Print this page
Email to a friend
Issues ยป Archived Testimony
Testimony Of David S. Hall
On Behalf Of The
Independent Petroleum Association of America
And The
National Stripper Well Association
Before The
Committee on Ways and Means
Subcommittee on Select Revenue Measures
U.S. House of Representatives
June 13, 2001
Statement Of David S. Hall for The
Independent Petroleum Association Of America
and The
National Stripper Well Association
and
|
|
Mr. Chairman, members of the committee, I am David S. Hall, Manager of Taxation for Berry Petroleum Company (an independent heavy oil producer since 1909), of Taft, California, and Chairman of California Independent Petroleum Association's (CIPA) Economic and Policy and Taxation Committee. I am also a member of the Tax Committee of the Independent Petroleum Association of America (IPAA). This testimony is submitted on behalf of the IPAA, the National Stripper Well Association (NSWA), and 33 cooperating state and regional oil and gas associations. These organizations represent independent petroleum and gas producers, the segment of the industry that is damaged the most when domestic energy policy does not recognize the importance of our own national resources. NSWA represents the small business operators in the petroleum and natural gas industry, producers with "stripper" or marginal wells.
Today's hearing addresses the effect of Federal tax laws on the production, supply and conservation of energy. I have attempted to answer your challenge by examining a critical issue confronting domestic petroleum and natural gas production - the role of the tax code with regard to the enhancement or deterioration of domestic exploration and production of natural gas and crude oil. To put this issue in a clear perspective all we have to do is look to the 1999 National Petroleum Council (NPC) Natural Gas study. The last NPC study of crude oil was done in 1994 and addressed Marginal Wells only. The 1999 study concluded that U.S. demand for natural gas would increase by over 30 percent during the next ten years. It also identified four general areas that must be addressed to assure that this clean burning fuel will be adequately supplied to America's consumers. These are: access to capital, access to the national resource base, access to technology, and access to human resources. The federal government is a significant - if not pivotal - factor in two of them: access to the resource base and access to capital. The federal tax code plays an integral part in providing access to the capital essential to develop domestic resources - both natural gas and crude oil.
Federal tax policy has historically played a substantial role in developing America's natural gas and crude oil. Early on, after the creation of the federal income tax, the treatment of costs associated with the exploration and development of this critical national resource helped attract capital and retain it in this inherently capital intensive and risky business. Allowing the expensing of geological and geophysical costs and percentage depletion rates of 27.5 percent are examples of such policy decisions that resulted in the United States' extensive development of its petroleum.
But, the converse is equally true. By 1969, the depletion rate was reduced and later eliminated for all producers except independents. However, even for independents, the rate was dropped to 15 percent and allowed for only the first 1,000 barrels per day of crude oil (or equivalent natural gas) produced. A higher rate is allowed for marginal wells, which increases as the crude oil price drops, but even this is constrained - in the underlying code - by net income limitations and net taxable income limits. In the Windfall Profits Tax, federal tax policy extracted some $44 billion from the industry that could have otherwise been invested in more production. Then, in 1986 as the industry was trying to recover from the last long petroleum price drop before the 1998-99 crisis, federal tax policy was changed to create the Alternative Minimum Tax that sucked millions more dollars from the exploration and production of crude oil and natural gas. These changes have discouraged capital from flowing toward this industry. And, without capital the ultimate result is lower production. Since 1986, domestic crude oil production has dropped by over 2.5 million barrels per day.
Now, independent producers are recovering from the low prices of 1998-99 that starved the industry of funds to maintain existing production and to explore and generate new production - production of both crude oil and natural gas. Today, we look at a world where petroleum production is perilously close to petroleum demand. In late 2000 essentially all countries except Saudi Arabia were producing at full capacity. Later this year as seasonal demand increases, we could well return to a similar situation. Today, we look at natural gas and crude oil supplies struggling to meet demand in the United States primarily because of the loss of capital when crude oil prices fell. Today, we have a domestic industry ready to find and produce energy for the nation's consumers, but this inherently risky industry must compete for funds against other more appealing investments and the lure of lower costs to produce foreign oil.
Hearings throughout Congress have echoed with the statements of members from producing and consuming states alike that more must be done to increase domestic production. The question is how. Much of that answer lies within this Committee.
Near Term Actions
In the near term there are a number of actions that can be taken. In fact, there has been wide agreement on these actions between Republicans and Democrats. Numerous bills have been introduced in the House and Senate with substantial sponsorship during the 106th Congress and now in the 107th Congress. In the House, H.R. 805 has been introduced with a number of exploration and production provisions and in the Senate S. 389 and S. 596 - both of the comprehensive energy bills - include a tax title with key provisions.
First, action should be taken to clearly allow expensing of geological and geophysical costs and of delay rental payments. Congress has passed these changes. These changes would clearly aid the development of new wells and they reflect historic practice in treating these costs. (IPAA Fact Sheets detailing these issues follow this testimony.)
Second, there is wide support for a countercyclical marginal well tax credit. This approach was recommended by the National Petroleum Council in its 1994 Marginal Wells study. This tax credit today can be crafted with a negligible impact on the federal budget, but at the same time create an important safety net for the most vulnerable American producing wells - wells that produce petroleum roughly equivalent to imports from Saudi Arabia - wells that are the nation's true strategic petroleum reserve. (An IPAA Fact Sheet detailing this issue follows this testimony.)
Third, Congress has suspended the property taxable income limitation on percentage depletion for marginal wells through 2001. The tax bill passed by the 106th Congress would have suspended this provision through 2004. The suspension that was in place in 1998 and 1999 saved many marginal wells during the price crisis. This provision should be permanently eliminated to provide domestic producers of these wells an incentive not to plug the wells during a low price cycle. Once the well is plugged, the potential to produce the remaining reserves is lost forever. (An IPAA Fact Sheet detailing this issue follows this testimony.)
Fourth, the 106th Congress' tax bill would have also suspended through 2004 the 65 percent net overall taxable income limit on percentage depletion. This constraint on independent producers limits the amount of capital that can be retained for reinvestment into existing and new production. In an industry that typically reinvests 100 percent of its profits back into the industry, this constraint means less domestic crude oil and natural gas. It too should be eliminated. (An IPAA Fact Sheet detailing this issue follows this testimony.)
The number of independent producers qualifying for percentage depletion has decreased. Percentage depletion has been further limited as a result of mergers and acquisitions of the various producers as they seek ways of reducing their costs, consolidating production fields, and operating more efficiently. However, percentage depletion remains very important to the small producer with marginal well production. Limiting the number of barrels qualifying for percentage depletion and artificially lowering the rate in a declining industry is counterproductive. Increasing the number of barrels qualifying and/or increasing the depletion rate would go a long ways to help the small independent when prices are low.
Fifth, the 106th Congress' tax bill extended the net operating loss carryback period for independent producers to five years. This approach or one that would allow for the carryback of carried over percentage depletion that was limited by the 65 percent net taxable income limit both have been introduced in the 107th Congress. Taken together with the changes passed regarding percentage depletion, millions of dollars would be made available based on costs and losses already incurred to enhance domestic production.
Collectively, these provisions have wide support. They would be of significant national value. They should be enacted now. Equally important, they must be crafted in such a manner to assure that the Alternative Minimum Tax does not nullify the benefits that they would create. The mistake of 1986 should not be repeated. When the industry is in desperate need of capital, it should not be stripped away.
Next Steps
For the future, the country needs to look toward tax policies to encourage domestic production of its crude oil and natural gas. The AMT remains a constriction. While the AMT was modified to exclude percentage depletion from the calculation of the alternative minimum taxable income (AMTI), independent producers remain subject to the AMT with regard to intangible drilling costs (IDCs). Specifically, if "excess intangible drilling costs" exceed 65 percent of net income from all oil and gas production, these costs are "potential preference items". AMTI cannot be reduced by more than 40 percent of the AMTI that would otherwise be determined if the producer was subject to the IDC preference. This 40 percent rule forces some independent producers - particularly smaller ones - to curtail drilling once the expenditures become subject to the AMT. Now is a time when drilling needs to increase significantly. The 1999 NPC Natural Gas study estimates that the number of wells drilled needs to double over the next fifteen years. Independent producers drill 85 percent of domestic oil and gas wells. It makes no sense for the federal tax code to be a barrier to this effort.
Some of the future focus also needs to be directed to getting more out of existing resources. For example, it is clear that the Enhanced Oil Recovery tax credit has added millions of barrels of crude oil production and continues to assist in recovering the economically higher-cost significant heavy oil reserves using technologies that have been proved to work for more than twenty years. This provision should be reviewed with the intent of examining and adding appropriate EOR methods as qualified methods. (An IPAA Fact Sheet detailing this issue follows this testimony.)
Equally significant, policies need to address encouraging more new development. Proposals to encourage domestic exploration and production should be created. A number of concepts are already in play and need to be more fully evaluated.
For example, the Section 29 tax credit for unconventional fuels proved to be a strong inducement to developing those resources. It applies to wells drilled prior to 1993 and uphole completions thereafter. Just last July, the Federal Energy Regulatory Commission acted to reinstate its certification process to address many wells that would otherwise qualify for the Section 29 tax credit. But, the existing credit expires in 2003 and provides no incentive for current development since the qualifying wells had to have been drilled before 1993. S. 389 extends the existing credit and creates a second drilling window that also applies to heavy oil. In early May, Steve Williams, President of Petroleum Development Corporation in Bridgeport, West Virginia - and a member of IPAA's Tax Committee - testified regarding Section 29 before this subcommittee. His testimony included several recommendations regarding Section 29 and IPAA commends that testimony for your consideration.
Fundamentally, the question facing the nation is how to marshal the capital to develop its domestic resources. The 1999 NPC Natural Gas study estimates that an additional $10 billion over and above the current expenditure level will need to be invested annually in domestic production over the next fifteen years to meet the expected demand. This investment is essential to provide for the supply increase of approximately 30 percent over this time period. So far, this target does not appear to have been met. The NPC study was based on 1998 actual information. From 1998 through 2000, domestic natural gas production has increased by about two percent - an average one percent per year - roughly half the amount needed. Some of this limitation reflects the consequences of the 1998-99 oil price crisis as it played out in natural gas development. Now, natural gas drilling rigs are at record levels constrained in part because of rig availability. The success of this activity is showing up in increased natural gas reserves, but it is important to recognize that - over the past five years - domestic natural gas reserve replacement has essentially stayed even. To meet future demand increases reserves must grow appreciably. Moreover, in recent years the depletion rate for domestic production has increased substantially to now average 24 percent per year - with some significant Gulf of Mexico fields depleting at rates exceeding 40 percent per year. New production must not only overcome this depletion, it must grow in absolute terms.
With regard to domestic oil production, the challenge is to maintain existing production levels to (1) reduce foreign dependence and (2) to assure the existence of a healthy domestic exploration and production industry. For example, while natural gas drilling rig counts are at record rates, domestic oil rig counts are essentially half of their 1997 level. Heavy oil production and development budgets in California has been drastically cut as the result of: 1) record high Southern California border natural gas prices, 2) the California utilities cash-flow problems including a bankruptcy, and 3) the non-payment to some qualified facilities (QF's) that produce electricity for sale. The sale of electricity offsets the cost of the co-generation steam, which is injected into the reservoir and is critical for heavy oil production. At issue, then, is how to obtain the continuing capital essential for domestic development. One source is the capital markets and some of this amount will come from there, but it has significant drawbacks. First, the capital markets have yet to show a strong interest in the oil and gas exploration and production industry despite the recent high prices of both commodities. Second, where the capital markets are likely to focus their attention will be on large companies. So, while some large independents may derive some of their capital from these markets, it will only be a portion and smaller independents will need to look elsewhere. Third, there is no guarantee that such capital will go into domestic production because even with regard to investment in exploration and production activities, capital must compete against other projects including international ones.
The next source of capital will be from the revenues generated by higher production and higher prices. First, the magnitude of this capital may be overstated because just as prices for oil and natural gas have increased, prices for drilling rigs and other costs are also increasing which will squeeze the capital that is available. Second, this capital will also be directed to the most promising projects, so there is no guarantee that it will be invested domestically. Third, this revenue will be significantly reduced by taxes.
The challenge, then, is to create a mechanism to direct the capital to domestic production. One such approach would be to create a "plowback" incentive that would apply to expenditures for domestic oil and natural gas exploration and production. This type of proposal would encourage capital formation and development of domestic wells provided it was immediately beneficial. Therefore, it would have to be creditable against both regular and AMT taxes and any excess available for carryback and carryforward. It would address the compelling need to improve natural gas supply as well as reduce the growing dependency on foreign oil. It must, in fact, apply to both oil and natural gas because they are inherently intertwined - often found together. Moreover, because of their inherent link, a healthy domestic natural gas exploration and production industry cannot exist without a healthy comparable oil industry. IPAA has identified two alternatives to create a plowback incentive.
The first would be a special deduction from gross income from the well. The deduction would be allowed for an amount equivalent to 50% of the costs incurred in the drilling and development of domestic oil and natural gas wells after December 31, 2001. These costs would include all Intangible Drilling Costs, Geological & Geophysical costs, equipment and related costs. In the event of a dry well, the costs would be allowed to offset qualifying gross income from other productive wells with any excess carried forward to offset future qualifying income of the taxpayer. Qualifying income is gross income from an oil or gas well, which was completed or re-completed by incurring additional qualifying costs after December 31, 2001. The deduction would be from gross income and would not reduce the costs or deductions generated by the expenditures themselves. Deductions in excess of gross income from a well could be carried forward or carried back to offset qualifying income from that well. If a well were plugged and abandoned prior to complete utilization of the deduction, the balance would be treated similarly to dry hole costs.
The second approach would be a 10% tax credit, based on the total drilling and development costs for wells drilled after 2001. These costs would include all Intangible Drilling Costs, Geological & Geophysical costs, equipment and related costs. The credit would apply against both the regular tax and the Alternative Minimum Tax. It could be carried back and carried forward. In order to obtain the credit, the taxpayer must be able to demonstrate that he has expended a like amount on similar development activity within 12 months following the end of the tax year to which the credit applies.
Structuring the federal tax code to allow greater revenues to be retained by energy producers who reinvest those revenues into new exploration and production can then enhance domestic investment. (An IPAA Fact Sheet detailing this issue follows this testimony.)
Conclusion
If Congress wants to see more domestic crude oil and natural gas production, it must recognize that federal tax policy plays a critical role in whether capital will flow toward this industry and the production of this resource. That has always been the case and it will continue to be. Domestic producers have always been "risk takers". During these times of plentiful investment opportunities, they need some assistance in attracting capital (or retaining it for use internally) and directing it towards domestic projects. There are immediate actions that can and should be taken. The time is right. The nation is seeking a more stable energy supply. Congress should act.
FACT SHEET
Geological And Geophysical Costs
Geological and geophysical (G&G) surveys are used to locate and identify properties with the potential to produce commercial quantities of oil and natural gas, as well as to determine the optimal location for exploratory and developmental wells.
Proposal
Allow current expensing of geological and geophysical costs incurred domestically including the Outer Continental Shelf.
G&G expenses include the costs incurred for geologists, seismic surveys, and the drilling of core holes. These surveys increasingly use 3-D technology rather than the conventional 2-D technology used for most of the last seven decades. Previously only very large companies were able to utilize this state-of-the-art, computer-intensive, 3-D technology because of its high cost and the considerable technical expertise it requires. However, as the costs of computer technology have declined, more and more domestic independent producers are making use of this technology. Still, while 3-D seismic provides a vastly superior tool for exploration, it is far more expensive than 2-D technology. 3-D seismic surveys usually cost between five or six times more per square mile onshore than the older technology and, in some instances can account for two-thirds of the costs of some wells. Encouraging use of this technology has many benefits:
- More detailed information. Conventional 2-D seismic is only able to identify large structural traps while 3-D seismic is able to pinpoint complex formations and stratigraphic plays.
- Improved finding rates. Producers are reporting 50-85% improvements in their finding rate. In prior years a producer might have to drill three to eight wells in order to find commercially viable production.
- Reduced environmental impact. Because the use of advanced seismic technology significantly improves the odds of drilling a commercially viable well on the first try, this reduces the number of wells that are drilled and, thus, reducing the footprint of the industry on the environment.
- Investment capital. Many investors are requiring producers to provide 3-D seismic surveys of potential development before committing their capital to the project in order to minimize their risk
Current Law Treatment
G&G costs are not deductible as ordinary and necessary business expenses but are treated as capital expenditures recovered through cost depletion over the life of the field. G&G expenditures allocated to abandoned prospects are deducted upon such abandonment.
Reasons For Change
These costs are an important and integral part of exploration and production for oil and natural gas. They affect the ability of domestic producers to engage in the exploration and development of our national petroleum reserves. Thus, they are more in the nature of an ordinary and necessary cost of doing business.
These costs are similar to research and development costs for other industries. For those industries such costs are not only deductible but a tax credit is available.
Crude oil imports are at an all-time high, which makes the U.S. vulnerable to sharp oil price increases or supply disruptions. The National Petroleum Council Natural Gas study concluded that natural gas supplies need to increase by over 30 percent by 2010 to meet demand. Domestic exploration and production must be encouraged now to offset this potential threat to national security, to meet future needs, and to enhance our economy. Allowing the deduction of G&G costs would increase capital available for domestic exploration and production activity.
The technical "infrastructure" of the oil services industry, which includes geologists and engineers, has been moving into other industries due to reduced domestic exploration and production. Stimulating exploration and development activities would help rebuild the critical oil services industry.
Encouraging the industry to use the best technology available and to reduce its environmental footprint are important public policy reasons to clarify that these ordinary and necessary business expenses for the oil and gas industry should be expensed.
Status
The Taxpayer Refund And Relief Act Of 1999 included a provision to allow expensing of G&G costs, but the bill was vetoed. Congress needs to pass legislation now to implement this common objective to enhance and preserve domestic oil and natural gas production.
FACT SHEET
Tax Treatment of Delay Rentals
Delay rental payments are made by producers to an oil and gas lessor prior to drilling or production.
Unlike bonus payments (made by the producer in consideration for the grant of the lease) which generally are treated as an advance royalty and thus capitalized, producers have historically been allowed to elect to deduct delay rental payments under Treasury Regulations 1.612-3(c). However, in September 1997, the IRS issued a coordinated issues paper stating that such payments are preproduction costs subject to capitalization under Section 263A of the Internal Revenue Code. The legislative history of Section 263A is unclear and subject to varying interpretation.
Proposal
Clarify that delay rental payments are deductible, at the election of the taxpayer, as ordinary and necessary business expenses.
Reasons For Change
In passing the Section 263A uniform capitalization rules, Congress broadly intended to only affect the "unwarranted deferral of taxes." Congress did not intend to grant the IRS the authority to repeal the well-settled industry practice of deducting "delay rentals" as ordinary and necessary business expenses.
Treas. Reg.1.612-3(c) states that, "a delay rental is an amount paid for the privilege of deferring development of the property and which could have been avoided by abandonment of the lease, or by commencement of development operations, or by obtaining production." Such payments represent ordinary and necessary business expenses, not an "unwarranted deferral of taxes." Given the clear disagreement over the legislative history and the likelihood of costly and unnecessary litigation to resolve the issue, clarification would eliminate administrative and compliance burdens on taxpayers and the IRS.
Status
The Taxpayer Refund And Relief Act Of 1999 included a provision to clarify that delay rental payments could be expensed, but the bill was vetoed. Congress needs to enact legislation to implement this common position if the Administration is unwilling to correct the current confusing interpretation of the tax code.
March 2001
FACT SHEET
Marginal Well Tax Credit
Summary of Legislation
The Marginal Well Production Tax Credit amendment to the Internal Revenue code will establish a tax credit for existing marginal wells. Marginal oil wells are those with average production of not more than 15 barrels per day, those producing heavy oil, or those wells producing not less than 95 percent water with average production of not more than 25 barrels per day of oil. Marginal gas wells are those producing not more than 90 Mcf a day. The amendment will allow a $3 a barrel tax credit for the first 3 barrels of daily production from an existing marginal oil well and a $0.50 per Mcf tax credit for the first 18 Mcf of daily natural gas production from a marginal well.
The tax credit would be phased in and out in equal increments as prices for oil and natural gas fall and rise. Prices triggering the tax credit are based on the annual average wellhead price for all domestic crude oil and the annual average wellhead price per 1,000 cubic feet for all domestic natural gas. The credit for the current taxable year is based on the average price from the previous year. The phase in/out prices are as follows:
OIL - phase in/out between $15 and $18
GAS - phase in/out between $1.67 and $2.00
The amendment would allow the tax credit to be offset against regular and the alternative minimum tax (AMT). In addition, for producers without taxable income for the current tax year, the amendment would provide a 10-year carryback provision allowing producers to claim the credit on taxes paid in those years. The carryback credit may be used to offset regular tax and AMT.
Reasons For Change
The 1994 National Petroleum Council's Marginal Wells report concluded:
Preserving marginal wells is central to our energy security. Neither government nor the industry can set the global market price of crude oil. Therefore, the nation's internal cost structure must be relied upon for preserving marginal well contributions.
Marginal wells account for approximately 20 percent of domestic oil production, amount roughly equivalent to imports from Saudi Arabia. Producing an average of 2.2 barrels per day, these roughly 400,000 wells are the nation's true strategic petroleum reserve. They are, however, particularly at risk during periods of low prices. Therefore, a principal recommendation of the Marginal Wells report was the creation of a countercyclical marginal well tax credit. The Dept. of Energy has evaluated the benefits of a tax credit and believes that it could prevent the loss of 140,000 barrels per day of production if fully employed during times of low oil prices like those of 1998 and 1999.
As the 107th Congress begins, legislation has been introduced in both the House and Senate to create a tax credit. If enacted now, this countercyclical credit would establish a safety net of support for these critical wells. As Congress addresses energy policy issues, IPAA believes a marginal wells tax credit should be an essential component.
March 2001
FACT SHEET
Eliminate The Net Income Limitation On Percentage Depletion
The net income limitation severely restricts the ability of independent producers to use percentage depletion, particularly with respect to marginal wells. Percentage depletion is already subject to many limitations. First, the percentage depletion allowance may only be taken by independent producers and royalty owners and not by integrated oil companies. Second, depletion may only be claimed up to specific daily production levels of 1,000 barrels of oil or 6,000 Mcf of natural gas. Third, depletion is limited to the net income from the property. Fourth, the deduction is limited to 65% of net taxable income. These limitations apply both for regular and alternative minimum tax purposes.
The net income limitation requires percentage depletion to be calculated on a property?by?property basis. It prohibits percentage depletion to the extent it exceeds the net income from a particular property. The typical independent producer can have numerous oil and gas properties, many of which could be marginal properties with high operating costs and low production yields. During periods of low prices, the producer may not have net income from a particular property, especially from marginal properties. When domestic production is most susceptible to being plugged, the net income limitation discourages producers from investing income to maintain marginal wells.
Proposal
Eliminate the net income limitation on percentage depletion.
Reasons for change
Marginal oil wells - those producing on average 15 barrels per day or less or producing heavy oil - account for approximately 20 percent of domestic oil production, an amount roughly equivalent to imports from Saudi Arabia. The U.S. is the only country with significant production from marginal wells. Once wells are plugged, access to the remaining resource is often lost forever. Eliminating the net income limitation on percentage depletion would encourage producers to keep marginally economic wells in production and enhance optimum oil and natural gas resource recovery.
The current requirement creates a paperwork and compliance nightmare for taxpayers and the Internal Revenue Service. Eliminating the net income limitation on percentage depletion would simplify recordkeeping and reduce the administrative and compliance burden for taxpayers and the IRS.
Current Status
The Taxpayer Relief Act of 1997 created a two-year suspension of the net income limitation on percentage depletion; this suspension has been extended through 2001. However, it is time to make this suspension permanent. If the country learned anything from the high oil and natural gas prices of 2000, it is that America needs to maintain and enhance its domestic oil and natural gas production. This tax reform allows more capital to be retained by producers where it can do the most good - producing more domestic oil and natural gas.
Legislation has been introduced to eliminate or further suspend the net income limitation provision for marginal wells. It should be enacted prior to 2002 when the current suspension ends
March 2001
FACT SHEET
Percentage Depletion Expansion and Carryback Proposal
Current tax law limits the use of percentage depletion of oil and gas in several ways. First, the percentage depletion allowance may only be taken by independent producers and royalty owners and not by integrated oil companies. Second, depletion may only be claimed up to specific daily production levels of 1,000 barrels of oil or 6,000 Mcf of natural gas. Third, the net income limitation requires percentage depletion to be calculated on a property?by?property basis. It prohibits percentage depletion to the extent it exceeds the net income from a particular property. Fourth, the deduction is limited to 65% of net taxable income. These limitations apply both for regular and alternative minimum tax purposes.
Percentage depletion in excess of the 65 percent limit may be carried over to future years until it is fully utilized. Many independent producers have been limited in the past because they have spent their income on continuing development of their properties, thereby reducing their taxable income. When oil prices dropped to historically low levels independent producers were unreasonably constrained by these tax provisions limiting their cash flow. They cannot use these carried over deductions. Now, when capital to develop oil and natural gas should be maximized, producers can be constrained due to the alternative minimum tax (AMT). Even if they could use the deductions, they may not benefit to the fullest extent possible from actual tax savings. This proposal would alleviate these limits by implementing the following changes:
- By annual election, the 65 percent taxable income limitation would be reduced or eliminated for current and future tax years.
- Carried over percentage depletion could be carried back for ten years subject to the same annual election on taxable income limitation.
Status
Legislation has been introduced in the 107th Congress to eliminate or suspend the 65 percent net taxable income limit and to provide for carryback of carried over deductions.
Congress needs to include such provisions in future tax reform bills and the Administration needs to support such provisions to enhance and preserve domestic oil and natural gas production.
March 2001
FACT SHEET
Enhanced Oil Recovery
Section 43 of the Internal Revenue Code provides an enhanced oil recovery (EOR) credit equal to 15 percent of the qualified enhanced oil recovery costs incurred in a tax year. Existing Treasury guidelines for the section 43 tax credit are very narrow, generally including only expensive EOR processes -- many of which are no longer in use. It excludes, however, many EOR processes that are the result of technological advances now considered common in the industry.
The Petroleum Technology Transfer Council (PTTC) in March 1997 compiled a list of EOR methods that should be included under section 43. This study was part of an industry effort to expand the EOR definition to include technologies that have proven potential for mitigating well abandonment and increasing oil production and resource recovery.
Proposal
Have the IRS review and expand the definition of methods qualifying for the EOR tax credit.
Reason for Change
The existing Treasury guidelines are based on 1979-vintage technology. This list has not kept pace with technology. A second rationale is the incentive generated by allowing domestic producers to position themselves to glean existing reservoirs in order to maximize production of existing reserves.
Two additional categories to the EOR list are proposed. Those categories include Enhanced Gravity Drainage (EGD) and Marginally Economic Reservoir Repressurization (MERR). Included under EGD would be horizontal drilling, multilateral well bores and large diameter lateral well bores. Included in MERR would be natural gas injection and waterflooding. Certain qualifiers and limiting factors include economic criteria for approved projects and incremental production limitations on each project.
By redefining the definition of EOR projects to include both EGD and MERR technologies, the EOR tax credit will encourage conservation measures to expand recovery of existing crude oil reservoirs and promote new drilling activity.
The benefit of these changes is well stated in the National Energy Policy report:
Anywhere from 30 to 70 percent of oil, and 10 to 20 percent of natural gas, is not recovered in field development. It is estimated that enhanced oil recovery projects, including development of new recovery techniques, could add about 60 billion barrels of oil nationwide through increased use of existing fields.
Congress needs to enact legislation to implement these definitional changes if the Administration is unwilling to correct the current constrained interpretation of the tax code.
June 2001
FACT SHEET
Plowback Incentive
Fundamentally, the question facing the nation is how to marshal the capital to develop its domestic resources. The 1999 NPC Natural Gas study estimates that an additional $10 billion over and above the current expenditure level will need to be invested annually in domestic production over the next fifteen years to meet the expected demand. To date this target has not been met; capital expenditures are essentially flat. At issue is how to obtain capital for domestic development. Independent producers are risk takers who will invest capital if it is available to find and produce more oil and natural gas. To encourage additional investment a method needs to be created to "plow back" as much of the revenue from oil and natural gas sales as possible to develop new production. Structuring the federal tax code to allow greater revenues to be retained by energy producers who reinvest those revenues into new exploration and production can enhance domestic investment.
Proposal Alternatives
- A special deduction from gross income from the well would be allowed for an amount equivalent to 50% of the costs incurred in the drilling and development of domestic oil and natural gas wells after December 31, 2001. These costs would include all Intangible Drilling Costs, Geological & Geophysical costs, equipment and related costs. In the event of a dry well, the costs would be allowed to offset qualifying gross income from other productive wells with any excess carried forward to offset future qualifying income of the taxpayer. Qualifying income is gross income from an oil or gas well which was completed or re-completed by incurring additional qualifying costs after December 31, 2001. The deduction is from gross income and would not reduce the costs or deductions generated by the expenditures themselves. Deductions in excess of gross income from a well could be carried forward or carried back to offset qualifying income from that well. If a well were plugged and abandoned prior to complete utilization of the deduction, the balance would be treated similarly to dry hole costs.
- A 10% tax credit, based on the total drilling and development costs for wells drilled after 2001. These costs would include all Intangible Drilling Costs, Geological & Geophysical costs, equipment and related costs. The credit would apply against both the regular tax and the Alternative Minimum Tax. It could be carried back and carried forward. In order to obtain the credit, the taxpayer must be able to demonstrate that he has expended a like amount on similar development activity within 12 months following the end of the tax year to which the credit applies.
Reason for Change
The challenge is to create a mechanism to direct the capital to domestic production. One such approach would be to create a "plowback" incentive that would apply to expenditures for domestic oil and natural gas exploration and production. This type of proposal would encourage capital formation and development of domestic wells provided it was immediately beneficial. It would address the compelling need to improve natural gas supply as well as reduce the growing dependency on foreign oil. It must, in fact, apply to both oil and natural gas because they are inherently intertwined - often found together. Moreover, because of their inherent link, a healthy domestic natural gas exploration and production industry cannot exist without a healthy comparable oil industry.
May 2001
