California Independent Petroleum Association
Sacramento, California 95814
March 16, 2001

Mr. Chairman and Members of the Subcommittee:

For the record my name is David S. Hall, I am the Chairman of the Economic Policy and Taxation Committee for the California Independent Petroleum Association. I thank you for the opportunity to address this Committee on behalf of our association.

Who is CIPA

California Independent Petroleum Association, also known as "CIPA," is a non-profit, non-partisan trade association representing approximately 450 independent producers, royalty owners, service and supply companies operating in California. We are the little guys, the "energy farmers" of America, who are independent, non-integrated companies that receives nearly all of our revenues from oil and gas production at the wellhead. We are exclusively in the exploration and production segment of the industry with no retail outlets, marketing or refining operations. As independents, we are "price-takers", with little or no control over the price we receive for our product at the wellhead. In most cases, we operate the smaller oil fields the majors oil companies have abandoned for higher rates of return, or passed over because it did not meet there investment criteria. In either case, the independent oil producers play an important role in developing our existing oil field reserves and reducing our dependence on foreign oil imports.

California Industry Highlights

California produced approximately 841,000 barrels of oil per day in 2000 or approximately 14.4% of the total U.S. production. Twenty-nine California counties produce some oil or gas. More oil is produced in Kern County (560,000+ bpd) than in all of Oklahoma, the fifth largest producing state. Annual state and local revenues from petroleum production in California total over $500 million. Direct and indirect employment in the petroleum exploration and production industry in California totals approximately 70,000. California's petroleum reserves are predominantly "heavy oil" (See Chart A), which requires a large, long-term capital investment to produce. California has approximately 45,000 producing oil and natural gas wells. California produces approximately 16% of its daily natural gas needs and approximately 40% of its daily oil needs. The upstream petroleum industry is highly regulated with some 28 federal, state, regional and local agencies with review and oversight responsibilities. Thirty-five major federal and state regulatory statutes, and many more local and regional ordinances and rules, govern industry activities in California.

In keeping with the focus of this Subcommittee, CIPA has attempted to address the concerns of this committee by addressing adequacy of current tax incentives for production and conservation.

Enhanced Oil Recovery Credit (EOR)

As previously stated, over two-thirds of California's oil production is from marginal heavy oil ⁽¹⁾. For example most of Kern County's oil is 13 gravity oil, which in layman's terms is thicker than molasses. This is the most marginal oil production in the United States. Because of viscosity of the oil it requires much more effort and costs to remove the oil from the ground. To remove the oil from the sands of the reservoir requires steam to heat the oil so that it will flow to the well head. Chart B shows that approximately 64% of heavy oil is thermally treated. There are two methods commonly used to produce the necessary steam. First method is a conventional steam generator, which is the most costly. The second method is a co-generation facility, which produces both steam and electricity as a by-product. Selling the electricity offsets the costs of producing the steam. Either method used to produce the steam requires considerable capital investments. After the oil is produced, the steam (in the form of water) must be separated from the oil. This also requires considerable capital investment to separate, recycle the water back into steam, and to dispose of the excess water. For every barrel of marginal heavy oil removed we also remove between three to one hundred barrels of water as well.

Marginal heavy oil is used primarily in the production of gasoline. California refineries are complex and have been configured to handle our heavy oil. Because gasoline is the most sought after product, the California refinery must perform a secondary step on heavy crude oil in order to extract the most from a barrel of crude oil. The value of our marginal heavy oil becomes worth less than lighter oil to the refineries because of the extra steps involved. This is proven in our Chart C which reflects the price differential between WTI-Nymex and California Heavy 13 (crude oil). The average "Basis Differential" between the two types of crude oil has been between $5.00 and $7.50.

Since the passage of EOR Credit in 1990, approximately 16,500 ⁽²⁾ new wells have been drilled. CIPA is aware that most producers calculate their return on investment including the benefits of the EOR Credit. The EOR Credit has become an important part of the production of marginal heavy oil.

In summary, EOR Credit has served to help independent producers producing marginal heavy oil, which requires large capital investments in steam costs, drilling, and facilities infrastructures. CIPA believes that EOR Credit should be offset against Alternative Minimum Tax (AMT) in the same manner as Foreign Tax Credit is. Without the EOR Credit some of California's marginal heavy oil would be uneconomically. CIPA further believes that EOR Credit could improved by including produced water disposal costs, recycling water costs, and environmental costs. Without the EOR Credit, CIPA strongly believes that California marginal heavy oil production would decline dramatically causing tankering of foreign crude oil to California and CIPA believes that gasoline prices would increase. In addition, electrical generation of oil field related co-generation may become uneconomical.

Other current tax incentives currently allowed by the Internal Revenue Code (IRC), which are critical to independent producers, are percentage depletion on their marginal oil production, intangible drilling costs, steam costs under IRC §193, capital recovery through depreciation. CIPA believes that these tax incentives are adequate in most cases but should be improved to help continue the development of our domestic marginal oil and gas production and thereby holding down our costs. Listed below are CIPA's suggestions for improving current tax incentives.

Percentage Depletion

Congress has provided for the temporary repeal of 65% percent net income limit for percentage depletion of oil and gas wells operated by independent producers. CIPA believes that the temporary repeal should be made permanent. In addition CIPA believes the repeal of the current 50% net income limit on percentage depletion of oil and gas wells should also be made. We believe that these limitations provide an accounting handicap to the independent producers and create an accounting nightmare tracking the small marginal oil fields. We also believe that the amounts of tax dollars involved are minimal. For these reasons CIPA support the repeal of the net income limitations on percentage depletion for independent producers.

Independent oil and gas producers are allowed a percentage depletion deduction based upon 1,000 ⁽³⁾ barrels per day or gas equivalent. Since the introduction of this limitation in 1975, the number of independent producers has greatly diminished due to consolidations and efficiencies of the market. CIPA believes that the removal of the artificial, extremely low, and ineffective barrel limitation would spur development of our domestic reserves. We further believe that this could be supported by statistic if an economic study were done. At minimum we believe that the limitation should be increased to 25,000 barrels per day. CIPA supports the repeal of tentative quantity limitation under §613A.

While the focus of this hearing is three fold: (1) the adequacy of current tax incentives for production and conservation, (2) the causes of current shortages and high prices, and (3) impact of shortages and high prices on individual consumers and business, CIPA believes that there are obstacles in the Internal Revenue Code (IRC) which could be eliminated, removed or reduced to help the development of our natural resources. Listed below are some of the major obstacles facing our industry and CIPA's suggestions for removing those obstacles. In all cases, AMT is the biggest obstacle an independent producer has in converting his tax incentives into cash. Without cash, the independent producers are unable to explore new fields, exploit and develop existing fields, and maximize existing production for domestic use.

Alternative Minimum Tax (AMT)

Probably the biggest obstacle outside of depressed oil prices to prevent producers from spending more on a drilling program (capital budget) is the alternative minimum tax. This section of the Internal Revenue Code prevents producers from converting their tax benefits into cash and thereby prevents producers from spending more on drilling and developing of America's oil and gas reserves. Consideration should be given to eliminating the tax preference items in the AMT calculation for producers. This would provide the small energy farmers the necessary capital to continue drilling and developing our oil and gas reserves. CIPA supports the removal of the alternative minimum tax on producers.

Capital Recovery

Our industry is a very capital-intensive industry, which requires large cash investments before any oil or gas wells are drilled. Once a discovery is found additional cash is required to develop. Should the well be economical to produce, more cash is needed to develop the infrastructure to bring the oil and gas to the market. Sometimes this cycle will take years to complete the first well and produce a product for the consumer. CIPA believes that our current capital recovery methods coupled with AMT are obstacles to the further development of our industry. Reducing these obstacles through shorter depreciable lives would spur new investors into the industry, which will ultimately benefit the consumer through increased production of oil and gas.

Geological and Geophysical Expenditures

These costs were deductible until 1943 when the IRS ruled that the costs should be capital. Today geological and geophysical (G&G) expenditures are not deductible as ordinary and necessary business expenses but are capital expenditures recovered through cost depletion over the life of the field unless the prospects are abandoned then the costs are deductible. These costs are an important and integral part of exploration and production for oil and natural gas and have become a necessary cost of doing business. As our domestic reserves are developed G&G studies become more important in finding new "stranded" or by-passed domestic oil and gas reserves. G&G expenditures include the costs incurred for geologists, seismic surveys, and the drilling of core samples. These surveys increasingly use 4-D (time) and 3-D technology rather the older conventional 2-D technology. Because technological advances have been made the cost of 4-D, and 3-D have dropped to a level where independent oil or gas producers can now afford to use this technology to develop more reserves. CIPA supports G&G expenditures as ordinary and necessary business expenses.

Mr. Chairman and members of the Subcommittee this concludes my remarks. I thank you for allowing me to submit my written testimony to this Subcommittee.

David S. Hal
Chairman, Economic Policy and Taxation Committee

[Attachments are being retained in the Committee files.]

1. IRC §613A(c)(6)(F) HEAVY OIL.--For purposes of this paragraph, the term "heavy oil" means domestic crude oil produced from any property if such crude oil had a weighted average gravity of 20 degrees API or less (corrected to 60 degrees Fahrenheit).

2. From Statistics gathered from the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources and IPAA's 1998-1999 Oil & Gas Producing Industry In Your State, Hart Publication.

3. IRC §613A(c)(3)(B).