A.D. Koen
Gulf Coast News Editor
The U.S. gas industry is edging toward harder times as growing supplies, sluggish demand, and regulatory uncertainty continue to stifle wellhead prices.
Following the 1990-91 heating season, marked by the warmest winter weather on record, U.S. gas producers were rocked last summer by still lower prices.
Throughout 1991, many companies adjusted to low wellhead prices by:
- Shutting in or curtailing production and buying gas on spot markets to serve sales contracts.
- Increasing production of unconventional gas qualifying for federal tax credits.
- Scaling back or refocusing 1991 exploration, drilling, and development plans.
- Restructuring, laying off employees, or taking writedowns on the value of gas reserves to reflect lower prices.
Expectations of continuing low gas prices last fall prompted many executives, respondents to an Arthur Andersen & Co. survey, to report plans to trim exploration and capital spending in 1992.
Gas producers hoped the 1991-92 heating season would stimulate demand enough to boost wellhead prices and increase cash flow. But gas surpluses have continued to grow, and low wellhead prices in mid-December showed no sign of increasing.
Growing deliverability, storage utilization, and pipeline capacity have boosted 1991-92 heating season gas supplies above the volumes available last winter.
At mid-December, spot market gas prices for January 1992 delivery trailed those of 1 year ago at a time when demand and price should be peaking.
Moreover, a stagnant U.S. economy can blunt demand, a sign that the worst may be yet to come for the U.S. gas industry.
While some in the industry voice concern about whether long term supplies will be adequate to serve greater future demand, others are prepared to measure success in 1992 in terms of survival.
Says Carol Freedenthal, principal of Jofree Corp., Houston, "We're going to see some more bloodletting before gas markets turn around."
Adds Jeff Skilling, chairman and chief executive officer of Enron Gas Services, "I wouldn't be at all surprised if 1992 gas prices come in weak relative to last year."
WORSE STARTING POINT
Perhaps most disturbing to gas producers is the growing belief that U.S. markets are in worse shape this winter than last.
With spot gas prices for January 1992 deliveries drifting below $1.75/Mcf, Freedenthal says it appears 1991-92 heating season prices peaked in December.
During the 1989-90 heating season, Freedenthal says, prices began falling in the middle of February.
Last winter, the decline began in January 1991.
"When you recall that prices for December 1991 deliveries were bid in the high $1.80s/Mcf to low $1.90s/Mcf, you can only say the market is cratering," he says.
"Coming in December, so early in the heating season, it's got to cause horrible uncertainty for people trying to budget 1992 operations.
"Companies have to be wondering whether they should put any money into exploration and production."
The U.S. Commerce Department's National Weather Service (NWS) and National Oceanic and Atmospheric Administration (NOAA) report that weather in the U.S. during July 1-Dec. 7, 1991, was 3% colder than normal and 16% colder than last year. But much of the cold has focused in regions that have not helped demand on U.S. gas markets.
"A lot of the cold weather we had in November and December was focused in the extreme Upper Midwest and mountain regions," Skilling says. "In high population, high gas consuming areas, our weather has been reasonably warm. As a result, prices are very soft."
As much as gas producers are disappointed by lower spot gas prices, Freedenthal says, they are just as surprised that demand is so low.
"Local distribution companies are taking gas out of storage," he says. "People just don't want gas right now. We're seeing real decay in the market."
END OF WINTER
Skilling says market softness in mid-December showed that many buyers believed extremely cold weather won't return this winter to major U.S. population centers.
"It's pretty clear the market believes winter is over at this point," he said. "It's going to take a period of very cold weather in January and February to get any kind of significant price boost this year. But the forecasts suggest weather in the first quarter 1992 is not going to be particularly cold."
The 90 day weather outlook through February 1992, compiled by NWS and NOAA, estimates there is a 55% chance of below normal temperatures for the southern Rocky Mountains, eastward through the High Plains, Texas, and all of the South, as far north as the Ohio River. In eastern New Mexico, Southwest Texas, Gulf Coast, and southern Appalachian Mountains chances for excessive cold are as high as 65%.
However, there is a 55% chance of above normal temperatures in northern California, Washington, western Oregon, and Montana, east-southeast across the Mississippi Valley, Great Lakes, New York, and New England. In the Upper Mississippi Valley and Upper Great Lakes the chances of warmer than normal weather increase to 65%.
To make a significant difference on U.S. gas markets, Freedenthal says, a cold snap would have to come at the right time with enough force.
"And we know by the end of January or February we'll be back into a downward pricing spiral," he said. "Most major U.S. gas consuming areas just don't have subzero temperatures in March.
"So we have to conclude that until next October or November gas prices will not be going back up."
1991 MARKET ACTIVITY
Participants in all sectors of the U.S. gas industry say demand would have increased significantly in 1991 if the U.S. economy had begun recovering.
"There's no question demand is responding to price signals," Skilling says. "We're seeing a lot of interest in using gas from all consuming sectors across the board."
The American Gas Association says U.S. gas consumption in 1991 reached about 18.8 tcf, about 100 bcf more than 1990 demand.
"If we had had a normal winter in 1990-91, the U.S. would have consumed more than 19 tcf of gas in 1991," says Mike Baly, president of AGA. "An industry that is increasing sales is not on the brink of disaster."
AGA has launched a campaign to increase gas demand at least 2.5 tcf to 21.3 tcf by 1995 (OGJ, Dec. 23, 1991, p. 24). Baly says the association's marketing plan will help wellhead prices become less temperature sensitive.
U.S. producers' strategy of curtailing 1991 production to bring supply and demand into balance produced only minor market adjustments.
Through September 1991, the Energy Information Administration reports, U.S. producers decreased dry gas production to about 13.124 tcf, only 60 bcf less than the first 9 months of 1990. Through the same time, spurred by low gas prices, U.S. gas consumption increased 452 bcf compared with 1990.
Supply lost to curtailments was partly made up by two sources:
- Withdrawals from storage through September 1991 surpassed 1.5 tcf, 240 bcf more than in 1990.
- Imports through September 1991 totaled nearly 1.2 tcf, 104 bcf more than in 1990.
As a result, about 3.2 tcf of working gas was in storage at the end of November 1991. That was 283 bcf less than a year earlier, but still 140 bcf more than the 5 year, end of November average during 1985-89.
With ample gas in storage, imports up, and production decreased mainly by curtailment, gas supplies heading into 1992 appear adequate for the short term.
NEW SUPPLY CONTRACTS
Although U.S. gas demand is increasing, matching reasonably priced supplies to the needs of new customers is a continuing stumbling block to capturing new markets.
"Somehow, the gas industry has to decide what is a fair price for longer term contracts," Baly says. "Many producers think gas prices will improve markedly, and some companies have written longer term contracts with sizable escalators above today's spot prices."
To spark demand among local distribution companies (LDCs) and industrial and commercial customers, Enron has been promoting contracts that offer long term supply and price predictability.
In April Enron will begin offering a group of sales agreements called EnFolio Gas Resource contracts, which will guarantee firm volumes of gas with prices based on provisions tailored to mirror the investment requirements of potential customers.
Under EnFolio contracts, gas purchasers may select among these options:
- EnFolio 30 contract offers a firm 30 day commitment, in contrast to current spot market deals that are best effort agreements. Enron says its contract offers stability at midmonth, when buyers bid lower prices and temptation is greatest to back out of best effort agreements.
- A fixed price contract offers firm future delivery at a fixed price based on Enron's aggregated portfolio of gas supplies.
- A gas cap contract allows the price to float with an index up to a ceiling, protecting customers from price spikes.
- Gas blend contract combines fixed price and indexed escalators to dampen price volatility. When gas prices go up or down on spot markets, the gas blend contract price will change by a lesser degree, depending on the portion of fixed price blended into the contract.
- Gas index contract allows a customer to lock in a specific price differential between various gas and alternative fuels indices. A company switching to gas could assure future gas costs would be low enough, compared with a specific competing fuel, to offset the investment in gas fired equipment.
"And we're working in some contracts linked to gas liquids prices," Skilling said.
Enron has yet to offer gas contracts with prices indexed to coal markets. But Skilling said Enron Gas Services' power services group is structuring a coal lookalike contract that packages long term gas supplies for the electrical power industry.
Because the capital cost of building a coal burning power plant far exceeds that of a gas fired power plant, the coal lookalike contract allows customers to apply some capital cost savings realized by building a gas fired plant to make a prepayment that buys down the commodity cost of gas, Skilling said.
OUTLOOK FOR DEMAND
Baly says passage in 1990 of amendments to the Clean Air Act and enactment, "maybe a year from now," of a National Energy Strategy could provide a one-two punch that will help stimulate gas use.
He criticized some states for discouraging gas consumption by promoting clean coal technology to protect coal industry jobs within their borders. Promoting cofiring applications for gas and coal would be more beneficial, he said.
"Gas and coal are the country's two largest energy sources, and we ought to be working to displace imported oil," Baly said. "If we focus on coal and mandate scrubbers, jobs in the coal industry still could be lost because electricity costs get too high."
Meanwhile, AGA estimates that 19.5-19.9 tcf and 20.4-22.3 tcf of gas will be available to U.S. markets in 1995 and 2010, respectively (OGJ, Oct. 28, 1991, p. 95). Incentives could increase supply to 25.8 tcf by 2010.
According to AGA, in 1991 for the first time gas consumed by cogeneration facilities topped 1 tcf.
Also, AGA estimates two new compressed natural gas (CNG) refueling stations/day opened in the U.S. in 1991. Baly applauds decisions in 1991 of the U.S. Big Three automakers to focus on developing CNG vehicles.
AGA proposes that all segments of the industry cooperate to expand U.S. gas markets. Among the goals of its 5 year marketing plan, AGA intends by 1995 to increase gas consumption by:
- 1 tcf/year on electric generation markets.
- 1.3 tcf/year though oil to gas conversions at stationary facilities.
- 20-30 bcf/year through electric to gas conversions, including residential and commercial gas cooling applications and converting electric water heaters to gas in 5 million homes with gas heating.
- 10 bcf/year by converting 50,000 fleet vehicles to run on CNG.
AGA also aims to convert another 2 million vehicles to CNG within 10 years.
"If we eliminated oil usage in every stationary facility in this country-every home, power plant, steel mill, chemical plant-the transportation market would still consume more oil than we produce," Baly said. "That does not make sense."
AGA's proposed oil to gas conversions would trim U.S. oil imports by 750,000 b/d, Baly says.
SUPPLY CREDIBILITY
Supplies appear to be adequate to handle foreseeable demand this winter, but concerns persist about the adequacy of future supply.
Robert J. Allison, chairman and chief executive officer of Anadarko Petroleum Corp., says long term wellhead supplies and deliverability needed to serve new markets envisioned by AGA are not guaranteed.
When it comes to convincing potential gas customers of the adequacy of supplies, the U.S. gas industry has a serious credibility problem, he says.
Despite potential gas resource estimates of about 1 quadrillion cu ft by AGA and the Department of Energy, Allison contends that proved, producing U.S. gas reserves-less 34 tcf of proved, nonproducing gas-total about 135 tcf.
At existing decline rates, he says, production from proved, producing gas reserves will decline from 18 tcf in 1990 to 14 tcf in 1993 and 11 tcf by 1995.
"If the gas industry is to avoid serious supply shortages in the next decade, we need to find a lot of gas-and soon," Allison said. "And we sure aren't going to do it with 800 rigs running."
DOE says Lower 48 gas reserves increased by 1.3% in 1990. But Allison questions the reserve replacements, most of which he says were based on infill drilling and revisions to prior estimates rather than new field discoveries.
"With the low rig count, there is no question that reserve replacement in the future will not be what it was in 1990," Baly said. "There will be a drop."
Concern about future gas supplies last year prompted AGA to combine its gas supply and gas demand committees "to make sure our supply and demand estimates are responsible."
Baly said, "It also bothers us that engineering schools are closing and there might not be enough talent to do the job."
An indication of the increased drilling needed to maintain gas reserves as demand increases can be found in data compiled by the University of Texas at Austin's Bureau of Economic Geology.
UT Prof. William L. Fisher says that since the late 1970s U.S. operators have added gas reserves in the Lower 48 in direct proportion to drilling activity, "in significant contrast to the presumed notion of exponential decline."
Fisher says:
- 42,000 wells drilled in 1977 through 1979 added 43 tcf of reserves.
- 56,000 wells in 1980-82, 58 tcf.
- 44,000 wells in 1983-85, 41 tcf.
If the same 1:1 proportion between wells drilled and reserves found had continued through the second half of the 1980s, the 43,000 gas wells drilled in 1986-90 should have yielded 43 tcf of new reserves.
"The actual yield has been 83 tcf," Fisher said.
Overall oil and gas reserve additions after 1985 have been more than 5 million bbl/rig of oil equivalent (BOE), he says.
If the average number of active rigs increased to 1,500 and drilling efficiencies were maintained, Fisher says, reserves additions would reach 7.5 billion BOE/year, enough to support U.S. production of 8.2 million b/d of oil and 22 tcf/year of gas.
Fisher reckons that indicators of exploration performance show similar efficiency improvements. The average size of fields discovered in the U.S. has declined since 1950 from more than 4 million BOE to about 500,000 BOE in the 1980s.
However, declining field size has been offset by "quantum jumps in acquisition, processing, and interpretation of reflection seismic data," and a stable volumetric finding rate has been achieved.
As a result, Fisher concludes that the long term U.S. gas supply outlook is good. But he warns that too few wells are being drilled-especially new field wildcats.
REGULATORY UNCERTAINTY
The evolution of federal gas industry regulation has added uncertainty to the form and performance of future gas markets.
Debate over the Federal Energy Regulatory Commission's so-called mega-Notice of Proposed Rulemaking (mega-NOPR) raises questions about how the proposed rule will affect service to gas customers.
Coastal Corp. Pres. James R. Paul says FERC's mega-NOPR will have unintended side effects, killing competition, introducing inefficiency, and disrupting gas markets to an unprecedented degree (OGJ, Dec. 2, 1991, p. 28).
Paul says forcing pipelines to unbundle charges for gathering, transmission, and marketing services will unnecessarily change a system that has worked for 5 decades and force LDCs to shoulder all the risk of providing gas service during periods of peak demand.
If mega-NOPR is approved, Paul says, "a cold front-even one that misses an LDC's service area-will trigger buying at premium prices to cover the just-in-case situation."
He warns that large, unregulated sellers will control capacity, allowing them to charge what the traffic will bear.
As an alternative, Paul says the gas industry should formulate its own comprehensive energy plan that focuses on consumers and balances benefits among all segments of the U.S. gas industry.
Anadarko's Allison says say nothing in FERC's proposed rule would prevent pipelines from offering a menu of unbundled services and packages of rebundled services (OGJ, Dec. 23, 1991, p. 6).
In contrast to assertions that mega-NOPR will kill competition or restrict customers' options, Allison say the rule "will create conditions where gas buyers can choose the services that match their market needs from pipelines, producers, and marketers."
"More sellers of gas...should lead to more innovation in contracts and services provided to the market, not less," he insists.
Rather than changing a system that has worked for 5 decades, Allison says, mega-NOPR will allow customers more options to assure their needs are served on peak heating days.
Also, he maintains, existing bundled service contracts of pipelines have not been able to guarantee supplies during peak demand.
"During the 1970s, U.S. interstate pipelines could deliver on average just 70% of customers' contract demand," Allison said.
Anadarko believes mega-NOPR will put into place market-based reforms that began 5 years ago under FERC Orders 436-500.
"Offering customers more options for their particular supply needs can only lead to better conditions for all segments of the industry," Allison said.
THE RIGHT CHOICE
If U.S. gas demand is to continue growing, AGA's Baly says, it is important for all sectors of the gas industry to cooperate.
"Unlike the weather, gas demand can't be increased overnight," he said. "But the whole gas industry-producers, marketers, transmission companies, and consumers-can stimulate demand by working together."
When U.S. consumers have the option to choose, Baly says, they pick gas in 59% of residential applications and more than 50% of commercial and industrial applications.
"The time is right to work together to market the fuel of choice," he said.
Skilling says Enron believes U.S. gas markets have tremendous potential to grow, given enough time and investment capital.
"But that new demand won't just happen by itself. The gas industry is very capital intensive, and if we want to increase demand, people are going to have to invest significant sums of cash."
He says producers will have to find enough capital to continue drilling gas wells, pipelines to continue expanding and interlocking pipeline systems, and consumers to continue investing in gas burning equipment and facilities.
"To do that, they need assurance that the physical molecules will show up when they're needed to justify their investments," Skilling said.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.