Tax Legislation and Energy Tax policy Testimony

Senator Baucus, thank you for the opportunity to be here.

My name is Gina Sewell, I am the Tax Manager for Devon Energy Corporation and I am here to testify today as the chairman of the Domestic Petroleum Council's Tax Committee.

Members of the Domestic Petroleum Council who are active in Montana along with Devon Energy Corporation include Ocean Energy, Burlington Resources, Samedan Oil Corporation and Cabot Oil and Gas.

Devon has significant acreage positions in Blaine and Hill counties in north central Montana, in the Powder River Basin of south central Montana, and in the Williston Basin in eastern Montana.

Montana has historically produced more oil than gas. However, the industry also recognizes the potential of coal seam gas reserves in the Powder River Basin. There is also significant shallow gas potential in north central Montana and exploratory potential in the Big Horn and Crazy Mountain Basins in southwestern Montana.

Montana is a key player in the future of gas transmission from the northern Rocky Mountains to the northwestern and eastern United States. There is also considerable development potential along these transmission routes. Devon, as well as many other energy companies, is very interested in this potential and is actively increasing its presence in Montana.

And, now, to share some background thoughts on natural gas before moving to tax issues that are directly related to the production of natural gas and oil.

We know that natural gas is a premium fuel. It is clean, reliable and abundant. We cook with it. We use it to heat and cool our homes and businesses. And it is a strong underpinning of our economy, as an industrial feedstock and as the fuel of choice for generating new electricity to power the computers and the other elements of "the new economy".

In fact, the recent National Petroleum Council natural gas study projects that demand for natural gas will grow by more than one-third over the next decade. Nearly half of that demand growth will come from new electricity generation capacity--more than 90% of which will be gas-fired. This same study estimates that capital expenditures of over $600 billion will be needed between now and 2015 to meet the nation's growing demand for natural gas.

A portion of that demand growth will also undoubtedly result from increased transportation fuel use--whether as compressed gas or liquefied natural gas. For the longer term, fuel cells that generate electricity from natural gas by chemical reaction as opposed to combustion will play increasingly important roles in a variety of applications--including transportation.

This country's independent companies produce approximately 75% of the nation's natural gas. The 22 large independent exploration and production (E&P) company members of the Domestic Petroleum Council (or DPC) produce nearly one-quarter of the natural gas in this country.

Our industry produces natural gas and oil from many types of geologic formations. Whether onshore or offshore, it takes expensive high technology like 3-D seismic, petrophysical logging to indicate the existence of hydrocarbons and hydraulic fracturing to produce natural gas and oil. All of these require enormous amounts of upfront capital (as mentioned above). And this capital outlay is required before a company even knows if it has a commercially viable well.

These are the things we do everyday. And we know we'll need to even further enhance our technology and its application in the future to meet our growing natural gas and oil demand.

The DPC companies drill 35% of all oil and gas wells in the United States and nearly 60% of all such wells drilled by independents. We are committed to continue to take on the challenges of providing gas and oil to consumers in the future.

But we do have challenges. Not the least of which relate to the Tax Code.

The DPC and other industry trade associations agreed last year that the key tax incentives for our industry were the following:

• allowing geological and geophysical (a.k.a. G&G) costs and delay rental payments to be deducted when incurred;
• alternative minimum tax reform;
• change natural gas gathering lines to seven-year property;
• a marginal well tax credit; and,
• for small operators, certain percentage depletion enhancements.

While DPC continues to support all of these measures, the items of greatest importance to our members at this time are the allowance of deductions for G&G and delay rental costs. With the time remaining in this Congress, it would be a shame to miss the opportunity to seize a win-win opportunity by providing normal business tax treatment for G&G and delay rental expenses as is supported by the Administration as well as many Members of Congress, both Republicans and Democrats.

What are these expenses?

G&G costs are the costs incurred to gather and process seismic and other data in an effort to locate oil and natural gas deposits underground. The costs are routinely and continuously incurred as part of an active ongoing exploration program and are among the first costs incurred in the exploration effort. Because of the depleting nature of its resource base, an E&P company must acquire new reserves to stay in business.

The deductibility of G&G will be important as companies such as Devon take the first steps in analyzing new exploration areas, including those in Montana. To state the case for G&G deductibility yet another way: G&G is the research and development expenses of the energy industry. The majority of G&G costs incurred end up condemning properties as having no potential and thus, they are completely sunk costs, yet taxpayers are not allowed a deduction for this. The minority of costs result in arriving at viable candidates for further evaluation by drilling.

Under current tax law, G&G costs are "suspended", meaning no deduction or amortization is allowed for tax purposes, while decisions are made as to whether the data is promising enough to warrant drilling a test well and if no leases have yet been obtained in the area, the feasibility of obtaining leasehold rights that will allow the well to be drilled.
If a test well is drilled and is successful, the G&G costs remain suspended with no recovery allowed for tax purposes until the lease begins production of the oil or gas. In many areas where exploration is now occurring, such as the deepwater GOM, the period of time from drilling a test well until commencement of production is often five years or more.
Furthermore, if a company incurs $10 million on a 3-D seismic study over a 1000 acre area and, based on an analysis of the study, only obtains a lease over a 250 acre area, the current rules require the total $10 million dollar cost to be assigned to the 250 acre lease. This allocation causes G&G to skew the property's economics.

An E&P company, like any business, must generate a reasonable after tax rate of return on its capital to ensure that it will have access to new capital. Since G&G costs are incurred early in an exploration effort and a recovery on that G&G investment is often delayed for many years, it is very challenging for companies to generate acceptable after tax rates of return on their exploration capital.
In addition, given the complexities of the current tax rules, a large amount of taxpayer administrative time and effort is expended to track and properly account for G&G costs. Further, the IRS and the taxpayer spend significant administrative time and effort auditing these costs. In joint IRS and industry meetings, the IRS has acknowledged the need for change in this area.

Delay rentals are payments that are generally required to be made on an annual basis by the lessee to the lessor for the right to hold the lease throughout its primary term. As the name implies, they are in the nature of rent. They are paid, say annually, to extend the lease an additional year. If a lessee begins operations on the lease, typically by drilling a well, then the obligation to pay delay rentals ends as long as the operations on the lease continue. To put this in perspective, Devon has some 50,000 active leases and pays delay rentals on about 6,000 of them each year.

Prior to 1986, E&P companies were unquestionably entitled to deduct delay rentals for tax purposes. When the uniform capitalization rules were added to the tax Code (section 263A) that year, the treatment of delay rentals became less clear. During IRS audits the examining agents did not always take consistent positions but in many cases determined that delay rentals should be capitalized under the uniform capitalization rules. The taxpayers in the industry believe that delay rentals continue to be deductible since they are costs that are paid to postpone improvement of the property - not to improve it. Adding to the confusion, a long-standing regulation (since 1933), which the IRS in year 2000 proposed to change, still provides that delay rental payments are deductible at the taxpayer's election.

Like G&G costs, delay rentals are an ongoing expense incurred by the industry very early in the process of exploration and production.

The members of the Domestic Petroleum Council believe that allowing G&G costs and delay rentals to be deducted for tax purposes when incurred will encourage domestic exploration and production efforts and over time help to reduce America's dependence on foreign energy resources. The previous Administration in March of 2000 proposed allowing these costs to be deducted for tax purposes.

While the DPC supports all of the industry recommendations mentioned earlier, the tax treatment of G&G and delay rental payments are the highest priority tax items for our members this year. If tax legislation is able to move forward this session, we urge you to include these changes in that bill.

I have a summary and examples of the legislative language that has been proposed in various bills that I will be glad to provide to the Subcommittee.

And I would be pleased to answer any questions.

Thank you.

Contact: Gina Sewell, Devon Energy, 405 552 4749