Windfall Profit Tax Research Articles

Windfall Profit Taxation in Europe (and Beyond)

In 2022, the European Commission introduced, for the first time in its history, a windfall profit tax to be applied on “excessive” profits realized by qualified businesses operating in the “Oil and Gas” sector. Immediately after its implementation, questions arose as to its sustainability and its consistency with constitutional principles of the different member states regulating the domestic power to tax. To assess the consistency with the aforesaid rules, the article samples two countries, inside and outside the EU (Italy and Australia, respectively), and the historical precedents of the matter. Italy has been chosen due to the particularly stringent set of principles regulating the power of the legislature to tax, and Australia has been chosen because of the long-standing experience with superprofit taxes. In most of the scenarios analyzed, one common feature emerged: the complexity in defining the “Extra” nature of the profits and, consequently, the uncertainties in the calculation of the taxable base. In the case of Italy, for instance, the legislator had to intervene in several different moments to fine-tune the taxable base and restore certainty to the tax system. As a conclusion, while the taxation of extra profits should not per se be disregarded, its implementation demands a more robust and precise legal framework together with the understanding that the introduction of such a levy would be a one-way journey for the tax systems: windfall profits taxes would be here to stay.

Are the Windfall Profit Taxes Introduced by Regulation 2022/1854 Compatible with the Objectives of the European Green Deal?

To alleviate the pressure on households and businesses in the European Union (EU) caused by the recent energy crisis, EU institutions and Member States have implemented exceptional measures aimed at reducing electricity costs for consumers, and redistributing excess revenue from the energy sector to end customers. At the EU level, these measures have been implemented through European Council Regulation 2022/1854 that establishes a temporary income cap for ‘inframarginal’ electricity producers and a temporary solidarity contribution on windfall profits in the oil, gas, coal, and refining sectors. This goal of this article is to analyse these measures in terms of their impact and alignment with the objectives of the European Green Deal. Specifically, it will examine whether the ‘windfall profit tax for energy providers’ can be considered an environmental tax. Since this does not appear to be the case, the study will also evaluate whether the remaining measures outlined in the regulation can compensate for or mitigate the lack of a true environmental component in the ‘temporary solidarity contribution’. It will assess whether the compensation mechanisms provided by the EU Regulation are sufficient for reconciling the social and redistributive objectives with the environmental objectives of the European Green Deal. Windfall profit tax, regulation 2022/1854, European Green Deal, temporary solidarity contribution, excess profit tax, environmental taxation.

The Implementation of the Windfall Profit Tax for Energy Providers in Spain: Its Contested Compatibility With European and Constitutional Law

This contribution focuses (1) on the legitimacy of the temporary solidarity contribution approved by the Council Regulation (EU) 2022/1854, from a legal perspective considering the use of emergency law; and (2) the European law and jurisprudence in contrast with the Spanish implementation of the windfall profit tax on hydrocarbons providers to sort out its compatibility with the European law. The analysis carried out leads us to maintain some doubts about the legal mechanism used by the EU for its approval, as well as its compatibility with the fundamental freedoms of the EU. We are also critical of the Spanish implementation of the Temporary Solidarity Contribution. Both the Court of Justice of the EU and the European Court of Human Rights (ECtHR) will have the last word. windfall profits tax, energy tax, temporary solidarity contribution, EU tax policy, unanimity, qualified majority voting, Spanish temporary solidarity contribution, equality principle, non-discrimination, proportionality principle

Windfall Profit Taxes Across Europe: Have They Proved to be Effective for Taxing Windfall Profits in the Energy Sector?

In this article, the author provides details of the various windfall taxes that have been enacted in Europe in response to the increased profits of, in particular, the energy and banking sectors. The author describes the policy reasons that led Member States to agree on a windfall profits tax, how the tax has been implemented across European countries, the constitutional challenges and State aid issues that might arise in the context of EU law and various reasons for and against retaining such taxes.

Law & Economics in the Italian Constitutional Jurisprudence: The Case of the Windfall Profit Tax on Energy Companies

AbstractIn the judgment issued on 2 February 2015 the Italian Constitutional Court decided upon the constitutional legitimacy of the windfall profit tax imposed by the Italian government in 2008 on profitable energy companies. In his decision the Court disentangles the very economic foundations of such a tax and seeks to explain under its legal reasoning the market outcomes for the energy industry. The aim of this article is to assess the path-breaking law and economics methodology used, for the first time, by the Italian Court to scrutinize the very nature of the tax reform. In doing this, the authors discuss how the Court envisages both a micro and a macro-economic perspective in its analysis which, in turn, shall take into account the primary principles embedded in the Italian Constitution. The newly adopted methodology may entail a change of paradigm in the way the Constitutional Court carries out its own review of constitutionality with respect to domestic provisions with far-reaching economic and budgetary consequences.

Shale gas in Poland: An analysis of tax mechanismsand dynamic interactions

(ProQuest: ... denotes formulae omitted.)IntroductionTo date, not a single cubic meter of shale gas has been extracted and sold in Europe. While the substance still sits deep in the ground, it has already fuelled a fierce debate, protests, hopes and fears across the continent. Poland is the forerunner of exploration of natural gas from unconventional (shale rock) deposits. Nevertheless, little economic research has been conducted on the topic of shale gas in Poland. This exploratory study hopes to contribute to the scholarship on the topic.The aim of this article is to approach the study of shale gas from an economic perspective, with welfare at the centre of the analysis, and to deliver policy recommendations for the Polish government on the taxation of the shale gas extracting firms in Poland.The key result of the static analysis is that is that lump sum tax is the first best of all taxation methods. The second best option for taxation is a combination of the CIT and a windfall profit tax. From the dynamic perspective, this research argues that Gazprom can remain the market leader thanks to the sequential character of the competition in the Polish natural gas market, but this would not have negative welfare effects.This study is structured in the following way: section two introduces the topic of shale gas in Poland, section three elaborates on the methods, section four provides an analysis of the tax mechanisms from a static perspective, section five looks at the dynamic effects and sections six concludes the research.1.Shale gas in PolandThe Polish government initially offered the licenses to explore, or explore and extract, shale gas in the form of concessions. The second license type, to explore and extract, was introduced in order to simplify the market regulation and to attract investors. For a low price firms could purchase the right to explore and extract, regardless of the findings. Concessions are individual parcels of land. The price of each concession is determined by its size multiplied by a single rate that the Polish government sets per square kilometre (km2). A single rate applies to all concessions in the country. For exploration only, the price per km2 had been set at PLN 105.811 and for exploration and extraction PLN 211.622. In addition, the firm that bought the license only for the exploration process had the pre-emptive right to upgrade the license to extraction of shale gas. There were two reason behind this design. First was lack of knowledge about the quantity and quality of natural gas in the Polish shale rock formations. Second, the investors, not the taxpayers, bore the cost of exploration and the associated risk. Shifting the costs and risk associated with exploration process on investors was compensated by the government to the firms in the form of the pre-emptive right to purchase a license for extraction and the single exploration/extraction licenses. A new law, introduced in 2014, has combined previous types of concession into one, in a further effort to simplify access to the market. In all cases the legal set- up has ruled out auctions at the extraction stage. For this reason the Polish government has turned to taxation as a method to collect revenue from the potential shale gas extraction and sales. In the Polish government's view the 19 per cent profit tax is insufficient. Warsaw decided, in the 2014 change of law, to raise the potential revenue from taxation of shale gas firms by adding a complementary tax on fossil fuels, that depends on the profitability of the source, and can amount to 0, 12,5 or 25 per cent and also an additional tax of 1,5 per cent on the total value of extracted natural gas from shale sources. Nevertheless, collection of the complementary tax has been suspended until year 2020, in an attempt to stimulate the industry. Possibly, taxation of shale gas will be adjusted once again in the future. Without certainty about tax regulation and the size of the tax burden, investors are reluctant to invest in exploration or move from exploration to extraction; what harms consumers of natural gas in Poland. …

Economic and Legal Arguments in <i>PPL v. Commissioner</i>

In late February 2013, the U.S. Supreme Court will hear oral argument in PPL Corp. v. Commissioner. The Court took that case, which involves a claim by a U.S. corporation for foreign tax credits for taxes paid in accordance with the 1997 U.K. Windfall Profit Tax Act, in order to resolve a conflict between the Third Circuit, which denied the credit in PPL, and the Fifth Circuit, which allowed the credit in Entergy Corp. v. Commissioner. Nominally, the U.K. Act imposed a tax on recently privatized regulated companies of 23 percent of the difference between their estimated market value and the price at which they were sold to the public. The Act calculated each company’s market value by multiplying average earnings over a period of up to four years by 9 (a multiplier described as a conservative estimate of the market capitalization rate for such companies). The Fifth Circuit allowed the credit on the grounds that the substance of the tax imposed by the Act is a tax on the four prior years’ earnings, albeit at an effective rate higher than the statutory rate. In contrast, the Third Circuit denied the credit on the ground that the Act imposed a tax on a difference in values, not on income, as required by the Code and the applicable Treasury Regulation for the foreign tax to be creditable. This essay examines the economic and legal arguments that have been raised in PPL.

Taxes and US Oil Production: Evidence from California and the Windfall Profit Tax

The recent boom in US oil production has prompted debates on levying new taxes on oil. This paper uses new well-level production data and price variation from federal oil taxes and price controls to assess how taxes affected production. After-tax price elasticity estimates range between 0.295 (0.038) and 0.371 (0.025). Response along the shut-in margin is minimal. There is no evidence of spatial shifting of production to minimize tax liabilities. Taken together, the results suggest that taxes reduced domestic production in the 1980s, and the response largely came from wells that continued to pump oil, but at a reduced rate. (JEL H25, H32, L71, L78, Q35, Q38)

Sergei Paushok, CJSC Golden East Company, CJSC Vostokneftegaz Company v Mongolia

Paushok v Mongolia touches upon the delicate matter of investors challenging a country’s tax legislation. The case primarily concerns the introduction of a windfall profit tax (WPT) by the Mongolian Parliament, in times of skyrocketing gold prices, which levied a tax rate of 68% on any gold sales at prices exceeding USD 500 per ounce. The tax had a severe impact on the Mongolian gold mining industry and, in particular, on KOO Golden East-Mongolia (GEM), a company ultimately held by the Russian national Sergei Paushok. Its main competitor was KOO Boroo Gold, a gold mining company owned by Canadian interests. That company was not affected by the tax as it had entered into a stabilization agreement with the Mongolian government protecting it from tax increases as well as from the introduction of new taxes. GEM also applied for a sweeping stabilization agreement before the introduction of the WPT. However, negotiations...

Windfall Profits Tax on Oil and Gas: US and Latin American Approach

In terms of tax policy, the excess profit taxation is predominantly recognized as a wartime fiscal instrument designed to capture profits that exceed normal peacetime earnings. Nevertheless, excess profit taxation is also levied to prevent excessive profits in special circumstances other than wartime. United States in the 1980s and Bolivia and Venezuela in recent years have levied windfall profits taxes on oil and gas production. In light of the US legislative history, this article proposes three points of analysis from a tax policy perspective: first, the justification addressed to impose the levy; second, its attributes of efficiency; and third, the revenues and its distributive effects. To that extent, four features are analyzed as fundamental aspects of which a modern windfall profits tax on the oil and gas industry is imposed nowadays.

An Approach To Optimize Economics in a West Texas CO2 Flood

Summary EOR projects, notably CO2 floods, are the next generation of recovery methods in the more mature west Texas waterfloods. Installing and operating a CO2 flood can be extremely expensive. In this paper, we discuss methods used to make several active CO2 floods more profitable by reducing operating costs and deferring investments. Introduction Our goal in studying several active west Texas CO2 floods was to determine the optimum near-term cash flow, overall project economics (rate of return, present woth, etc.), and oil recoveries. We developed various CO2 flood designs with a reservoir simulator by altering specific operating parameters, including the half-cycle slug size, gas/water ratio (GWR), injection schemes, and total CO2 slug sizes. The resulting injection and production rates were then entered into an economic simulator to determine the most economical set of operating conditions. We also assessed the impact of various economic conditions - oil prices, CO2 prices, gas processing fees, and operating costs - on the optimization process. This was done to ensure that the optimum set of operating conditions did not change drastically should the economic environment change. This study shows how optimizing operations can significantly improve the economics of existing CO2 floods. An additional benefit of the study was insight gained on plant sizing and adjusting injection schemes to minimize or defer investments while maximizing the economics of new projects. Background During the late 1970's and early 1980's, Amoco Production Co. committed significant manpower to evaluate the feasibility of full-scale CO2 flooding in west Texas. Before the feasibility work, Amoco undertook numerous CO2 pilots in various fields.1 Because of high crude prices, optimistic price forecasts (Fig. 1), and successful pilot recoveries, the future of CO2 flooding looked promising. The approach taken at the time was first to history match waterflood performance with an in-house black-oil simulator.2 The resulting reservoir description then was transferred to a streamline generating model and finally to a miscible streamtube model. The CO2 prediction was done at a single GWR with the CO2 injection slug size changed to find an optimum based on present worth. The reservoir simulation provided oil, gas, and CO2 production rates and CO2 injection rates for input into an economic model. Because of the man-hours and computer time involved in simulating the CO2 process, only a few GWR's were tried, with slug size as the main variable. In these early CO2-flood designs, CO2 reinjection was planned and a plant design was needed to remove H2S and hydrocarbons and to handle the peak predicted total gas production. Because of the single GWR being used, the gas rate was expected to increase to some peak and then decline, leaving excess plant capacity. This type of injection scheme impaired the economics because a large plant investment was needed at the beginning of the project. Unless there was an offset property feasible for CO2 flooding, the excess plant capacity went unused once the peak was past. The costs of plants and other investments were relatively high compared with today's environment because of high oil prices and high inflation rates. Most projects were still economical, however, because oil price forecasts were optimistic and tax relief from the Windfall Profits Tax was granted for EOR projects. One shortcoming of this early approach was the optimistic nature of the miscible streamtube model. Although this model adequately handled loss of miscibility, it was unable to regain it should the pressure rise above the miscible pressure. The model also was too efficient in areal sweep: the displacement was piston-like through the streamtube and all streamtubes were eventually swept for nearly 100% areal sweep efficiency. Injectivity losses also were handled inadequately in the streamtube model. Water hysteresis was accounted for, but solvent relative permeability effects3,4 were not. The miscible streamtube model also had limited ability to make changes in the pattern configuration and injection schemes. If such changes were to be made, the streamline generator had to be run again for entry into the miscible streamtube model. This was both time-consuming and costly. As a result of these model shortcomings, many economic sensitivities were run with various rate and reserve scenarios to become comfortable with the final CO2-flood design.

The Evolution of Economic Forecasts and Risk Adjustments in Property Evaluation in the U.S.

Summary The evaluation engineer generates not only reserve projections, but alsocash flows and often fair-market-value (FMV) estimates. These tasks requireecopolitical assumptions in addition to the technology involved. This paperdiscusses the evolution of economic and risk considerations into current"industry-accepted" practices and the engineer's role in the evaluationprocess. Introduction Given that a company's reserve base is its collateral and source ofoperating funds, it is not surprising that a need has long existed for reserveevaluations to facilitate financial reporting requirements. These uses requireprojections of cash flow, net profit, payout, and expenditure. The generalpayout, and expenditure. The general acceptance of the "time value ofmoney" concept added the need for discounting and rate-of-returnindicators. Increasingly, political considerationse.g., conservation, politicalconsiderationse.g., conservation, prorationing, and pricing regulationshaveprorationing, and pricing regulationshave affected U.S. domestic reserveevaluations. Converting a reserve estimate to a cash-flow projection oftenrequires reservoir engineers projection often requires reservoir engineers toexercise judgments on subjects beyond their areas of technical expertise. Although reserve evaluations traditionally exclude quantitative riskconsideration, the engineer is frequently requested to estimate FMV, whichinvolves producing property risk in all its many guises. In response toindustry's increasingly complex evaluation needs, evaluation engineering hasevolved into a distinct subdiscipline. The typical evaluator is an experiencedreservoir engineer with sufficient exposure to evaluation requirements torecognize both the physical and the ecopolitical uncertainties involved. Thehighest degree of professionalism is required because the reserve evaluator hasa fiduciary responsibility to the investor or management. These "endusers" depend on the evaluator to use "accepted" or"standard" industry practices when such standards are seldom defined. Estimating FMV and the evaluation engineer's role in this process is not fullyunderstood within industry and remains a mystery to outsiders. Reserve Evaluation The first reserve evaluation apparently has been lost in history, but thefirst bank oil loan was reported in 1928. Petroleum engineering was in itsinfancy. Because of the lack of accurate technical data and the chaos thatexisted in marketing, early evaluations could hardly have been more than roughestimates. The introduction of conservation, prorationing, and tax laws duringthe 1930's prorationing, and tax laws during the 1930's and 1940's gave a morereliable data base from which to estimate reserves. After the East Texas fieldwas prorated and the U.S. economy strengthened in the late 1930's, domesticdemand began to exceed supply. Oil prices improved enough to allow expansion tobe financed by cash flow. After World War II, supply overtook demand owing tolarge U.S. discoveries and some displacement of U.S. crude by gas and non-U.S.oil. As a result, producing rates, particularly in Texas, were further limitedby particularly in Texas, were further limited by prorationing, making itharder to finance prorationing, making it harder to finance operations out of areduced cash flow. Bank borrowing became necessary, which increased the demandfor reserve evaluations. Postwar technical advances greatly improved theaccuracy of reserve projections. Industry-accepted reserve evaluation methodsbegan to emerge and reserve definitions were established. Evaluating reservesbecame a fairly routine engineering procedure where the only ecopoliticalprocedure where the only ecopolitical considerations were the allowable and thenumber of producing days in Texas. Pricing was constant and reserve projectionswere based on top allowable or exponential declines. More than 90% of theevaluation effort dealt with the technical aspects. Reservoir engineering andpetroleum geology continued to mature as disciplines. Data-gathering tools forlogging, coring, and testing became more accurate and comprehensive. Theevaluator needed increased expertise as secondary recovery became widespreadand offshore drilling introduced new concepts in the 1960's. The threatened orshort-lived oil embargoes in the late 1960's were an unheeded presage. When oilprices increased in 1973, presage. When oil prices increased in 1973, engineerswere faced with the need to forecast economic parameters. Close on the heels ofescalating energy prices was political reality in the form of oil pricepolitical reality in the form of oil price controls, the 1978 Natural Gas Policy Act, and the U.S. government's ultimate solution to the energy crisisthe Windfall Profit Tax. These political constraints combined with increasingoptimism about oil and gas prices began to relegate engineering to a secondary role. JPT P. 220

Regional Impacts of Petroleum Price Regulation: The Case of Texas, 1973-1983

A dynamic engineering-based econometric model of the Texas petroleum industry is used to jointly assess the impacts of federal price controls and the windfall profit tax, on both oil and gas supply, over the period 1973-1983. Comparing simulation results obtained using actual prices, and then counterfactual, uncontrolled prices, show small but persistent losses in aboveground production but considerably larger percentage impacts in drilling activity and new reserve additions. Thus, the long-run opportunity costs of post-embargo energy policy may not be fully reflected in traditional calculations that use constant supply elasticities to calculate annual supply impacts without regard to previous years’ prices or production levels.

Assessing the impact of the windfall profits tax on the US economy

The paper focuses on the effect that the elimination of the windfall profits tax (WPT) on crude oil would have on the various producing sectors, consuming sectors and household categories in the USA, where the interrelationships between these entities are explicitly considered. Special attention is given to the agricultural sectors of the economy. Thus, in the context of a general equilibrium model, the effect of the elimination of the WPT on the producing sectors in general and the three agricultural sectors plus forestry in particular, on the consuming sectors, on households and on the Government is calculated. Over the period 1984–1990, such a policy initiative would result in higher output by the non-crude-oil producing sectors (by about $1.783 billion), higher consumption of goods and services (by about $1.651 billion), and an increase in welfare (by about $1.625 billion). The Government will realize a decrease in revenue of about $1.362 billion while the domestic crude oil industry will experience an increase in output of approximately $1.217 billion. For the agricultural sectors, output overall will fall. Specifically, for the programme crops sector, output will decline by $39 million, for the livestock sector, output will fall by $14 million, for all other agricultural commodities, output will decline by $36 million and for forestry, output will be reduced by $29 million. Attendant on these reductions in output will be lower prices for the respective commodities.

The crude oil windfall profit tax act of 1980: An economic analysis of its effect on domestic crude oil production

In this paper a framework is developed to examine the effects of the Crude Oil Windfall Profit Tax Act of 1980 on domestic production of crude oil that specifically takes into account both the pre-existing system of price controls the Act replaced and the temporary nature of the tax. The Act established three categories of oil, called tiers, which are taxed at different rates on the difference between the removal price and an adjusted base price. Tiers two and three comprise most of the oil that was not controlled prior to 1980, whereas tier one comprises essentially all oil that was subject to price controls before 1980. Assuming that the market for oil is competitive, and given reasonable assumptions about extraction costs, the Act will increase the production of crude oil from tier one above the level that would have been produced had the price controls remained in effect for the same length of time, although less than the socially optimal amount of oil will be extracted from tier one while the tax is in effect. Because the tax is temporary — it is scheduled to expire by 30 September 1993 at the latest — production after the tax is phased out is relatively more attractive than it would otherwise be. Thus, before it is phased out, the Act will reduce production of oil from tiers two and three below the socially optimal level of extraction.

The Great Plains Gasification Project: The Problem of Juridical/Administrative Incompatibility

Such is the public memory (and so completely has the problem vanished from the scene) that some will recall only with difficulty the vast and costly program on which President Jimmy Carter staked so much-to reduce the American dependence on imported petroleum through the production of substitute synthetic fuels from coal. The major component of that program was a project to produce a synthetic natural gas from coal. And yet even in 1982 in a special issue of The Energy Journal devoted entirely to natural gas, so absorbed were the authors with the process of decontrol, market distortions in a situation of partial decontrol, and apprehension at the prospect of a possible windfall profit tax that the matter of synthetic fuels had dropped entirely out of sight. There was not a single mention of Project Independence. Nor was there any concern for the fundamental problem of replacing a depletable and rapidly depleting resource.

Historical Trends and Current Production of Gas From Tight Formations (includes associated papers 16461 and 16645 )

Summary. Low-permeability (tight) formations are an acknowledged majorsource of future U.S. natural gas supplies. The unproven recoverableresource potential, as estimated by the Natl. Petroleum Council (NPC), ison the order of 500 Tcf [14.2 × 10 m ] at prices and technologies currentat the time of the study. The NPC study and other analyses have pointed tothe significance of tight gas in future supplies, but the role it plays incurrent reserves and production has not been so clearly defined. We have estimated the volume of gas produced from tight sands inrecent years, calculated ultimate recovery and proved reserves associatedwith this production, and compiled quantitative descriptions of 663 fieldscurrently producing tight gas. Data limitations constrained the study tothe western and southwestern states, which account for about 85% of U. Stight-gas production. To provide national tight-gas production volumes, however, estimates based on aggregate data were also made for Appalachia. Introduction In the late 1960's and early 1970's. low-permeability(tight) gas-bearing formations were recognized as the nextmajor source of natural gas. offsetting, the predictabledecline in conventional reserves. This realizationexpanded rapidly after the 1980 publication of a majorassessment of the tight-gas technical and economic Potential, conducted over 2 years by a multicompany, working groupof the NPC. NPC estimated that, given specifiedtechnology advances, as much as 500 Tcf- [14.2 × 10–12 m3 ]of tight gas could be produced at prices up to the gasequivalent of the world oil price. Several studies, sponsored by the federal government, the NPC, and the Gas Research Inst. (GRI), haveanalyzed the overall resource and its potential response toeconomic and technological stimuli. An automatedversion of the NPC study data and methodology has beenconstructed to allow sensitivity analyses using updatedresource, technology, and cost data. None of these, however, quantified the actual role of tight gas in supplyin recent years. This role needs to be clarified todetermine whether tight gas is beginning to be produced in theamounts suggested by studies of its potential. Specifically, this paper distinguishes how much of recent gasproduction has come from tight formations. This study does not production has come from tight formations. This study does not address the extent to which estimates of the undiscoveredtight-gas resource may coincide with estimates ofnontight or conventional undiscovered resources. Special Economic Incentives for Tight-Gas Production. The Natural Gas Policy Act of 1978 (NGPA) graduallyphased out price controls on new gas and provided phased out price controls on new gas and provided incentive or decontrolled pricing for certain types of gasdeemed to be high cost, including gas from tightformations. To receive the incentive price established for tightgas, an operator must first secure the approval of stateregulatory bodies to designate an individual formation ina specific geographic area as "tight" in accordance withcriteria established by the Federal Energy Regulatory Commission (FERC). In addition, in a provision of the Crude Oil WindfallProfit Tax Act of 1980, the Internal Revenue Service Profit Tax Act of 1980, the Internal Revenue Service provides for an unconventional gas tax credit in lieu of the provides for an unconventional gas tax credit in lieu of the incentive price in any tax year except those in which anincentive price is taken. This tax credit is a function ofthe price of oil so that declining oil prices are met witha corresponding increase in the tax credit. The intent ofthis provision, in effect a price support, is to minimizethe incentive to switch from tight gas to oil when oil pricesdecrease. The nature of these two economic incentives-providingeither higher prices when gas is in short supply or taxcredits when it is not-creates a situation that isbeneficial to tight-gas producers. Regardless of gas marketconditions, these incentives are available only for gasproduced from wells in FERC-designated formations. produced from wells in FERC-designated formations. Thus, at all times, this encourages operators to seekdesignation for qualified tight formations. This study assumedthat, because of these available economic incentives, thoseareas designated as tight by the FERC will make up theareas where the majority of tight gas will have beenproduced in the past and will likely be produced in the near produced in the past and will likely be produced in the near future. By Aug. 1984, FERC had approved 171 separatearea/formation designations throughout the U.S., mostlyin the west and southwest. where tight gas is known tohave been produced for some time. JPT P. 77

The 1984 Natl. Petroleum Council Study on EOR: An Overview

Summary An overview of what is considered the most extensive EOR study ever accomplished is discussed. In this study, 86 persons from 34 companies worked over a period of 17 months to develop a document that indicates the direction that EOR might take for the next 3 decades. Projected production, based on both implemented and advanced technology, is Projected production, based on both implemented and advanced technology, is presented to show the effect of changes in price of crude and minimum rate presented to show the effect of changes in price of crude and minimum rate of return (ROR) requirements. The study indicates that EOR could increase the current domestic crude reserves by about 40%. It also indicates that the ultimate recovery and the projected producing rates of EOR projects are highly sensitive to changes in crude oil prices. Introduction The Natl. Petroleum Council (NPC) is a board of industry leaders established solely for the purpose of advising, informing, and making recommendations to the Secretary of Energy on any matter relating to the petroleum industry. In 1976, the NPC developed a study on EOR covering state of the art, future amounts to be produced, and policy considerations. On March 10, 1983, the Secretary of Energy requested that the 1976 study be updated and expanded where necessary. Therefore, a committee on EOR and a coordinating subcommittee were established. The coordinating subcommittee formed four task forces specializing in chemical, miscible, and thermal recovery processes and costs and economics. processes and costs and economics. The resulting study is presented in the following format. Chap. 1-Background of Oil Recovery Operations Chap. 2-Developments Affecting EOR Since 1976 Chap. 3-Analysis Considerations and Procedures Chap. 4-Potential for EOR Chap. 5-EOR in Perspective to Other Energy Sources Chap. 6-Policy Considerations. The Appendices present important information too detailed to include in the main part of the report. Appendix A-Request Letter Appendix B-Rosters Appendix C-Additional Economic Considerations Appendix D-Chemical Flooding Appendix E-Miscible Flooding Appendix F-Thermal Recovery Appendix G-Environmental Considerations Appendix H-Research Progress and Future Implications This paper, which presents an overview of the study, was presented in conjunction with three companion papers 1–3 that provide analyses of the specific processes. papers 1–3 that provide analyses of the specific processes. The NPC Study Chap. 1 Background of Oil Recovery Operations. The API and DOE estimate that a total of about 481 × 10(9) bbl [76.5 × 10(9) m3] crude liquids have been discovered in the U.S. Of this, 130 × 10(9) bbl [20.7 × 10(9) m3] (27%) have been produced and 28 × 10(9) bbl [4.5 × 10(9) m3] (6%) are expected to be produced under existing technical and economic conditions. This leaves 323 × 10(9) bbl [51.4 × 10(9) m3] (67 %) of conventionally unrecoverable hydrocarbons as an upper-limit target for EOR techniques. Current EOR projects are providing 0.5 X 10(6) B/D [79.5 × 10(3) m3/d] (6%) of the total production of 8.6 × 10(6) B/D [1.4 × 10(6) m3/d]. Chap. 2 Developments Affecting EOR Since 1976. Since 1976, several factors have affected the EOR programs of many companies. The decontrol of oil allowed programs of many companies. The decontrol of oil allowed the effective price of crude to seek its market value, resulting in an increase of as much as 100% in constant dollars. Additionally, the Tertiary Incentive Program met with great success and contributed to the initiation of 423 projects operated by more than 100 companies. projects operated by more than 100 companies. Because of the provision that reduces the burden on tertiary recovery, the Windfall Profit Tax stimulated some projects, primarily those with low initial investments. projects, primarily those with low initial investments. Chap. 3 Analysis Considerations and Procedures. Developing and Verifying a Data Base. A data base was initially provided for the study by the DOE to expand this information to include as many domestic reservoirs with more than 20 × 10(6) bbl [3.2 × 10(6) m3] original oil in place (OOIP) as possible and to check the accuracy of the place (OOIP) as possible and to check the accuracy of the data, questionnaires on 1,300 reservoirs were completed by 18 different companies. The resulting data base, supplemented by information provided by Lewin and Assocs., included 2,500 reservoirs provided by Lewin and Assocs., included 2,500 reservoirs containing approximately 73 % of all the OOIP in the U.S. estimated by the most recent (1980) API state-by-state analysis. A size distribution study of the data base, shown by Fig. 1, indicated that the largest 35% of the reservoirs (those greater than 50 × 10(6) bbl [7.9 × 10(6) m3] OOIP) contained 92% of the OOIP. Related papers: SPE 13239, SPE 13240, SPE 13241 Related discussions and replies:SPE 18397, SPE 20007, SPE 20009

Microcomputers and Petroleum Economics Software: A Purchaser's Guide

Summary Microcomputers with software designed specifically for the petroleum industry can provide a highly cost-effective alternative to petroleum industry can provide a highly cost-effective alternative to manual calculation and timeshare computer use in many applications. Understanding the types of hardware and software available and the limitations to their use is critical to the user. Software availability and limitations are often difficult to assess without insight into each alternative. Information that is important in the selection of a microcomputer system suited to the needs of any company can be identified through definition of the intended use and matching this use to the available systems. Introduction With the advent of microcomputer technology, many hardware and software manufacturers have developed products to tap what appears to be a virtually limitless products to tap what appears to be a virtually limitless market of ideal applications. High on the list is the petroleum industry with its large capital outlays for technical petroleum industry with its large capital outlays for technical support, accounting sophistication, and need for managing and processing large amounts of data. To screen the market for the type of computer, peripheral equipment, and software to suit the needs of a specific peripheral equipment, and software to suit the needs of a specific company or individual requires some education on the capabilities and limitations of each product. The following discussion identifies the options available in purchasing these products with specific software emphasis on purchasing these products with specific software emphasis on petroleum economics. Included is a discussion of the petroleum economics. Included is a discussion of the advantages and disadvantages to the use of microcomputers in petroleum economics as well as a table outlining typical costs associated with such a system. A glossary of computer classifications and commonly used computer terms is also provided. Petroleum Industry Petroleum Industry Microcomputer Applications Microcomputers provide an ideal source of computer support for many petroleum applications, particularly for smaller companies, energy banks, petroleum consultants, and individual departments of larger companies. Their chief limitation relates to the speed at which they process certain types of information and their internal memory that is used to store the program and data in use at any given time. Current applications for microcomputers for which software is available are listed below. The degree of sophistication for some of these applications is substantially inferior to what may be obtained on a larger computer (i.e., reservoir simulation, computer-aided design, and production control). 1. Production accounting--storage of accounting information such as general ledgers, joint-interest billing information, and Windfall Profits Tax information. 2. Production data base--storage and organized retrieval of historical production information. May provide information directly on government reporting forms, graphs, or in tabular format. 3. Petroleum economics--calculation of typical profit indicators, cash flows, and other parameters on the basis of projected producing rates, taxes, operating expenses, and investment assumptions. Often used in acquisition evaluations, prospect reviews, reserve surveys, and bank loan reviews. 4. Reservoir engineering--basic reservoir simulation, material balance calculations, transient pressure analysis, log analysis, and subsurface mapping and contouring. 5. Computer-aided design--basic pipeline and plant design, subsurface equipment sizing, and production equipment selection. 6. Production control--physical control of minor plant process functions, well testing, and volume monitoring. process functions, well testing, and volume monitoring. 7. Other--microcomputer technology is improving very rapidly with new software applications emerging constantly to meet the needs of the petroleum industry. As the sophistication of the hardware improves, so will the number of applications expand. Hardware Selection In this section, hardware options available to the computer purchaser will be discussed with recommendations for those particularly useful in petroleum applications. The Computer. Microprocessor. In the past, the vast majority of generic software was written for the Zilog Z-80 or Intel 8080 microprocessor under the Digital Research CP/M operating system. Since 1982, however, current business software, including that specific to the petroleum industry, has been written for the Intel petroleum industry, has been written for the Intel 8088/8086 (or 80286) series microprocessor under the Microsoft Corporation MS-DOS operating system. For this reason, computers that use the Intel 8088/8086 (or 80286) series are recommended in petroleum engineering applications. JPT P. 337

Solar Versus Conservation Tax Credits

In the late 1970s concern about energy shortages motivated Congress to establish federal income tax credits to individuals for (1) household energy conservation expenditures and (2) purchases of renewable energy systems. Under terms of the Energy Tax Act of 1978, the tax credit for conservation expenditures is 15 percent of the amount invested, with a maximum credit of $300. The credit for renewable energy systems (such as solar space or water heaters) was initially set at 30 percent of the first $2000 and 20 percent of the next $8000. In 1980, the Windfall Profit Tax Act increased the tax credit for renewable energy systems to 40 percent of the first $10,000 in qualifying expenditures-a maximum credit of $4000.