. However, expensing of oil and gas investments — which is basically an incentive to drill more wells — is largely claimed by integrated oil and gas companies, rather than independents. For example, the 70% limitation for integrated oil companies might be removed, but this would do little to help the small domestic oil producer.

Another type of liberalization, which is included in the TRRA, would extend expensing treatment to geophysical and geologic costs and to "delay rentals," which now must be capitalized. Delay rentals are payments made by a producer to a landowner, under a lease agreement, in the absence of a producible well.

Percentage Depletion Allowance and Enhanced Recovery. The percentage depletion allowance, unlike expensing, is largely claimed by the small independent producer. This tax subsidy permits independent producers to subtract 15% of sales from a property as a deduction for the depletion or depreciation of the capital investment in the mineral reserve. The deduction for stripper oil wells and for heavy oil — which account for about 20% of total oil output — is the basic 15% plus an additional I % for each $ I that the benchmark price of oil (the average wellhead price of crude oil in the preceding calendar year) falls below $20 per barrel. Thus, with 1998 oil prices at about $12 per barrel — $8 below the $20 threshold — the percentage depletion allowance for stripper wells was about 23% (15% + 8%).

Thus, one way to assist large and small domestic oil and gas producers would be to raise the percentage depletion rate above 15% and to broaden it to a larger share of domestic oil output. Before the repeal of the percentage depletion allowance for major oil companies in 1975, the basic percentage depletion rate was 27.5%, and all oil producers, including major integrated oil companies, qualified for it.

Another way of liberalizing the percentage depletion allowance would be to remove one or more of its restrictions. For example, currently the percentage depletion allowance is available only to independent producers and royalty owners, and it applies only to an average daily production of up to 1,000 barrels of oil, or the equivalent amount of gas (6 million cubic feet). An independent producer is one that does not have retail or refinery operations, unless the revenue from the retail operations do not exceed $5 million per year, and refinery runs do not exceed 50,000 barrels of oil per day on any given day. The TRRA would define excluded refiners as those that on average, during the taxable year, refine more than 50,000 barrels of oil per day, thus expanding the number of oil producers that qualify for the depletion subsidy. Current law also limits the percentage depletion allowance to 100% of the net income from that property in any year (this is the net-income limitation), and to 65% of the taxpayer's overall income.30 The TRRA suspends the 65% taxable income limitation for six years.

A third tax incentive — in current tax law but not altered by the TRRA — is the 15% income tax credit for the costs of recovering oil through one of several enhanced oil recovery methods. This tax incentive could also be expanded, although the impact would still be relatively limited within the domestic oil industry.

Some proposals would assist oil producers by creating exceptions to specific provisions of the general income tax laws, which apply to all businesses generally. Focusing particularly on oil producers that were hit hard by the 1997-99 price collapse, one proposal would broaden the net operating loss carryback and carryforward provisions of the income tax laws. For example, the TRRA proposes to allow net operating losses in the case of oil and gas properties to be carried back five years, instead of the current two years.31

Reducing Existing Taxes, Fees, and Other Costs. A third policy approach would attempt to reduce industry costs, not by expanding existing tax incentives or subsidies, but by lowering existing tax penalties, fees, and various other types of government-imposed costs.

The domestic oil industry currently makes a variety of payments to governments — excise taxes, severance taxes, fees, royalties, and customs duties. Some of those payments, such as the severance tax, are state and local taxes outside the direct control of the federal government. Others, such as excise taxes and royalty payments on federal lands, are under the control of the federal government. A variety of excise taxes, for example, are imposed on crude oil and petroleum products. These include various motor fuel excise taxes that fund the Highway Trust Fund and the Leaking Underground Storage Tank (LUST) Trust Fund, a petroleum tax that funds the Oil Spill Liability Trust Fund, and the petroleum tax that funds the Superfund. The latter two petroleum taxes expired on December 31, 1995, but might be reinstated if either the oil spill fund or the Superfund is reauthorized. They are, however, relatively small and are assessed only on refiners and importers.

Producers that extract oil and gas from federal land pay royalties to the federal government. Royalties — although not a tax but a type of factor payment — could also be lowered to assist the oil industry, as was discussed in the previous section. The domestic oil industry is also subject to many types of regulations that, in theory, could also be reduced or loosened as a way of reducing production costs and enhancing industry profitability. Because such regulations support objectives in other policy areas, a vigorous debate might be engendered.

New Tax Incentives. Still another approach in assisting the domestic oil industry would introduce new tax incentives. Several new tax incentives have been suggested recently, though none were incorporated into the TRRA. Some of these date back to the mid 1980s, in the aftermath of the 1986 oil price collapse. For example:

Royalty-in-kind (RIK) payments for the government's share of production from federal lands have been a goal of some producer groups for several years. Royalty rates vary from 12.5% to 16.67%, and are typically paid in cash. A number of disputes have arisen over the cash value of oil upon which the percentage royalty due the federal government is based. Some producers have contended that crude valuations have appraised crude too high, resulting in cash payments to the government that are too large. One remedy, these producers contend, is to pay the royalty in physical barrels of crude, rather than trying to attach a dollar value to the crude.

The Strategic Petroleum Reserve (SPR) in 1998 began receiving RIK oil from federal leases in the Gulf of Mexico to replace oil that was sold during FY 1996-1997. While the volumes involved are probably not having any appreciable effect on domestic oil prices, the industry has been pleased by the decision to use a royalty-in- kind program to acquire oil for the SPR. The intention is to acquire 28 million barrels through this program. More than 13 million barrels had been contracted for through June 1999, with additional solicitations planned for deliveries in 2000.

The SPR was authorized in late 1975 to protect the nation against a repetition of the economic dislocation caused by the 1973-74 oil embargo. Its intent was to store a volume of crude oil in salt caverns that could be drawn down and introduced into the market place to blunt the sorts of sharp price increases that had accompanied interruptions of oil imports in the 1970s and early 1980s.

To pay for maintenance of the SPR infrastructure, Congress authorized sales of SPR oil during FY1996 and FY1997. More than 28 million barrels of SPR oil was sold in three separate sales. A sale of another $209 million scheduled during FY 1998 was canceled when oil prices fell sharply in late 1997 and early 1998. With the more recent expectation of federal budget surpluses, talk of any further sales ended. Indeed, attention began to turn to finding some way to replenish the SPR if Congress were disinclined to do so by direct purchase of oil. In late July 1998, for example, the Senate approved an amendment to the Treasury-Postal appropriations bill (S. 2312) to purchase $420 million of oil for the SPR to prop up domestic oil prices by replacing the volume sold in the three recent sales. But the provision was stripped from this bill. A request to the Office of Management and Budget by Secretary of Energy Richardson for $100 million in the FY2000 budget request for oil purchases was turned down. At a price of$13/barrel, such an amount would have funded the purchase of less than 8 million barrels.

Although doubtful that any appropriation for direct purchase would have supported a daily volume sufficient to boost prices significantly, the domestic industry argued that removing some domestic oil from the marketplace could at least be part of a broader package of relief measures for producers. Quite apart from whether or not the plan would boost producer prices, the SPR fill proposal may benefit producers because it is a step toward in-kind payments that many believe are more fair.

The proposal to accept crude for the SPR as royalty-in-kind in lieu of the customary cash payment collected by the Minerals Management Service (MMS) surfaced in late 1998. On February II, 1999, Secretary of Energy Richardson announced such a plan. Final details were worked out during early 1999. DOE negotiated for an initial arrangement that would secure the greatest volume of oil as soon as possible. On April 1, 1999, DOE announced that it had signed three-month contracts with Texaco, Shell, and BP to accept a total of 3.5 million barrels, or 38,600 b/d. Adjustments were made allowing for the quality of the oil to be delivered and the expense of transportation.

While the SPR plan was praised by segments of the oil industry and by some Members of Congress who cited the benefits to the nation's energy security by replenishing the SPR, the budgetary consequences of the proposal drew less explicit attention. Payment of a royalty-in-kind constitutes a barter transaction. In this deal, producers are to physically deliver oil to the SPR instead of making cash payments based on the oil's estimated value. The producers would not have to be paid for royalty oil sent to the SPR, but MMS (and ultimately the Treasury) would lose the cash royalty payments that it otherwise would have received for that oil. Theoretically, royalties paid in cash should be equivalent to royalties paid in kind. However, it is uncertain whether the value of oil received would be greater or less than the value of cash royalties foregone. Oil prices have recovered since the RIK plan was first proposed, and it is unlikely that taking the volumes involved off of the market had a measurable effect on price. Nonetheless, producers believe they benefit from regular collection of in-kind royalties, and greeted the RIK plan as a well- intended and helpful first step.

At the same time that the SPR is being replenished, the sharp increase in oil product prices led to at least one call in late September to sell oil from the Reserve. On September 21, 1999, Senator Charles Schumer urged DOE to consider a sale of SPR oil to blunt further increases in the price of petroleum products, especially home heating oil, as winter approached.34 Initial indications from Secretary Richardson that the idea would be given serious consideration took some by surprise, and a few days later, DOE distanced itself from this interpretation, suggesting that inventories appeared adequate for the moment.35 The prospect of taking in oil, on the one hand, and selling it on the other, reflects the policy complexities arising out of an extremely sharp rise in prices following closely upon a period of low prices. At the same time that a sale of SPR was being proposed, the Senate Committee on Energy and Natural Resources, in its reporting of legislation to reauthorize the SPR, urged DOE and DOI to consider continuing to fill the unutilized capacity of the Reserve with RIK oi1.36 (For additional information on the SPR, see CRS Issue Brief 87050.)

A coalition of independent oil producers, Save Domestic Oil Inc. (SDO), filed antidumping and countervailing duty petitions with the U.S. Department of Commerce on June 29,1999 alleging that Saudi Arabia, Mexico, Venezuela and Iraq have sold oil in the United States at prices below its fair market value, and that producers or exporters from these countries receive countervailable subsidies. The Department's International Trade Administration rejected the petitions on August 9, 1999 on the ground that there was insufficient support from others within the industry to warrant an investigation.37 While the petitions were dismissed, their very submission caused some ripples of concern.38 Some hoped initially that some sort of resolution would be negotiated, but these attempts were not successful.39 SDO has since filed a complaint with the U.S. Court of International Trade requesting review of the decision, arguing that the Department improperly measured industry support.40

While the expression "dumping" may connote in everyday language simply a large volume of imports of a product at low prices, its operative definition in international and U.S. trade law is more specific. A product is "dumped" when it is sold by the exporter in the importing country at "less than fair value," that is, at a price which is lower than that charged to buyers in the exporter's domestic market or in sales to third countries. In addition, under World Trade Organization (WTO) agreements and U.S. law, an antidumping remedy in the form of an antidumping duty, equivalent to the unfair pricing margin, cannot be applied unless it is determined that such imports also materially injure, or threaten material injury to, an industry in the importing country, or materially retard the establishment of a domestic industry. Similarly, WTO agreements and U. S. law allow for the imposition of a countervailing duty in the event an imported product is found to be subsidized and to cause the material injury described above.41

The petitions sought imposition of anti-dumping duties on imports from these countries, ranging from more than 33.4% on Mexican imports to nearly 178% on Venezuelan crude imports. Additionally, SDO sought a countervailing duty of more than $6/bbl to offset alleged government subsidy of production in these nations. Some argued that imposition of duties would only redirect world oil supplies. Crude oil that would be subject to a duty in the United States would simply be sold elsewhere at market prices; price would not be appreciably higher and domestic producers would derive no benefit. Others suggested that there would be dislocation while the reallocation took place, and that refiners would have to purchase higher-quality crudes in some instances.

The petitions created problems for the Administration because the charges were lodged at certain important allies. Some suggested that it would complicate Administration free trade policy objectives, especially if there were antidumping and countervailing investigations in progress when the WTO met in Seattle in the fall. Additionally, immediately after the petition was filed, Mexico postponed its previously announced plan to lift tariffs on natural gas imported from the United States. With the announcement on August 9, 1999, that the petition had been rejected, Mexico indicated it would move forward with removing the tariff.

It is possible that an investigation of low-price petroleum imports into the United States would have found the existence of actual or threatened injury to at least one segment of the U.S. petroleum industry (small producers). It is, however, highly unlikely that such investigation would also have found the existence of sales at less than fair value, primarily because the nature and structure of the international petroleum market is such that crude oil prices essentially are set in the world market rather than by individual producers. These prices are more or less uniform, allowing for differences in quality and distance from markets.

The concept of limiting petroleum imports to support domestic producer prices has been a subject of national debate dating back to the Great Depression. Efforts to support domestic prices by establishing quotas for petroleum imports began after World War II, when substantial amounts of low-priced Persian Gulf crude oil began to arrive on world markets. At the time, U.S. prices were in the $3.00 per barrel range; Persian Gulf crudes sold for as low as $1.00.

National security provisions aimed at protecting domestic producers of key commodities — to be utilized by the President at his discretion — were included in the 1958 Trade Agreements Extension Act. These provisions are now contained in even greater detail in §232(b) of the Trade Expansion Act of 1962 (19 USC 1862). In essence, §232(b) gives the President authority to limit the imports of a commodity if they threaten to impair the national security.

With oil, demands for protection had grown to the point that President Eisenhower responded by establishing a voluntary import restraint program. This program was coordinated by the Oil Policy Committee, a group of oil industry and government officials who advised the President. Voluntary quotas were adopted in 1957, relying on the cooperation of oil importers, and proved ineffective. On May 10, 1959, the President issued Proclamation 3279 under authority in the 1958 act. This instituted a mandatory protection program, which set quotas on imports to balance supply and demand at an acceptable target price in the $3.00 range. Mexico and Canada were exempted from the quota program, since transport was overland and considered safe from a security view. Under the Eisenhower quota, imports were not to exceed 9% of domestic demand.

This quota system became known as the Mandatory Oil Import Program (MOIP). Under the system, import "tickets" — allowing the holder to import a barrel of oil— were issued to all refiners in proportion to the amount of crude they refined. Refiners received tickets regardless of whether they imported oil or not. A "white market" for tickets quickly developed, where unneeded tickets could be bought by import-dependent refiners. The white market functioned as an auction-type market, which priced the tickets to reflect the domestic/foreign price difference. Since all refiners were given — at least during the program's initial days — equal proportions of tickets (relative to crude use), and the market priced the tickets accurately, refiners' crude costs (relative to one another) were not affected.

Later modifications were designed to benefit small refiners, among others. But initially, no refiner received an advantage or was put at a disadvantage because of the type of oil refined, U.S. crude prices for both imported and domestic oil were held above world market levels by the quota, and U.S. producers received the highest prices in the world. Refiners importing large amounts of cheap foreign crude paid for it in part by having to buy tickets (from refiners not importing oil) in excess of their allocation. And refiners paying higher domestic prices because of the import restriction received offsets by selling their excess tickets to importing refiners.

The MOIP continued with adjustments for over 14 years. By 1969, rising oil prices — combined with a growing number of quota loopholes — made the tickets valueless. President Nixon established a Cabinet Task Force on Oil Import Control, headed by Labor Secretary George Shultz, to review the program.42 Shultz recommended that the quota program be scrapped and replaced by an import fee system.

On June 25, 1974, the import fee system was imposed by President Nixon in Executive Order 11790. As implemented in the aftermath of the Arab oil embargo, the new fee system essentially provided for unrestricted access to imports, imposing only an import fee of a few cents per barrel.

Subsequent policy interest in oil import fees and quotas centered on periodic efforts to raise U.S. oil prices in order to achieve price-induced conservation and import reduction, as well as increase domestic output. A number of proposals were brought forward during the decade after the Arab oil embargo. Basically, they centered on an import quota or import tax, but variations aimed broadly at price- induced conservation and increasing Treasury revenue would have taxed all oil consumption. The latter variation offered no benefits to domestic producers.

The oil import quotas, tariffs and fees that have been considered for the past four decades all would tend to increase the price of imported oil within the United States. This would, in turn, have the effect of raising the price for domestic crude as well; with import prices increased, a target price umbrella is created, providing a domestic price floor predetermined by policymakers.

Quotas operate by limiting supply so that a given price level is maintained. In order to hold a certain price point, constant quota adjustment is called for so that variations in demand are met without price instability. Sticking with one fixed quota amount would likely result in wide price swings and could cause spot shortages. Higher petroleum prices resulting from a quota would benefit domestic producers of all types.

But businesses and consumers would pay higher fuel prices. At present consumption levels, every $1.00 per barrel of price support totals nearly $7 billion annually. If passed on to consumers on a penny-for-penny basis, this would amount to about 2.4 cents per gallon of gasoline at the pump.

The imposition of a fixed fee on crude and refined product imports could achieve a more direct effect on crude oil prices without the volatility of a quota; additionally, it might offer a more easily implemented policy tool under §232(b). Tariffs or import fees would lead to higher prices for domestic oil producers, reaching the price level targeted by policy with much less chance of a supply imbalance and related price volatility in the oil patch and at the gas pump. A fee would result in a reasonably predictable amount of producer protection, a better delineated pump price increase and economic effects that would be more predictable. And the import levy would presumably accrue to the Treasury, generating revenue under current market conditions at a rate of about $3.5 billion annually for each tax increment of $1.00 per barrel.

Higher oil prices would, in turn, reduce energy consumption and related environmental damage. However, price increases would also be likely to harm the economy as a whole and create adverse effects in specific regions of the United States. Such problems would have to be balanced against the positive effect on the domestic oil industry and other benefits of reduced demand for imported petroleum.

The steep decline in crude petroleum prices during 1998 put pressure on oil companies ranging in size and scope from the smallest independent producers to the largest integrated "majors," and on oil field service firms as well as producers. Merging with and/or acquiring other firms is one way that oil companies try to increase reserve-finding efficiency and reduce costs, hoping to thereby improve financial performance. Factors in addition to lower oil prices, however, probably are contributing to, or have set the stage for, the recent surge in mergers and acquisitions; and mergers themselves put pressure on non-merged firms to find partners. Despite the revival in oil prices in 1999, mergers continue to be announced.

Among recent completed and/or announced mergers and acquisitions involving U.S.-based companies are the British Petroleum Company PLC (BP) takeover of the Amoco Corporation, Exxon Corporation's planned merger with Mobil Corporation, and BP/Amoco's planned takeover of Atlantic Richfield. Abroad, Total S.A. (France) merged with Petrofina S.A. (Belgium); Repsol (Spain) acquired YPF SA (Argentina); and Elf Aquitaine S.A. (France) has agreed to be acquired by TotalFina.

Perhaps equally significant, the fallout of consolidations of giant firms such as the above has included the growth and the strengthening of competitive positions by a number of large domestic independent firms through acquiring assets from the major integrated companies, but also from second-tier majors and from other independents.

Non-price developments in the last 15 years are highly relevant to the boom in mergers. Since the mid-1980s, large companies have been de-emphasizing oil production activities onshore in the United States (shifting to offshore U.S. and foreign activities), focusing on their core competencies and core geographic markets, and consolidating organizationally (partly through previous mergers). At the same time, improvements in exploration and development technologies have substantially reduced finding costs.43 (Such costs in the early to middle 1980s were driven up by the willingness of hopeful producers to spend in the context of high and rising oil prices.) As a result of these developments, cost-reduction and efficiency-improving options available to oil companies in the middle to late 1990s were diminished, leaving consolidation as one of the few remaining options.

Thus, when finding costs rose between 1995 and 1997 44 and oil prices fell in 1998, companies tended to look to mergers again (referring to the merger surge of the mid-1980s) as a performance-improving option. A merger can offer the prospect of a larger capital base, or better access to capital markets, to finance large up-front exploration and development costs of hopefully large finds, a larger number of "richer" prospects from which to choose (by virtue of a bigger menu), a dovetailing of operations in different phases of the oil business, and a reduction in overhead costs (by eliminating the duplication of staff and facilities). A larger capital base and greater diversity of operations also enable companies to better ride out periods of low oil prices. In addition, efficiencies may be gained in combining chemical operations, which constitute a not insignificant portion of most large "oil companies." Joint ventures (in any aspect of the business) may not always be workable alternatives to mergers, since criteria for business decisions may differ between firms.

Mergers, however, may have negative aspects. Sometimes they do not achieve the anticipated gains, and may even disrupt adequately functioning operations. Combining large oil companies (such as Exxon and Mobil) raises the issue of excessive concentration in production, refining, and/or marketing. However, it could be argued that concentration resulting from announced mergers does not appreciably reduce the number of crude oil suppliers to the United States inasmuch as numerous foreign and domestic corporate entities supply crude markets, with more than half of U.S. crude supplies coming from abroad. Also, due to antitrust or corporate efficiency considerations, many mergers have resulted in the sale of crude oil production assets to independent producers.

Notwithstanding, or even due to, the shifting of crude oil production assets described above, mergers might increase concentration in exploration and development. Larger companies tend to be attracted to larger fields (with potentially larger payoffs). And, with crude oil prices being set in a world market, the greater proficiency of merged companies in selecting and developing oil and natural gas prospects and the strengthening of large independents could displace some production by small U.S. producers. This, of course, would tend to counteract policy measures designed to sustain such producers.

Some are concerned about increasing concentration in the market for refined products, especially in geographic areas that are not well served by local refineries or long-haul pipelines. In such cases, U.S. regulators frequently require divestitures of some refining and marketing assets; and many mergers (past and recent) have resulted in the spinoff of refining and marketing operations. Many of these operations have been purchased by new, independent firms, and there has been an entry of foreign firms as well. However, at least for now, there remain geographic areas with relatively few suppliers; and mergers, divestitures, etc., often disrupt existing supply arrangements, affecting numerous independent distributors, retailers, and other marketers.

It is also argued that, if the potential efficiencies of mergers are achieved to at least some extent, economic benefits would tend to accrue to the U.S. economy and the oil industry. From this perspective, mergers should not be discouraged as long as undue concentration and displacement in one or more phases of the industry do not result. It should be noted, however, that small companies (producers and many service firms), may not have the size or scope of operations to capture the types of benefits from mergers like those cited above.

Mergers are one of the consequences of the decline in oil output and the total revenues of oil producers. With much lower output and less revenues, a smaller oil industry in the United States is a given, and the smaller oil industry need not be composed of the same number of firms doing business as when the U.S. oil industry produced twice as much crude. Firms tend to have a minimum size for survival, and the need to be large enough to operate profitably remains.

1 The average refiner acquisition cost for domestic and imported crude was $19.04/bbl in 1997, declining to $ 12.57/bbl in 1998. See: U.S. Department of Energy. Energy Information Administration. Monthly Energy Review. August 1999: p. 111.

2 American Petroleum Institute. Perkins, Jody M. Policy Analysis and Strategic Planning Department. Economic State of the US Oil and Natural Gas Exploration and Production Industry: Long-Term Events and Recent Events. April 30, 1999: p. 7-11. See also: "Comments on National Security Investigation of Imports of Crude Oil and Petroleum Products [Docket No. 990427107-9107-01] on behalf of the Independent Petroleum Association of America and the National Stripper Well Association." Viewable at http://www.ipaa.org/departments/govemment_relations/section%20232.htm

3 Royalties on production from federal leases are typically paid to the U.S. Treasury in cash. Royalty-in-kind means the royalty share is paid in physical barrels. For example, if a 12% royalty were due, the government would receive 12 of every 100 barrels produced on leases subject to that royalty.

5 A more detailed discussion of this particular issue appears later. See also: U.S. Congressional Record. Vol. 145, No. 125., SI 1277-SI 1347.

6 U.S. Department of Energy. Energy Information Administration. Monthly Energy Review, September 1999, p: 15.

7 U.S. Department of Energy. Energy Information Administration. Weekly Petroleum Status Report.

8 The 1999-2000 Winter Fuels Outlook, released by the Energy Information Administration of DOE on October 8, 1999, suggests that while supplies of winter fuels are expected to be "more than adequate," consumer prices "could be much higher than those of a normal winter season." See http://www.eia.doe.gov/emeu/steo/pub/wintout.html.

10 For some discussion of the potential economic costs of rapid fluctuations in energy prices, see: Oil Imports: An Overview and Update of Economic and Security Effects. CRS Report for Congress. December 12, 1997. 98-1-ENR, p. 6-7. Proposals in the past typically suggested an oil import fee of $.10/gallon as a starting point to achieve policy objectives. It is worth noting that the price increase during the spring and summer of 1999 has been in the range of nearly $10.00 per barrel, the rough equivalent of $.24 cents per gallon, and that this was altogether independent of public policy.

11 Secretary Says Disaster Relief Money Not in the Cards for the Oil Industry," appearing in Inside Energy/with Federal Lands, March 1, 1999: p. 7-8.

12 Last-Minute Legislative Efforts to Help Oil and Other Companies ..." appearing in Inside Energy/with Federal Lands, August 9, 1999: p. 20.

15 See: Inside Energy/with Federal Lands. Interior Spending Bill Conferees Cut Royalty Rule Delay to 180 Days. October 18, 1999: p. 15-6.

18 With some minor qualifications, an independent producer is one with average daily production of no more than 1,000 barrels of crude oil and/or 6,000,000 cubic feet of natural gas, and does not have any refinery operations.

19 Oil and gas well drillers must have no more than 500 employees; oil and gas exploration and/or other services must have no more than S5 million in annual sales.

20 See, for example, the remarks of Senator Nickles in the debate on H.R. 1664, Congressional Record, June 17, 1999: p. S7183. 21 Ibid, p. 7003.

22 See: Oil Daily. House Seen Likely to Support Oil-Loan Bill. June 21, 1999: p. 5. For mention of CBO estimates of the legislation's cost earlier in the debate, see: U.S. Congress. Congressional Record. June 15, 1999: p. S7002-S7003.

23 See: Oil Daily. Oil Producers To Benefit As Senate Tipped To Pass Guaranteed Loan Program. June 15, 1999: p. 5.

24 The section that immediately follows, "Economic Questions," discusses broader economic issues.

25 The proposal specifically authorizes loans through the end of calendar year 2001. Congress could, of course, extend this date.

26 See remarks of Senator Nickles, appearing in Congressional Record, June 15, 1999: p. S7002: "We are saying the Secretaries of Labor and Commerce and Treasury have better wisdom on whether or not to be making loans than bankers throughout the country."

27 Energy security refers to the availability of "adequate" energy supplies, particularly petroleum products (and therefore crude oil), so as to maintain economic performance and standards of living. Basically this means that demand and supply, including imported supplies, are roughly in balance. National security, as it relates to the energy industry, refers to the availability of energy supplies for the military to maintain or improve national defense and for the government to execute foreign policy.

28 Many bills have been introduced in the 106"' Congress to provide tax relief to the domestic oil industry (e.g., S. 162, S. 325, S. 595, S. 1042, S. 1050, H.R. 43. H.R. 423, H.R.497, H.R. 1116.H.R. 1971). Some of provisions in these bills were consolidated and incorporated into H.R. 2488, the Taxpayer Refund and Relief Act of 1999 (TRRA).

29 These and other energy-related tax expenditures (other than those for oil and gas) are discussed in greater detail in: U.S. Congress. Committee on Budget. Tax Expenditures: Compendium of Background Material on Individual Provisions. Committee Print. December, 1998. Prepared by the Congressional Research Service. U.S. Govt. Print. Off. Washington, 1998.

30 However, these limitations do not apply to marginal properties, i.e., oil produced from stripper wells, and heavy oil.

32 S. 595 (H.R. 1116 in the House) is a very broad bill that basically uses all the tax options to provide tax relief to the oil industry discussed earlier in the text: 1) tax relief by liberalizing current provisions; 2) reduction in some of the existing tax penalties, 3) introduction of new tax incentives, and 4) exemptions from general income tax provisions. In addition, this bill proposes a variety of ways to keep imports from exceeding a specified fraction of consumption (the ceiling cannot exceed 60%). Two other broad oil industry tax relief bills are H.R. 1971 (S.1042)and S. 1050.

33 Several state governments, in states where the oil industry has a sizeable presence, have enacted or are considering enacting tax breaks for their oil industries. In April, 1999, the Governor of New Mexico approved a tax credit for the drilling of a new oil or gas well. In May, 1999, the Kansas legislature approved a bill signed by the Governor that would provide Kansas oil producers with a refundable tax credit for 75% of the property taxes paid on marginal wells.

34 Schumer Seeks SPR Withdraw! to Ease Price, appearing in: The Oil Daily, Vol. 49, No. 182, Wednesday, September 22, 1999: p. 1.

35 Administration Downplays Idea of SPR Sale, appearing in: The Oil Daily,. Vol. 49, No. 185, p. 1-2. An administration official remarked that the Secretary's remarks had been "taken out of context."

36 U.S. Congress. Senate. Committee on Energy and Natural Resources. Energy Policy and Conservation Act Amendments. Report to accompany S. 1051. S.Rept. No. 106-163, September 27, 1999, p. 3.

37 Dismissal of Antidumping and Countervailing Duty Petitions: Certain Crude Petroleum Oil Products From Iraq, Mexico, Saudi Arabia, and Venezuela, 64 Fed. Reg. 44480 (1999). When a petition is filed requesting the imposition of antidumping or countervailing duties, U.S. law requires that the petition be filed "by or on behalf of the domestic industry involved. The Commerce Department applies a 25%/50% test to determine if this industry support requirement is met. 19 U.S.C. §§ 1671a(c)(4), 1673a(c)(4). The test requires that: (1) the domestic producers or workers who support the petition account for at least 25% of the total production of the domestic like product and (2) the domestic producers or workers who support the petition account for more than 50% of the production of the domestic like product produced by that portion of the industry expressing support for or opposition to the petition. Otherwise stated, "of those producers expressing a view, more producers [must] support than oppose the petition." S.Rept. 103-412, at 35. With regard to the SDO petition, the Commerce Department determined that the 50% requirement was not met; because of this, it did not address the second prong of the test.

38 Commerce Dismisses Controversial Dumping, Subsidy Cases on Crude Oil," International Trade Reporter (BNA), August II, 1999: p. 1330. "U.S. Agency Rejects Oil Dumping Complaint," The Washington Post, August 10, 1999: p. E4. See also: "Dumping Motion Filed; Mexico Eyes Retaliation," The Oil Daily, Vol. 49, No. 124, Wednesday, June 30, 1999: p. 1,3.

39 How U.S. May Avoid Massive Oil Import Duties," Petroleum Intelligence Weekly, Vol. XXXVIII, No. 27, July 5, 1999: p. 1, 4.

40 "0il Group Files CIT Complaint Against Commerce for Dumping Petition," Inside U.S. Trade, September 10, 1999. The standard of review to be applied by the Court is whether the Department's action was "arbitrary or capricious, an abuse of discretion, or otherwise not in accordance with law." 19 U.S.C. § 1516a(b).

41 An exporting country is not entitled to a material injury test in a countervailing duty case if it is not a WTO Member, it has not assumed subsidy obligations that are substantially equivalent to those imposed in the WTO Subsidies Agreement, or it is not a party to certain other trade agreements. 19 U.S.C. § 1671.

43 Finding costs are the per-barrel costs of adding new oil and gas reserves (or replacing reserves removed through production) by exploration and development activity. Such costs fell roughly 80% between 1981 and 1995 for large U.S. energy companies reporting to the Energy Information Administration (EIA). U.S. Department of Energy, EIA. Performance Profiles o)'Major Energy Producers 1997. Washington, January 1999. p.69-70.

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