Analysis: Although they'd prefer none at all, producers in states like Texas are thankful for any permanent or temporary reduction they can get in state severance taxes. And with maturation of their U.S. oil and gas properties during the past 20 years, they've managed to get some reductions, but mostly to promote increased production from existing fields.
However, certain regulators in producing states, particularly Texas, have determined that in order to promote new oil and gas reserve additions—the name of the game, ultimately, in exploration and production (E&P)—producers would benefit from a severance tax reduction incentive that covers new exploratory discoveries, which include rank wildcat wells and deeper new pays in existing fields.
Severance taxes were created to compensate states for private use of—and profit from—nonrenewable natural resources removed (severed) from beneath state territory. In Texas, the oil severance tax was created in 1905, and the current rate is 4.6 percent of the market value of the oil. The tax for natural gas was created in 1951 at a rate of 7.5 percent. Condensate brings 4.6 percent.
Operators in Texas are no doubt encouraged that Michael L. Williams, chairman of the Texas Railroad Commission (RRC) is building support for a new investment tax credit—the first of its kind in Texas—to encourage exploratory drilling. In Williams's mind, besides adding to the state's dwindling reserve base, such a credit against future severance tax liability would result in earlier revenue for producers that eventually would generate additional severance tax income. Also, more bucks would accrue to local and community governments via increased sales and ad valorem taxes. Williams, currently running for re-election (although that has no relevance here), introduced the tax credit proposal last month in Austin, and RRC officials said a bill probably would be introduced early in the next legislative session, which begins in January. Such a bill, they said, should meet relatively little opposition and could draw quick action from lawmakers.
Commission records indicate that in 2001, Texas operators drilled some 12,000 wells. Of those, only 500 were deemed exploratory—an unimpressive ratio in anyone's view. Under Williams's proposal, operators who drill exploratory wells in Texas would earn the tax credit if the number of such wells exceeded the statewide average by only 5 percent. In 2001, that would have been only 25 more wells.
Under the proposal, the amount of tax credit available would depend on well depth, with deeper, more expensive wells receiving a greater credit. The depth of the average Texas exploratory well in 2001 was about 8,000 feet, says the RRC. Had it been available, an operator would have earned a tax credit of about $74,000. That would have offset about 10 percent of the cost to drill the well.
The proposed tax credit formula is: Credit = (depth in feet squared) divided by 1,000 + $10,000. Under it, the following are average tax credits that would be possible for three general types of exploratory wells:
· Shallow well—3,500 feet: (3,500 x 3,500)/1,000 + 10,000 = $22,250. · Medium well—8,000 feet: (8,000 x 8,000)/1,000 + 10,000 = $74,000. · Deep well—11,500 feet: (1,500 x 11,500)/1,000 + 10,000 = $142,250. There are other aspects to the boilerplate, of course. For instance to qualify, the bottomhole location for the new well must be at least two and one-half miles from the nearest bottomhole location of a producing (or previously produced) well; or, the well must be drilled to a point at least 1,000 feet deeper than the deepest producing (or previously produced) well inside the two and one-half-mile radius.
Bryndan Wright, RRC policy director, mentioned that if such a deeper well were a dry hole and the operator tapped an established pay zone uphole, he could not earn the credit. Interestingly enough, however, the new well does not have to be a producer to qualify, so a dry hole would count, as long as it meets the other criteria.
The state economic impact could be considerable, Wright pointed out. For producers, it would mean the 10 percent per-well drilling cost reduction equivalent, and producers everywhere are always looking for ways to lower drilling costs. But there's more:
1. A 10 percent increase in exploratory well activity would result in some $160 million in new income to producers, and generate an estimated $13 million in new severance tax revenue.
2. For a 25 percent increase in exploratory wells, about $400 million in new income and about $34 million in new severance taxes.
3. For a 40 percent increase, about $640 million in new revenue and some $54 million in severance taxes.
For most industries, groups that keep watch on federal government largesse—even the environmental lobby—openly approve of incentives in the form of investment tax credits. But when it comes to the petroleum industry, such incentives are all too often fast-tracked to the "corporate welfare" file and marked for quick opposition.
Much of such criticism has been influenced by hidden motives. One need only recall that in 1975, the U.S. Congress deprived integrated oil companies of the 27.5 percent income tax depletion allowance on oil and gas sales value—a benefit they'd had since 1926. To the companies, it was their own "severance" allowance, as it were, and helped repay them for their hard work and pre-drilling exploration and development costs. In any case, the announced reason for the rule change was the companies' obligation to pay their "fair share" of taxes. However, there was an obvious resentment in Congress and elsewhere about healthy industry profits in the 1960s and early 1970s. In fact, to this day, petroleum industry veterans call the Tax Reduction Act of 1975, which cancelled the allowance, a "gotcha" fueled partially by class envy.
To their credit, lawmakers left independent operators with a 15 percent deduction of gross production value, but on a maximum of only 1,000 barrels per day. Certain other industry sectors also kept some reduced write-offs. But even today, federal legislators' mistrust of the industry is intense. President Bush's new Energy Plan currently is being held up in Congress due partly to suspicion by liberal congressmen that oil company influence may have fostered inclusion of some incentives they would refuse to call anything but tax "loopholes."
Such an air of doubt, however, is far less dominant in the halls of state government. Most oil and gas producing states recognize that E&P is an important "goose" whose ability to lay golden eggs—in the form of capital investment and, hence, tax revenue—should not be stifled unduly. They've heard that giant "sucking" sound of major company exploration dollars going overseas, and they don't like it.
In fact, state government E&P incentives are alive and well, and producers are fortunate enough to be able to "shop" for them from a detailed menu.
Since the mid-1990s, the Interstate Oil & Gas Compact Commission (IOGCC), a 67-year-old outfit that represents the governors of the 30 states that produce virtually all domestic production, has published a report listing the various incentives offered by state governments to encourage E&P growth. The report, "Investments in Energy Security: State Incentives to Maximize Oil and Gas Recovery," is updated each year and lists the incentives offered, as well as in-depth analysis of what each was meant to accomplish.
The Oklahoma City-based IOGCC says such incentives demonstrate the importance of flexibility and a business-friendly attitude. These, combined with an intimate understanding of the industry, of citizens' needs, and of the state's economic goals, have allowed them to develop effective programs.
The report includes any U.S. state, federal, or Canadian provincial program that helps producers achieve efficient petroleum resource recovery while protecting health, safety, and the environment. These range from tax relief for low-volume, economically marginal wells, or idle wells brought back into production, to incentives for development and use of existing or new technologies to increase production efficiencies. Over the years, many such incentives have proven effective, while others have been disappointing, IOGCC points out. The report lists them all, as well as reasons why the disappointing ones didn't work.
An important point, says the IOGCC, is that even when a particular incentive program is not used extensively by industry or judged successful based on economic rewards to government, "…its adoption can strengthen the interests of oil and natural gas producers considering expanding in that state. The attitude displayed by the state in adopting incentives is one of welcome, and business people prefer to operate where they are welcome. "
It would appear that commissioner Williams's proposed tax credit for Texas exploration drilling takes that welcome attitude. It comes in combination with whatever incentives manage to remain in the President's plan after Congress gets through with it—and not a minute too soon. Other states likely would adopt a similar incentive in the near future. Meanwhile, the IOGCC's 2002 incentives update is in final preparation, and should be made available soon. Though cost has not yet been announced, the 241-page 1999 edition, along with its 2001 supplement of 67 pages, is being offered as a package for $45, with the supplement available separately for $10. For more information, contact IOGCC headquarters at (405) 525-3556 or visit www.iogcc.state.ok.us.
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