Rick Hagar
Gulf Coast News Editor
The U.S. gas industry is assessing the lessons it learned last December.
That's when the industry came within days of severe gas shortages because of widespread cold weather that drove up demand and froze off substantial production volumes.
The blast of arctic air sent temperatures plunging in much of the country, particularly during a Dec. 22-25 cold snap.
Executives say that several lessons can be learned, but the most important may be that the industry's health still depends very much on the weather.
Transcontinental Gas Pipe Line Corp. (TGPL), hardest hit of the pipelines, lost 60% of its normal supply during the 4 day period due to freeze offs, leaving customers in New York, New Jersey, North Carolina, and South Carolina to scramble for alternate supplies.
"Storage is what held it together," said David T. Ellis, vice-president of operating services at Tenneco Gas. TGPL has very little system storage.
But even lines with sizable gas storage, which had been greatly expanded since the mid-1970s, saw volumes drawn down to critically low levels.
For example, only about 48 hr of maximum deliverability remained at Panhandle Eastern Corp.'s storage facilities when full production was restored in supply regions.
Planners had counted on the ability of some customers to switch to alternate fuels to meet human comfort needs during such emergencies. However, available fuel oil and propane supplies also were short (OGJ, Jan. 1, p. 28).
The crisis passed, however, because the cold was followed by a warm January and February.
Executives say the cold snap did not provide a firm indication of U.S. productive capacity because too many gas wells froze up during the peak demand period. U.S. productive capacity has not been adequately tested by a prolonged cold snap for more than a decade.
However, the December cold snap did provide a test of the quality of post-Order 436 deliverability.
"The industry rose up and met a tough challenge, although it was close," said George L. Mazanec, group vice-president at Panhandle Eastern.
Producers saw a sharp swing in spot gas prices to an average $1.96/MMBTU in December and $2.34 in January from an autumn low of $1.41 last September. Last month the average spot price fell to $1.85.
But the low spot price is not expected to last. Despite storage refill efforts during January and February, several pipelines and distributors plan a normal refill purchasing schedule later this year, which should firm up prices during the summer.
RECORD DEMAND
A prolonged blast of arctic air shattered low temperature records in more than 125 cities from the Rocky Mountains to the East Coast during Dec. 22-25.
Panhandle's Mazanec said December in Boston was the coldest since 1921. Then January, he said, was Boston's warmest in 100 years. February in Boston also was more than 30% warmer than normal.
Mendal Yoho, vice-president of CNG Transmission Corp.'s system gas operations, said, "It was really more than just a record cold December in Upstate New York.
"We had as much cold weather in a 6 week period from the end of November as we would have anticipated in an entire design winter season on our system."
He said CNG's system was fully utilized. The peak sendout for CNG was 7.5 bcfd, compared with a previous peak sendout of less than 7 bcfd.
Yoho said, "There was almost a solid week after Dec. 20 when every day's sendout was almost as big or bigger than the previous system peak."
Larry F. O'Byrne, Natural Gas Pipeline Co. of America's vice-president of marketing, said NGPL's December delivery volumes were 15% higher in 1989 than in the same month in 1988. And NGPL's draw on storage in December was 63% higher than in the same month in 1988.
PRODUCTION SHUTDOWNS
Gas production was frozen off in much of Kansas, Oklahoma, Texas, Arkansas, and Louisiana.
ARCO Oil & Gas Co., which normally produces 1.8 bcfd, lost 400-500 MMcfd for most of Dec. 22-25 due mainly to well freeze offs, said W. R. Harper Jr., president of ARCO Gas. About 75% of the lost volume was in the Gulf of Mexico.
High winds, meanwhile, prevented crews from getting offshore to most unmanned platforms during the cold snap to service wells.
Anadarko Petroleum Corp. Chairman Robert J. Allison Jr. said his company had some well freeze offs in Hugoton field of western Kansas, but the problem was minor and production was quickly restored.
Conoco Inc.'s deliverability dropped well below 30% of normal.
Ronald E. Thompson, Conoco's general manager of gas, said the freezing weather had a domino effect on off shore operations.
When Conoco's 950 MMcfd Grand Chenier gas processing plant was knocked out by the freeze in Cameron Parish, La., offshore production facilities upstream of the plant also were choked off.
For Conoco and other producers, most of the problems occurred in the gulf. Conoco gas processing plants in West Texas and Oklahoma operated at about 75-80% of capacity partly because wells onshore could be serviced easier than those offshore.
However, Tex/Con Oil & Gas Co., which has substantial production and operates two gathering systems in Oklahoma's Anadarko basin, saw as much as 40% of its supply frozen off.
"Hydrates are what kill you," said Victor T. Linck, Tex/Con's vice-president of gas supply and marketing. "There are things to do to prevent formation of hydrates, but they are not common practices in Oklahoma."
A major problem the company faced was determining which wells were frozen up. Other producers hooked up to the system at first denied their wells were frozen. Only when meter charts were read after the crisis could anyone determine for certain which wells were frozen.
Another problem for producers was that the cold weather hit when many field people were away for Christmas holidays.
PIPELINES WITHOUT SUPPLY
The well freeze ups occurred at about the same time pipelines were called on to deliver record volumes of gas.
TGPL lost 2 bcfd and Texas Gas Transmission Corp. 1 bcfd, said Transco Gas Co. Pres. David F. Mackie. The two systems obtain about 80% of their supply from the Gulf of Mexico, which was hit hard by the freeze.
Texas Gas did not curtail firm services. But average firm service curtailment on TGPL was about 22% Dec. 22-25, with an extreme of about 50% at one time, said Mackie.
Curtailments of firm service averaged 15% during the 4 day period on the Texas Eastern Gas Pipeline Co. system due to supply freeze ups, said Mazanec.
For gas consumers, said Conoco's Thompson, the events of that period were confusing.
Conoco manages supply purchases and transportation for E.I. du Pont de Nemours & Co.'s chemical plants. Each plant had a different story. Some had firm transportation curtailed while others could get all the interruptible transportation they wanted.
"Some that were able to get gas to the city gate had it confiscated by the local distribution company," said Thompson.
Tennessee Gas Pipeline did not curtail firm service.
NGPL did not curtail firm sales and transportation and kept on most of its interruptible sales and transportation. Interruptible transportation was knocked off mostly when the shipper could not get gas to the NGPL receipt point.
Enron Corp.'s systems had very few operational problems, although 2 bcfd of supply was lost to freeze offs. All firm loads and most interruptible shipments-except where lines were full-were kept on, said Ronald J. Burns, president of Enron Gas Pipeline Group.
Burns said a peak of 14 bcfd moved on Enron's systems during the cold snap.
Columbia Gas System Inc., which lost more than 1 bcfd of flowing gas from the southwest producing region, maintained firm services but halted interruptible services throughout the system for the 4 day cold snap.
Interruptible service was restored Dec. 26 in the system's western operating area and in mid-January in the eastern operating area.
CNG, which also lost 1 bcf of supply due to well freeze offs, had no firm service curtailments but halted interruptible sales in early December and asked customers to voluntarily halt interruptible transportation.
Coastal Corp.'s systems met all firm commitments but cut some interruptible services where supply was tight.
TAKING PRECAUTIONS
A key to Tennessee's success in maintaining firm service was the effort made before the arrival of cold weather, said Tenneco's Ellis.
The pipeline began watching the market closely when gas demand in its service area rose strongly beginning with the second week of December. By Dec. 15, the company's gas controllers reported concern with load characteristics, such as pressures along certain segments and volumes of supply moving across various receipt and delivery points.
The 7 day weather forecast that week called for severe cold temperatures in market regions and the supply area. The pipeline took more steps Dec. 18 to prepare, such as increasing line pack.
On Dec. 19, Tennessee announced that it would halt all interruptible transportation services upstream of its Winchester, Ky., compressor station the following day. At the time, said Byron R. Kelley, Tenneco's vice-president of marketing and supply services, Tennessee thought it would not have to take any other action.
But on Dec. 20, its northeast marketing area moved into a state of emergency as record low temperatures resulted in record high demand. The pipeline halted all interruptible transportation services.
Then the cold weather moved into the supply area Dec. 22, freezing off production. Tennessee lost 1 bcfd of supply.
The first signs of relief came the morning of Dec. 25.
"Pressure on the system had dropped to the lowest level most people here remember," Ellis said. "Only 24 hr more and we would have had problems."
SAVED BY STORAGE
Industry executives say gas storage, greatly expanded after supply curtailments in the mid-1970s, is the only thing that prevented widespread curtailments for human comfort needs Dec. 2225.
"We truly learned the value of storage," said Clark Smith, president of Coastal Gas Marketing Co.
Ellis said, "We drew down storage reservoirs to dangerously low levels."
Tennessee kept interruptible services off its system until Jan. 10 so it and its customers could refill storage. The company today has refilled storage to normal levels for this time of the year.
Since the mid-1970s, Texas Eastern has added 800-900 MMcfd of seasonal deliverability at its market area storage facilities for a total deliverability of 3 bcfd. During the cold snap, Texas Eastern was delivering 5 bcfd.
The company, meanwhile, has increased its transportation capacity by 1.1 bcfd since 1985 and plans an additional 150 MMcfd expansion in time for the 1990-91 winter.
When supplies from the gulf were restored, Mazanec said, Texas Eastern's storage levels were so low that deliveries, even at the curtailed volume, could be maintained for only another 48 hr.
"If we had a normal January, there would have been severe deliverability problems," he said.
During the cold snap, 65% of Columbia's 6.6 bcfd deliveries came out of storage, said Larry Robinson, Columbia's senior vice-president of planning, storage, engineering, and gas control. As a result, Columbia's storage volume by Jan. 1 was about 60 bcf under schedule.
Enron's systems entered December with 105 bcf of storage. The lines pulled on storage continuously for a 12 day period in December, bringing it down to 92 bcf.
CNG went into the season with about 620 bcf in total storage inventory, a 10 year high for the company. The average winter volume during the 1980s was about 605 bcf.
Due to some contractual obligations, CNG maintains a colder than normal weather reserve in storage, equal to about 5% of normal capacity. By the end of last December, however, the colder than normal reserve was depleted.
By the middle of February, however, storage had been refilled to normal levels for that time of the year due to the warm temperatures. Line pack also helped.
Algonquin Gas Transmission Co., which serves New England, obtains about 90% of its supply from Texas Eastern. When Texas Eastern curtailed supply, Algonquin used storage to maintain deliveries.
Algonquin packed the system ahead of time to make sure it had enough supply to meet demand.
Mackie said TGPL delivered 2 bcf during the 4 day cold snap out of line pack.
WARM WEATHER FOLLOWS
Many pipeline systems were able to refill storage this January and February because demand was down due to warmer weather.
O'Byrne said the weather in NGPL's market area was 41% warmer than normal in January.
At Panhandle, system storage at mid-February was at normal volumes for that time of year. The systems plan a normal storage refill purchasing program this summer.
However, said Mazanec, some of the company's customers were not able to refill their storage to normal levels, so he expects an aggressive refill purchasing program from them during the summer.
Burns said Enron likes to end February with 83-84 bcf in storage at its Bammel site near Houston. However, volume was expected to be 97 bcf this year because of the warm January and February.
Burns said Enron plans to refill Bammel to about the 120 bcf range this summer, compared with about 97 bcf at the end of February and 105 bcf at the start of the 1989-90 winter.
Columbia by mid-February was able to refill storage to normal levels for that time of year. The company plans a normal refill program this year.
Transco's systems plan a lower than normal refill purchasing program because storage was mostly refilled in January and February.
NGPL also plans a small refill program because of the large volumes it purchased following the December cold snap.
CNG plans to refill storage to the high level it had prior to the 1989-90 winter.
Meanwhile, California utilities have begun their storage refill programs. Strong gas demand is expected in California during the summer cooling season as more gas is used due to environmental concerns.
BATTLES AMONG THE PLAYERS
Some producers are angry at the way their pipeline transporter handled the December crisis.
Tex/Con's Linck, for example, said pipelines worked the crisis to their advantage.
"They sought not to stabilize systems for the benefit of shippers but to get back into the merchant function," he said.
Anadarko's Allison said legislation is needed to force pipelines into a common carrier status similar to product pipelines. Dealing with the current set of transportation regulations is the biggest obstacle to selling gas today, he said.
For example, Anadarko had a major sales contract with an end user in the Midwest. During Dec. 22-25, however, the pipeline transporter called one morning to say transportation services were being backed out because the system was full of system gas-gas purchased by the pipeline for resale.
But that afternoon, said Allison, the pipeline's marketing department called, desperately seeking gas so it could keep its system full.
Enron's Burns said what happened to Anadarko is a signal that the pipeline lost control of its system during the cold snap.
"We don't think it is good policy to knock off interruptible supplies if the line isn't full," he said. "You can't ram service down a shipper's throat and then take it away and expect him to be happy about it."
Shippers will look for transporters that provide better service, assuming the option is available.
But, said Panhandle Eastern's Mazanec, the Natural Gas Act gives pipelines a service obligation to perform under their pre-Order 436 contracts with customers even if customers have been buying cheaper spot supplies. During a crisis, pipelines must make tough decisions to make sure such system gas is available for human comfort needs.
For producers and nonpipeline marketers to have firm access to the system during crises, they must first assume some of the service obligation responsibility, Mazanec said.
At Tennessee, the service obligation is for 3 bcfd of system gas, which means Tennessee must always have 3 bcfd on call in case its pre-Order 436 customers want it. Last July the pipeline could sell only 150 MMcfd of the system gas because end users chose instead to buy cheaper spot gas and use Tennessee's system only for transportation services.
"It's time for industry to accept responsibilities on the other side of the transaction," said Ellis.
Meanwhile, United Gas Pipe Line Co. is charging as much as $12.79/Mcf for gas taken by noncontract consumers attached to the system after being warned their third party shippers had failed to deliver the gas to the pipeline. The charge represents the commodity cost of gas, cost of transportation service, and a penalty outlined in United's posted transportation tariffs.
United, which said the $12.79/Mcf is the same rate that would be charged to jurisdictional customers with penalties, said the gas volumes involved are small.
Panhandle Eastern's three systems also are charging a penalty. Mazanec said the penalty would amount to about $5/Mcf.
U.S. PRODUCTIVE CAPACITY
Judging by the first part of December, when gas demand was strong, deliverability from the supply areas was as expected, said Kelley.
Mazanec said Panhandle Eastern's systems are not yet encountering problems with producers unable to deliver volumes indicated by deliverability tests.
The American Gas Association says the U.S. surplus of gas deliverability is gone (OGJ, Jan. 15, p. 22).
According to AGA, there is only 316 bcf of unused productive capacity available in the U.S. this year. That's down sharply from 1.234 tcf last year and the record 4.572 tcf of 1983.
One thing different about today's market is the production cushion afforded by pre-Order 436 contracts, said Mackie.
Under old style contracts, a 65-75% take or pay obligation resulted in a 25-35% cushion of deliverability that could be called upon in times of peak demand.
"That no longer is true," said Mackie. "Producers now flow their gas in the 90% ranges. We no longer have the margin of deliverability built into the system."
LESSONS TO BE LEARNED
Virtually all players in the U.S. gas market are involved in a review of their operations during this winter heating season.
ARCO's Harper said the flaws in open access were magnified, but he believes industry responded well.
The flaws he saw included methods of allocating firm transportation during curtailment, managing storage, allocating volumes on a real time basis on receipt and delivery points, and poor communications between industry players.
Several said more should be done to define the role of each player in the new open access regulatory structure.
In addition, more gas storage facilities are needed in market areas, pipeline transportation bottlenecks need to be eliminated, gas controllers need more real time information from receipt and delivery points, and pipelines tied into Gulf of Mexico production need connection with other supply regions.
Producers learned that, despite conventional engineering wisdom, it occasionally gets cold in Texas, Louisiana, and the gulf.
"All of us wish we had more control over the transportation system," said Thompson.
Mackie said getting real time data is important.
For example, during the first day of the crisis TGPL was told by producers that about 350 MMcfd of their deliverability was shut in.
"We set up the system and delivered gas to all the nominated parties accordingly," he said. "The next day we found our line pack drawn down 540 MMcfd from the day before."
With a much more diverse supplier and customer base, pipelines have learned that they must have data at least every 24 hr to adequately balance the gas crossing receipt and delivery points.
"We have put together a task force of customers, marketers, and producers to develop and implement an information program," said Mackie.
"We have the basic information systems in place. It's a question of timing and accurate receipt of the data."
WHAT TO EXPECT
Several industry executives believe the December crisis will cause end users to emphasize supply security over low cost in upcoming purchasing programs.
Yoho said CNG, because of the December experience, may be more inclined to purchase from producers special services, such as priority delivery next winter and winterized production facilities.
"Reliability considerations will be more on everyone's mind," he said. "I don't think producers are going to get a big windfall. The weather warmed up too soon. But I expect buyers who learned something about their suppliers' reliability may be willing to pay a little more next year."
Tenneco's Kelley believes spot gas prices this year will roughly track 1989 prices, although he expects 1990 prices to average 5-10/Mcf more.
Thompson said several end users will start asking themselves why they are paying a premium for firm transportation when it is not available in a tight market. It is for such circumstances that end users buy firm services, he said.
CNG plans to develop more seasonal deliverability storage in its market area.
As to clearing up the industry's regulatory mess, Mazanec is putting his hopes on the U.S. Supreme Court, which is reviewing a couple of lower court decisions against different Federal Energy Regulatory Commission open access transportation orders. He does not expect any legislative remedy.
It took severe supply curtailments in the mid-1970s to produce the Natural Gas Policy Act in 1978, he said. It will take a similar crisis to move Congress today.
Unfortunately, the economic plight of producers is not seen as a crisis by Congress, he said.
Producers are likely to shut in discretionary production again this year when prices drop too low.
Conoco, for example, has already shut in about 25% of its offshore deliverability because of price.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.
