Patrick Crow
Washington Editor
A.D. Koen
Gulf Coast News Editor
U.S. federal tax credit for drilling wells in tight gas sands formations has contributed significantly to U.S. exploration and development activity.
The credit, due to expire for new wells at yearend, has been a key factor in the rebounding U.S. active rig count in second half 1992. Drilling in tight gas sands currently accounts for as much as one third of the active U.S. rig count.
By mid-October, the number of rigs drilling for gas accounted for at least 80% of the increase since July in Smith International Inc.'s count of working rotary rigs in the U.S. (see chart, p. 24).
Of those gas rigs, about 60% were drilling wells targeting coal seams or tight gas sand formations as defined by the Natural Gas Policy Act of 1978 Section 107(e), where operators seek to qualify wells for the Section 29 credit. At least nine of every 10 Section 29 rigs working in the second half targeted tight gas sands.
Many analysts attributed the spurt in drilling activity in the U.S. since July 31 to rising natural gas prices caused by weather related shut-ins in the Gulf of Mexico, supply concerns over producing states' gas proration measures, and thinning storage levels.
U.S. spot gas prices since February have more than doubled to more than $2/Mcf, rising steadily through the year before posting their biggest jump in mid-September. Drilling related to conventional gas objectives was down in early September from end of July levels. It then staged a rally still under way last month. Drilling for tight sands gas in the U.S. has soared by almost 70% since the end of July Smith's tally shows.
1993 OUTLOOK
Companies active in designated tight gas sand formations report plans to cur tail drilling in tight sand areas after the credit expire at yearend. Operator opinion is mixed about whether higher gas prices will lessen the expected first quarter 1993 drilling slump.
However, operators ar certain the Section 29 credit functioned as intended in tight gas sand areas. Because of the credit, many companies say they were able to drill tight formation gas wells too risky to try otherwise because of low wellhead prices and constrained drilling budgets.
Even when U.S. gas price began to rise, tight gas economics without the credit still could not compete with conventional prospects to drilling funds.
Section 29 critics have claimed that selling incremental tight gas volumes into oversupplied U.S. gas markets depressed prices. But companies drilling wells to qualify for the credit said not enough tight sands gas is being produced to affect markets very much. Rather, U.S. gas prices are driven more by fundamentals of regional gas markets, they claim.
Congress as early as next year could revisit the question of whether to allow a federal tax credit for gas produced from tight sand formations.
House-Senate conferees in the past congressional session declined to renew beyond yearend 1992 Section 29 tax credits for nonconventional gas production after deciding there was not enough revenue to fund the credit and grant independent producers relief from the alternative minimum tax at the same time.
Although industry is split on the effects of the credit-some producers lobbied against extending it-the measure has widespread support in Congress, especially in the Senate.
TAX CREDIT ENDING
The Senate finance committee declined to renew the credit, but the full Senate approved an amendment on the floor, 57-41, that placed an 8 month extension back in the omnibus U.S. tax bill. The amendment would have limited the credit available for high volume wells.
But a House-Senate conference committee then struck the provision when it merged the bills from both houses. Extending the credit would have cost the U.S. Treasury about $180 million/year.
Although the credit was not extended, it will continue in force for a decade. Wells completed this year will be eligible to receive the subsidy until 2002.
The Section 29 credit was enacted as part of the 1980 U.S. "windfall profits" tax on crude oil and retained when the rest of that tax was repealed in the late 1980s.
The amount of the credit is equal to $3/barrel of oil equivalent, adjusted for inflation. The current credit is 920/Mcf for coalbed methane and 52/Mcf for tight formation gas.
With the subsidy in place, the Department of Energy says coalbed methane's share of U.S. gas supplies rose by nearly 29% and tight sands gas by 19%, compared with only a 4% increase for conventional gas.
SENATE DEBATE
Many of the benefits cited by companies seeking Section 29 credits were listed when the Senate debated the issue in late September.
Sen. Robert Dole (R-Kan.) championed an extension, arguing on the floor of the Senate that gas from nonconventional sources "will be absolutely essential to meet our near term future needs."
Sen. Lloyd Bentsen (D-Tex.) agreed, saying, "We have used it for some 12 years now and it has dramatically increased our resource base of nonconventional fuels-for example, gas from tight sands, coal seams, Devonian shale, coal, and biomass."
Bentsen said the credit also has led to significant development of nonconventional fuel technologies, a trend Congress wants to continue.
Sen. Richard Shelby (D-Ala.) said the tax credit "benefits virtually all of the 50 states, whether or not there is an nonconventional fuel industry in that state."
He said additional gas supplies resulting from the credit may have helped restrain U.S. gas prices by $3-4 billion the past decade.
Sen. Bill Bradley (D-N.J.) led the fight against extending the credit.
"Ten years ought to be enough public subsidy to go after this gas that was trapped in difficult areas to reach," Bradley said. "But once you get hooked on a subsidy, you like getting more and more.
"If you are a normal gas producer, you take your risk, hit the gas, and sell it for $1.50," he said. "If, on the other hand, you are a producer of tight sands or geopressurized brine or whatever, the government gives you $1/Mcf even before you sell the gas. This is a huge distortion on the energy market.
"Since the mid-1980s, large numbers of domestic gas wells have been shut in or produced at partial capacity," he said. "Each Section 29 well that has been brought on line has worsened that situation."
Bradley said only five states are the main beneficiaries of the credit: New Mexico, Colorado, Wyoming, Alabama, and West Virginia.
"They will get the bulk of the $900 million the next 5 years that this will cost us. And the cost of what we have already done (with the credit) is going to be about $6 billion," he said.
Sen. Don Nickles (R-Okla.) said, "In January and February of this year, we were selling gas in Oklahoma for $1/Mcf. So a 92 tax credit was almost twice the value, or 92% of the value of gas, an enormous tax credit."
TIGHT SANDS ACTIVITY
The effect the Section 29 tax credit has had on U.S. drilling and production activity is undeniable.
Several companies have kicked off large drilling programs to qualify as many tight gas sand wells as possible for the credit. The effect of accelerated tight sand drilling is beginning to be reflected in some companies' production profiles.
U.S. drilling activity has been increasing steadily since the week ended June 12, when Baker Hughes Inc.'s weekly rig count dropped below 600 units for the first time since the company began keeping records (OGJ, June 22, p. 91).
The Baker Hughes count rebounded to 690 rigs by the end of July, more than 75% because of new gas well drilling. Of the 113 rig gain during July 31-Oct. 16, Baker Hughes reported 82 were drilling gas wells.
Smith estimated 303 rigs were drilling Section 29 tight gas wells of the 950 active U.S. rotary rigs it counted the week ended Oct. 16. Smith tallied about 540 rigs drilling gas wells on that date.
According to Smith's weekly rotary rig count, about 168 more rigs on Oct 16 were drilling wells in the U.S. than in the week of July 31. Of that increase, 158 units were drilling gas wells, including 95 in tight gas sands.
"What we're seeing in the rig count right now certainly reflects the scramble that everyone has on to get all their Section 29 wells spudded," said Mark Papa, senior vice-president of U.S. Gulf Coast and Canadian operations of Enron Oil & Gas Co. (EOG), the upstream arm of Enron Corp., Houston.
Some industry observers predict as many as 150 rigs drilling Section 29 wells will be idled in first quarter 1993.
Data compiled through mid-October by Petroleum Information Inc. (PI), Denver, shows companies are spudding new tight gas wells at the expense of tight gas completions. PI data show about 1,473 U.S. tight gas wells were completed in 1991, but only about 50 had been reported as of midspring this year. PI's top 10 companies, as ranked by tight sand gas well completions in 1991-92, reported a total 565 tight gas completions in 1991 and through mid-October 1992.
EOG ACTIVITY
EOG the past 2 years has been one of the most active U.S. tight sand operators, spudding more than 400 tight gas wells that will qualify for the Section 29 credit.
Like many other U.S. companies, EOG was involved in some tight formation activity before the credit became available. In the past 2 years, the company has drilled qualifying Frontier formation wells in Wyoming, Wasatch wells in Utah, and Cotton Valley wells in East Texas, Canyon sandstone wells in West Texas, Granite wash wells in the Texas Panhandle, and Lobo wells in South Texas.
"During the last 6 months of the year, it will account for about 80% of our total drilling effort," said Papa. In 1991, tight gas wells accounted for about 60% of EOG drilling activity.
The company's drilling emphasis the past 2 years boosted EOG tight gas production at the end of September to about 240 MMcfd, slightly less than 44% of companywide gas output.
EOG expects the Section 29 tax credit combined with a Texas state severance tax exemption on revenue from tight gas sales to generate after tax net income of more than $45 million in 1992 and $50 million in 1993.
Quaker State Corp., Oil City, Pa., is another company focusing on spudding as many tight sands wells as possible before the credit for new wells expires at yearend.
"Given limitations of our remaining capital budget, we plan to use everything available to drill wells and not necessarily completing all those this year," said Steve Bauer, Quaker State finance and administration manager.
EFFECT ON AMOCO
Tight sands drilling activity also is buoying gas production of Amoco Production Co.
"After wells we currently are drilling are completed and on line, we estimate we will be producing about 300 MMcfd of tight sands gas," said Jerry M. Brown, Amoco vice-president of U.S. exploration and production. Company-wide U.S. gas production amounts to 2.4 bcfd.
Brown said Amoco has 15 rigs running in tight sands areas.
"That generally will go to zero after the first of the year," he said.
Amoco in 1991 drilled 174 company operated tight gas wells that qualify for the Section 29 credit and expects by yearend to have spudded another 105. In 1990, Amoco drilled 80 qualified tight gas wells on company operated acreage.
In all, Amoco by yearend will have drilled 550 wells since the beginning of 1990 in tight sands areas in Texas, Wyoming, Utah, and Colorado. Its activity includes drilling about 200 company operated Moxa arch tight gas sands wells in Wyoming, 75 of which qualify for Section 29 tax credits. By comparison, Amoco from 1990 through the end of 1992 expects to drill slightly more than 1,200 wells in the U.S. Amoco also has a 42% interest in Lobo trend tight sands wells on the South Callahan Ranch in Southwest Texas, where Mobil Corp. is operator with 42%.
OTHER LARGE PROGRAMS
Quaker State is among companies with large tight gas sands drilling programs. The company expects this year to drill 61 qualified tight gas wells out of 66 total step-out and development wells, mostly in the Medina formation in Pennsylvania and the Clinton in Ohio. In 1991, Quaker State drilled 73 tight sands gas wells that qualified for the Section 29 credit out of 92 total development wells.
Before the credit was available, 50-60% of Quaker State drilling activity was in designated tight sands areas. Bauer said the company's tight gas production in the past 2 years has increased at about the same rate as its tight sands drilling.
Meridian Oil Inc., Houston, expects by yearend to have participated this year in about 70 wells in Section 29 qualified tight sands areas. It drilled about 95 in 1991. Such drilling accounted for about 25% of all new wells in which the company held working interests in 1991-92.
Combined tight gas production net to Meridian's interests in both years has averaged 19-20 MMcfd out of total U.S. production of about 800 MMcfd. Most of Meridian's Section 29 drilling has occurred in qualified coal seams.
Coastal Corp., Houston, by yearend expects 1992 tight sands gas well drilling to total 120 wells, or about 78% of its U.S. total. In 1991, 65% of Coastal drilling was in tight sands.
The company's tight sands activity is focused in Northeast Utah, South Texas, Southwest Wyoming, and Northwest Colorado. Coastal estimates that tight sands production will account for about 19% of its 1992 gas flow, up from about 7% in 1991.
RIG AVAILABILITY
Bauer said the surge of drilling occurring in the U.S. because of the imminent expiration of the Section 29 credit is squeezing rig availability in tight sands areas.
"We're not sure we're going to have enough rigs to begin drilling what we want to drill by yearend," he said.
Unless gas prices continue increasing, Bauer said, Quaker State expects rig availability to improve after 1992, at least in first half 1993, because many companies focusing on tight sands drilling this year will forego drilling some wells next year to catch up on tight sands completions.
But despite the large expected decline of U.S. drilling activity expected after the first of the year, Bauer said, Quaker State believes rig availability after 1993 will become a problem. He said many problems plaguing the oil and gas industry for the past 7 years have significantly reduced the number of qualified drilling crews available in the Northeast.
Papa said rigs are in tight supply in tight sands areas of East Texas, South Texas, and Wyoming.
"The rig count in first quarter 1993 likely will be a function of what happens to gas prices this winter," Papa said. "But if you factor out rig activity in response to various gas price scenarios, we're certain to see a big negative bounce in the rig count because of Section 29 expiring."
PACE OF 1993 DRILLING
Operators agree most drilling in U.S. tight gas sands areas will grind to a halt early next year.
Papa said EOG tight sands drilling will drop sharply because most of its tight gas prospects are not economic without the Section 29 credit.
"There will be a few areas, where we found a sweet spot or where we have a special situation, where we'll be able to continue drilling but on a much less active scale," Papa said.
Quaker State expects to become more selective about the tight sands prospects it is willing to drill.
"We'll be drilling some tight sands wells," Bauer said. "We'll just be looking more closely at variable well costs to earn an acceptable rate of return."
If gas prices don't improve much more, Bauer said, "we'll have to drill a few more higher risk, higher cost exploratory prospects, which generally have more reserves potential and larger paybacks."
Coastal said it will continue drilling in some tight sands areas next year, regardless of what happens with the Section 29 tax credit. However, the company said its rate of tight sands drilling will decrease not because the credit is expiring but because Coastal expects to have started development on most of its tight gas properties by yearend 1992.
"We don't drill wells unless they're economically viable," a Coastal official said. "So while Section 29 has been an additional incentive, we did have some tight sands drilling before and it's quite possible we would have done some tight sands drilling in 199192 if it were economical without the credit."
NO CHANGES EXPECTED
Rick Hebert, Meridian senior vice-president of operations, said the company neither expected the Section 29 tax credit to be extended beyond 1992 nor began a big push this year to drill tight sands wells.
"So our activity levels next year will not be significantly affected," he said.
Similarly, expiration of the tax credit will have little effect on drilling plans of Wagner & Brown, Midland, Tex.
The independent the past 2 years has been qualifying wells for the Section 29 credit, mostly on tight sands acreage in Conger field, Sterling County, Tex. But rules preventing producers from applying the credits to alternative minimum tax liabilities have prevented Wagner & Brown from using it.
"Because of our federal tax situation, we aren't able to enjoy the benefits of the tax credit that some other producers might be able to," said a Wagner & Brown official.
Yet Wagner & Brown has been drilling and qualifying tight sands wells because the credit can be claimed through 2002 on production from wells drilled before the yearend 1992 deadline.
"Looking ahead, we can't anticipate what changes might take place, either in our situation or the tax law," the official said. "So we want to preserve an opportunity while it exists, even though we don't have a current benefit."
Wagner & Brown said the credit had not spurred it to undertake drilling it wouldn't have considered otherwise because it considers its tight gas wells economic without the credit.
TIGHT SANDS ECONOMICS
Critics of the Section 29 tax credit claim most companies drilling qualifying tight gas wells have been working in areas where many wells would be economic even without the credit.
But some companies drilling qualifying wells dispute that. Bauer said some of the tight sands gas wells Quaker State drilled in 1991-92 might have been economic with higher gas prices. But gas prices that mostly prevailed the past 2 years have been too low for most of Quaker State's tight sands wells to be economic.
According to corporate guidelines, gas prices must average about $2.50/ Mcf without the credit for the tight sands wells to be economic, Bauer said. In 1993, Quaker State expects to set a development drilling budget about 25% lower than if the Section 29 tax credit had been extended.
"Since that was not passed, we reduced our budget to about $4.5 million from about $6 million," he said.
Amoco's Brown said many tight sands wells drilled in the past 2 years would not have been drilled without the Section 29 credit because without it, "tight gas wells just don't stack up against other drilling opportunities."
When deciding which activities to fund with limited operating capital, he noted, companies compare the economics of possible projects. Some unconventional gas wells might have been economic without the credit but likely would not have been drilled because they could not compete with other prospects in Amoco's portfolio.
Papa said the industry's strong effort to boost tight sands activity indicates that many prospects drilled would have been uneconomic without the Section 29 credit.
"There's no question that a significant number of tight sands wells we drilled in the past 2 years would not have been economic without the credit and likely would not have been drilled," he said.
Enron supported extending the Section 29 tax credit because of its perceived effect on long term supplies. But recent wellhead gas price increases indicate U.S. tight gas production could become more important sooner than later.
"The main point we make about Section 29 is it will generate a lot of long term gas supplies," Papa said. "Many of the people who decried extension of Section 29 would like to create a shortfall of gas so prices would rise dramatically."
Section 29 gas accounts for only 35% of marketed U.S. gas production.
ACHIEVING INTENDED GOALS
Amoco's Brown contends that from the standpoint of an operator or a policymaker, the tax credit has done what it was intended to do.
"It spurred activity in tight sands areas," he said. "Wells were drilled that never would have been drilled in the price environment we've been facing in 1991 and early 1992."
Brown said tight sands wells were drilled even when gas prices were quite low, providing competitively priced gas in a market characterized by growing demand.
With the possible exclusion of companies not holding extensive tight sands acreage, "we think it was good for everybody," he said.
Brown said Section 29 credits allowed producers with qualifying wells additional price stability during a period of plunging wellhead prices, "particularly in the summer of 1991 and early 1992."
Indeed, most companies trying to take advantage of the credit contend it has achieved most of the policy objectives intended by Congress.
Meridian's Hebert said the credit has been an indispensable factor in developing tight sands fracturing and completion technology, thereby helping to assure the viability of tight formations as a long term, economic gas resource.
"It gave incentives to the industry to look in nonconventional areas and identify significant future reserves," Hebert said.
Although Hebert maintained Meridian didn't target its development program based on economics associated with generating tax credits, Section 29 gave the company more confidence to overcome risks and apply technologies required to stimulate tight formations.
"We weren't using the credit as the basis to develop the needed technology. It was not the driving factor for us that it was for some companies," he said. "But it did serve as an incentive and gave us the confidence to proceed."
Papa said, "I can think of several cases within EOG where we developed fracture technology for specific tight sands wells in the course of Section 29 work, and we hope to be able to apply those lessons to other situations."
LESS TIGHT SANDS DRILLING
Brown said the Section 29 credit's expiration at yearend will alter comparative well economics, likely reducing drilling in tight sands areas to very low levels throughout 1993.
How much tight sands drilling slows will depend partly on wellhead prices and the extent to which budgets will allow spending on conventional drilling activity.
Onshore service and supply contractors particularly are concerned about what will happen to drilling activity after the first of the year, he said. Recent increases in wellhead prices, while improving economics of some tight sands prospects, also have improved economics of conventional prospects, so Amoco next year still is not likely to drill many unconventional gas wells.
"I don't think gas prices right now are going to influence our expenditures on tight gas," Brown said. "We will direct our drilling capital to the most economically attractive prospects, and as a consequence tight sands prospects will not get funds relative to more conventional areas."
Amoco likely will step up drilling on offshore leases where its activity has been low for the past couple of years, he said.
Unpredictable gas price stability and price levels will significantly influence the pace of future unconventional gas development.
"But even in a higher pricing environment, I think we still would not see tight gas areas get a lot of activity because most of our capital will be moved to more conventional projects for the higher rates of return per unit of investment," Brown said.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
