One of the warmest winters on record has kept the U.S. natural gas industry in doldrums.
Unseasonably high temperatures during winter 1990-91 kept U.S. gas demand flat while supplies increased.
Industrial gas demand already was lagging heading into last winter because of the economic recession. And the supply/demand balance worsened as gas storage use remained high while production and deliverability rose.
The upshot has been a slide in spot gas prices to the lowest monthly average level in the history of the Natural Gas Clearinghouse (NGC) survey of U.S. spot gas prices. The NGC survey showed an average $1.25-$1.30/Mcf for February-April 1991 vs. $1.39-1.84/Mcf during the same period in 1990. That's in contrast with a spike in spot gas prices that accompanied a severe cold snap in the 1989-90 heating season (OGJ, Mar. 5, 1990, p. 17).
The squeeze in gas prices has spurred some companies to shut in production, curtail drilling plans, or even restructure. Others, however, are boosting sales to maintain cash flow in spite of lower prices.
Paine Webber noted U.S. gas related drilling has fallen 23% since the fourth quarter and well permit applications in the Gulf of Mexico have plunged almost 50% from a year ago.
As bleak as the near term looks for the U.S. gas industry, however, there remain signs the long awaited disappearance of the gas deliverability bubble is on the near horizon, perhaps with the next hard winter or economic upturn.
SUPPLY/DEMAND SITUATION
Supplies on U.S. gas markets were plentiful in 1990 because storage utilization was high and productive capacity jumped by about 4.3 bcfd.
U.S. gas demand remained at about 52 bcfd in 1990, however.
Some end users and distribution companies last winter relied more heavily on storage drawdowns to meet spikes in demand and bought less gas on spot markets. While peak demand was within typical historical ranges, 1990 ended with 3 tcf of working gas in storage, nearly 500 bcf more than at yearend 1989.
Heavy competition for available markets kept squeezing gas prices through first quarter 1991.
Persistently low gas prices are forcing many exploration and production companies to change drilling and development strategies. Some are curtailing production rather than accept the lower gas prices, while others are increasing production of low cost reserves to maintain revenues.
Some gas prone E&P companies have taken writedowns on gas reserves to conform asset values to lower prices.
Most operators are tempering risks while awaiting stronger markets and higher prices by drilling more development wells.
The outlook is weak for gas prices until next fall, when the onset of the heating season is expected to push prices up again.
Jofree Corp., Houston, expects U.S. gas prices in 1991 to average $1.53/MMBTU, increasing to $1.73/MMBTU by 1993. Jofree predicts U.S. gas demand will climb to 21.2 tcf in 1993 from about 19 tcf this year.
LOW PRICE SCENARIO
Many gas producers, pipelines, and local distribution companies say low gas prices in first quarter 1991 primarily stemmed from relatively short term market imbalances. They believe gas surpluses are smaller than prices indicate.
After several years marked by excess supplies, the U.S. gas industry entered the 1989-90 winter heating season with 3.3 tcf of working gas in storage, Energy Information Administration reported. Abnormally cold temperatures in late December 1989 created a net draw on storage of more than 750 bcf during that month. There was about 2.5 tcf of working gas in storage at yearend 1989, and with curtailments of interruptible customers, industry bid spot prices up sharply.
After December 1989's peak demand, gas companies continued buying gas to replenish storage, anticipating seasonally higher demand in first quarter 1990.
But the draw on storage in first quarter 1990 was the smallest in a decade. Storage volumes of working gas remained higher than normal throughout the year, and the industry entered heating season 1990-91 with more than 3.4 tcf of working gas in storage. With demand lower than expected last winter, 1990 ended with more than 3 tcf of working gas remaining in storage, EIA said.
HISTORICAL MARKETS
In the early 1980s, surplus gas productive capacity developed as federal regulations discouraged consumption and gas supplies increased because of high drilling activity levels.
After 1986, gas surpluses began declining because falling prices dampened gas well drilling and completions while at the same time encouraging slight increases in demand.
The curtailments of the 1989-90 winter and resulting price spikes raised concerns about adequacy of U.S. gas supplies.
EIA estimates average U.S. gas productive capacity had fallen to 61.3 bcfd at yearend 1989 from 70.8 bcfd in January 1986. Correspondingly, U.S. surplus deliverability had dropped to an average 13.7 bcfd by yearend 1989 from 21.5 bcfd in January 1986.
If no gas wells had been completed after 1989, U.S. surplus productive capacity would have plunged to zero by January 1991, EIA said.
In 1989, average December utilization of available wellhead capacity reached 77.6%, the highest since 78.1% in 1980.
AGA'S VIEWS
Robert Kalisch, American Gas Association manager of gas supply and statistics, said, "We've had warm winters for several years now. The last real cold month was December 1989."
"Gas is very competitive now. Prices are quite low. We have warm weather, a recession, and the usual difficulty in marketing the gas in the summer months."
He said the gas bubble is all but gone.
"Supply and demand are pretty well matched up for a normally cold winter heating season, but we haven't had any of those for a few years so we haven't been matched up.
With prices continuing to be low, he said, "Producers are taking a risk to develop gas resources when the market is so lackluster."
He noted completions are up 9.8% through December 1990, so, "I think it's amazing we've done as well on gas well completions as we have. Its a tribute to industry's conviction that this thing is going to turn around with normal weather and new markets."
STORAGE FACTOR
Kalisch said another reason supply is having no trouble meeting demand is the increase in gas storage.
EIA reported a record 805 bcf of gas came out of storage in December 1989, or about half the total 1.5 tcf of U.S. production that month.
"People don't think of storage in such dramatic terms, but it's had a dramatic effect," Kalisch said.
EIA said, "in the past several years, both the levels of working gas in storage at the beginning of the heating season and total available working gas capacity have continued to increase. In addition, the utilization rate for working gas capacity has increased to 80%.
"These increases have occurred at the same time that the number of reservoirs and total storage capacity have actually slightly decreased. This has been possible due to the better use of available capacity brought on by improvements to existing underground storage facilities and the opening of storage services to competitive forces brought on by market restructuring."
EIA said as a direct result of 1990 having about 16% fewer heating degree days than normal, the amount of natural gas withdrawn from storage decreased almost 32% in 1990 from 1989 levels.
"This lack of demand has kept working gas volumes at record high levels for this time of year and has played a significant part in keeping end use sector prices comparable to last year's prices."
DELIVERABILITY
Meanwhile, gas pipeline construction continues to expand U.S. access to more gas supplies.
As of January 1991, gas pipeline projects totaling 8,730 miles had been approved, were pending at the Federal Energy Regulatory Commission or other regulatory bodies, or were under construction (OGJ, Feb. 11, p. 31).
The projects could add up to 10 bcfd of pipeline capacity, although AGA noted that might not equate to increased throughput. It said another 9 bcfd is in various stages of planning or regulatory approval, although all of that might not be built.
A Natural Gas Supply Association survey found U.S. gas productive capacity utilization increased on an annual and peak month basis in 1989, and the higher utilization rate indicates the gas deliverability surplus is diminishing (OGJ, Oct. 22, 1990, p. 29).
The survey found capacity utilization increased to 82.3% in 1989 from 81% in 1988.
The NGSA survey of 41 producing companies showed their productive capacity rose in 1989 to 32.821 bcfd from 32.02 bcfd while deliveries rose to 27.022 bcfd from 25.939 bcfd. Another 2.344 bcfd was waiting for pipeline hookup.
NGSA Pres. Nicholas Bush said, "it would appear that at long last the gas 'bubble' that was only to last 6 months when it developed 8 years ago-is sluggishly going away. What this means for all segments of the natural gas industry, from producers to consumers, is that new sources of domestic natural gas supplies are going to have to be sought out and developed."
NONCONVENTIONAL GAS WELLS
Low gas prices are causing Arkla Exploration Co. to redirect drilling toward development prospects and nonconventional gas reserves that qualify for federal and state tax credits.
In East Texas, Arkla plans to spend $90 million to drill 80 tight sands gas wells in Carthage and Waskom fields in 1991-92. Most drilling will occur in Panola and Harrison counties.
Tight sands gas wells are especially attractive prospects in Texas. In addition to a federal tax credit of 52/MMBTU on gas produced from tight sands wells drilled by yearend 1992, the Texas Railroad Commission allows a 12/Mcf abatement of state severance tax.
Enron Oil & Gas Co. (EOG) plans to spend a substantial part of its 1991 budget on drilling 150-200 tight sands gas wells. The federal tax credit for tight sands gas equates to about 80/Mcf before taxes, EOG said.
CURTAIL PRODUCTION
EOG has curtailed 30% of its production because it is unwilling to sell gas at prices prevailing on U.S. spot markets, said Forrest Hoglund, president and chief executive officer of the Enron Corp. subsidiary.
"With prices at $1.20/Mcf, I think we can make a pretty good case for not selling what we have rather than drilling for new reserves," Hoglund said.
At yearend 1990, EOG expected its 1991 budget to be very close to 1990 capital and exploration outlays of $309 million. As natural gas prices dropped in first quarter 1991, EOG cut its projected 1991 spending to $240 million.
To minimize the effect of low spot market gas prices, EOG hedged about 30% of its gas sales under long term contracts.
Hoglund said distressed gas pricing can be overcome if gas producers sell less gas on spot markets and increase sales under long term contracts. Long term contracts benefit producers and consumers, he said.
"If a consumer can get prices with fixed escalations for long terms, he at least knows what his gas price will be," Hoglund said.
Gas producers willing to sign long term sales contracts will win larger shares of new power generation markets, he said.
Hoglund said some of the decline of spot market prices can be attributed to improved drilling and production technology. More reserves are being found with fewer wells, improving wellhead economics and thus enabling some producers to profit at lower prices.
"But I still don't see why people keep selling their gas, regardless of what price is offered," he said.
In the short term, Hoglund said, improved operating efficiencies depress gas prices because resulting lower production costs enable producers to accept lower gas prices.
However, in the long term, that bodes well for the U.S. gas supply outlook, he noted.
HOLDING STEADY
When gas prices started failing in 1986, Kelley Oil Corp. decided scaling back operations to ride out the storm until things got better would work for only a short time.
Since then, the company has focused on drilling economic development prospects and has sought acquisitions, mostly in areas where it already owns interests.
"We'd still be waiting for high prices-if we were still around," said Joe Bridges, president of Kelley Oil and Kelley Oil & Gas Partners Ltd. "Even though our gas prices have continued to decline since 1986, we've sharply increased production and cash flow."
Kelley group's annual production has increased by more than 400% since 1986, to 21 bcf of gas equivalent in 1990. Cash flow last year rose to $29.1 million from $4.1 million in 1986.
Bridges said Kelley has kept its gas moving by keeping its spot gas prices in tune with the market. During 1990, one long term contract accounted for about 28.3% of Kelley's gas sales.
During December 1990, Kelley's gas sold for prices about 5% higher than during December 1989. During first quarter 1991, prices averaged 18% below first quarter 1990 levels, Bridges said.
Bridges believes U.S. gas demand will grow about 3%/year during the 1990s.
"Natural gas is a premium fuel," he said. "As long as we continue to increase production and reserves, pricing will work itself out in due course."
LOW FINDING COSTS
Meridian Oil Inc.'s gas prices deteriorated by about 25/Mcf in first quarter 1991 from first quarter 1990.
At the same time, Meridian first quarter sales averaged 717 MMcfd and operating income totaled $69 million-up from 610 MMcfd and $56 million in first quarter 1990.
"Our intention every month is to sell as much gas as we can," said Dick Jack, Meridian executive vice-president and chief financial officer. "That's not to say we wouldn't hold some gas off the market early in the month in hopes of improving secondary markets later on."
Like Kelley, Meridian doesn't see much difference between gas markets for the past 4 years and in first quarter 1991.
"Oil and gas companies should know how to cope with low gas prices by now," Jack said.
Meridian copes with low prices by maintaining low finding costs.
During the past 3 years, the company has held finding costs to less than 70/Mcf. During 1990, Meridian increased reserves by 370%, two thirds through drilling and one third through acquisitions, Jack said
Meridian's gas reserves at yearend 1990 were 4.7 tcf.
MAJOR RESTRUCTURING
Lack of market demand and low gas prices have prompted Forest Oil Corp. to continue a restructuring begun in 1990.
The company intends to cut operating and financial risks by deemphasizing new field exploration. It plans to add to its reserve base by exploiting development opportunities, farming out prospects from its inventory of properties, and pursuing strategic acquisitions.
Forest announced in early April that it had terminated 47 salaried positions and would offer severance packages to 25 other employees during the next 9 months, as specific projects are completed.
In 1990, Forest reduced its staff by 20% in a reorganization designed to trim $10 million of administrative costs beginning this year. Low prices during first quarter 1990 forced the company to write down the value of its reserves.
William Dorn, Forest president and chief executive officer, said the company will continue reduced levels of exploration, drilling lower risk prospects.
"We can't count on prices to boost our cash flow in the near term," Dorn said.
RELIANCE OF STORAGE
Union Texas Transmission Co. (UTT), Houston, changed its gas purchase pattern during the past heating season, relying more on storage to meet peak demand.
"We actually bought about 200-300 MMcfd more gas during the summer than in the winter," UTT Pres. Wayne Thompson said.
UTT is a subsidiary of Occidental Petroleum Corp. unit MidCon Corp., Lombard, Ill.
Until it began 2 years ago purchasing storage from Natural Gas Pipeline Co. of America, another MidCon subsidiary, UTT didn't use storage, Thompson said.
In addition to the crimp on gas prices resulting from unusually warm weather in first quarter 1991, Thompson said prices might have dropped unexpectedly because so many companies supplied demand from storage.
For example, Thompson said UTT last winter injected 17 bcf of gas into storage, roughly twice as much as during the 1989-90 heating season. Though warmer than normal, weather in January-February 1991 still was cold enough for UTT to withdraw all the gas it had in storage.
Currently, the company is replenishing storage according to its annual plan, and not holding back for lower natural gas prices next summer, he said.
Although UTT believes it can anticipate demand on its own pipeline system, gauging supply is another matter.
"It's hard for us to get a good picture of how much new gas is coming to market and how much gas is shut in," Thompson said.
COST OF SURPLUS
Jofree estimates that about 8% too much gas is available on U.S. markets, including about 4.3 bcfd of supply added in 1990.
"Surpluses are killing gas prices, and people are continuing to drill," said Jofree Principal Carol Freedenthal. "It doesn't take a lot of surplus to allow a buyer to go somewhere else if he doesn't like a producer's price."
An increasingly significant factor in that supply picture is production of gas from coal seams and tight sands, which last year rose by 1.4 bcfd. Coal seam gas receives a tax credit of 83-870/MMBTU, Freedenthal noted.
Gas production in the Arkoma basin and Gulf of Mexico in 1990 each climbed by 500 MMcfd.
"A lot of offshore producers sell associated gas at any price they can get, because they're more interested in moving the oil," Freedenthal said.
Higher levels of imports also contributed to the oversupply. Last year, Jofree estimates, U.S. gas imports increased by 1.9 bcfd, lifting annual imports to about 1.5 tcf .
GAS TO COAL COMPETITION
Freedenthal sees great potential for gas to replace coal in power generation markets but believes many projections of growth in that market sector are exaggerated.
For example, during the early 1970s, some analysts predicted that by 1985-90 the U.S. would be consuming 35-40 tcf/year, he said.
Jofree expects electric utility consumption of gas to increase by 1.3 tcf by 1995.
In the present recessionary climate, gas will have to be economic to win a significant share of new power generation markets.
The traditional idea of indexing gas prices to oil prices is a "myth of the gas business," he said.
"Gas is cleaner, and it's cheaper to build a gas fired plant than a coal fired plant," Freedenthal said. "But the coal industry is going to get its share of new facilities, and all existing coal fired plants aren't going to be scrapped because they're dirty.
"Gas producers are going to have to come to grasp with that reality."
EOG disputes that view.
"In our minds, there's no doubt that gas ought to be priced relative to oil," EOG's Hoglund said. "Coal demand is much less flexible, and not many coal fired plants are being built."
Hoglund expects some utilities and independent power companies to consider coal as a possible fuel for new plants. But gas to coal competition won't be based entirely on relative costs per BTU.
"Coal fired plants are more expensive, they need longer lead times to build, and environmental considerations are a problem," he said. "Companies have to weigh that into their thinking about what the price of gas ought to be, compared with coal."
OUTLOOK
EIA's latest energy outlook predicts U.S. gas supplies will be adequate for the foreseeable future.
"The average wellhead price of natural gas is expected to remain fairly level throughout much of the 1990s, given the relative abundance of gas that is available from lower cost sources.
"The stable gas prices projected for most of the coming decade are low in relation to oil prices, and this leads to more demand for natural gas and correspondingly higher production of the fuel."
EIA estimated the wellhead price of natural gas in 2010 at $4.68-5.21/Mcf.
EIA said Lower 48 production should peak after 2000 at 19.5-20.5 tcf/year. It said offshore production will continue to decline at about 3%/year but that will be replaced from additional onshore gas from tight formations and other sources. Alaskan North Slope gas is not expected to come on stream before 2007, Imports from Canada and elsewhere also will increase.
Although EIA said wellhead productive capacity will be adequate through 1991, more wells will be needed in future years.
"After 1991 certain major producing states (Texas, Louisiana, and California) and 17 minor producing states may not be able to meet their historical share of gas demand," said EIA.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.