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Southcentral Alaska running out of cheap gas Utilities already seeing deliverability problems in Cook Inlet; industrial users provide backstop for utility needs in cold weather Kristen Nelson Petroleum News
Natural gas powers electric utilities in Southcentral Alaska, provides heat for residential and commercial customers and is the feedstock for Kenai Peninsula industrial plants which make fertilizer and liquefied natural gas for export, providing taxes and good-paying jobs to the local economy.
The industrial users were created to make use of plentiful gas discovered in the late 1950s and 1960s during the search for oil. A local distribution company, Enstar Natural Gas, was formed to provide natural gas for heating and the electric utilities began to burn gas.
But in the decades since the initial discoveries of the big gas fields — Beluga, Kenai and North Cook Inlet — there have been no additional large gas discoveries.
Until recently there has been little exploration for gas.
That was the basis for the Southcentral Alaska Energy Forum held Sept. 20-21 in Anchorage, organized by the Alaska Oil and Gas Conservation Commission and co-sponsored by the State of Alaska, the Municipality of Anchorage, the Kenai Peninsula Borough and the Matanuska-Susitna Borough. (See part 1 of this story in the Oct. 1 issue of Petroleum News.)
Access, capital and drill-ship all issues Charles Thomas, manager of the Arctic Energy Office for Science Applications International, reviewed SAIC studies on Cook Inlet natural gas. He said issues of concern in finding more gas in the Cook Inlet basin include access (much prospective onshore gas acreage is in the Kenai National Wildlife Refuge), the large capital investment required, the need for a drill-ship to explore offshore areas and the need for both three-dimensional seismic and long-reach drilling.
Thomas said the area probably has conventional gas for “commercial and residential consumer demand until about 2012,” and until 2014-15 “with somewhat limited reserves’ growth.”
SAIC studies have put a price tag of some $4 billion to $6 billion on investment that would be required to develop 50 percent of an estimated 15 trillion cubic feet of natural gas believed to exist in the Cook Inlet basin over the next 20-25 years. That’s not cheap, he said, and it would impact the price of gas.
“Aggressive and successful Cook Inlet exploration has the potential to support basic needs and some of the industrial base for 25 to 30 years,” Thomas said. A spur pipeline from a North Slope gas pipeline to market “would assure supply from the North Slope,” and “LNG imports is an option just like it is in the Lower 48.”
“I don’t think we’re running out of gas — but we are probably running out of cheap gas,” Thomas said.
LNG will impact price of gas Natural gas price forecasts are a factor driving investment, but perhaps not always a dependable factor.
“Authoritative forecasts of gas prices have — in my lifetime anyway — always been wrong. And they’ve been disastrously wrong,” said Arlon Tussing, a professor of economics at the University of Alaska Anchorage’s Institute of Social and Economic Research.
The “big systematic error” in forecasts, such as those by the Energy Information Administration, is “underestimation of the elasticity of supply and the elasticity of demand,” he said. Forecasts also failed “to take into account impending changes in the structure of the market.” In the 1970s there was a failure to recognize “the fundamental change” in the U.S. natural gas industry. It took time for state regulators to acknowledge that gas was no longer a byproduct of oil exploration and production, but that companies would have to look for gas — and costs would have to be assigned to that activity.
In the late 1970s and early 1980s what forecasters missed was how under-utilized the existing supply of Canadian gas was because of requirements by Alberta and the Canadian federal government that there be three decades “of reserves to back up any incremental export.” When those restrictions were removed, “there was a real boom of Canadian gas available to the North American markets at roughly a dollar Canadian per mcf.”
What’s the current blind spot? Tussing said it is a failure “to realize how complete and profound a change may be coming as a result of the globalization of the gas market.”
As the United States imports more liquefied natural gas, international LNG producers and traders will be exposed to the “competitive U.S. pipeline-based market — and it’s going to change both those groups.”
Why does this matter in Southcentral Alaska? Tussing said that once people “overcome their initial shock” he thinks it will be apparent that importing LNG would be “the best and … most secure (and) the most probably successful strategy for the Cook Inlet Railbelt market.” Anchorage, he said, “is less than 200 nautical miles” from shipping routes from Sakhalin, and the Kenai area, site of the existing LNG export terminal, is “probably the only site in North America that almost totally lacks NIMBY type opposition.”
What about a spur line bringing North Slope natural gas to Cook Inlet? Tussing said “the energy and political establishment” is pushing the spur line, “regardless of a number of problems” including the cost of getting ANS gas to Cook Inlet and the deterrent such a line would be to more exploration in Cook Inlet. Who would explore for and develop new fields in the inlet if there was the potential for ANS gas, he asked.
The utility view: Enstar The gas and electric utilities have much more than an academic interest in natural gas supplies: they need it to meet commitments to customers on a daily basis.
Dan Dieckgraeff, manager of regulatory and gas supply for Enstar Natural Gas Co., Southcentral Alaska’s local distribution company, said the area is already seeing a deliverability problem because of declining gas supplies.
“Last year was the first year that everyone didn’t get what they wanted in cold weather when everything was operating normally.”
There have been system disruptions in the past, a compressor down or a well freezing up, but last winter “we didn’t have enough gas for everybody when it got cold, (with) everything operating normally we didn’t have enough gas,” Dieckgraeff said. “That situation will be magnified this winter.”
Looking at reserves by field, he noted that in addition to gas under production there are “undeveloped and underdeveloped fields” where “the producers have to spend a heck of a lot more money to get those reserves online and in the pipe to serve us and the electric utilities and the industrial customers.”
Enstar isn’t the only one supplying gas locally. While it “serves most of the residential and commercial load,” about one-third of “the traditional utility load has been picked up by direct marketing” by producers and a third-party marketer over the past 10 years, he said. If gas is developed from known reserves Enstar expects problems about 2017; “if that gas under development doesn’t show up like people plan, the problem occurs a lot sooner.”
Agrium, which needs a low gas price to compete in the international fertilizer market, is “the canary in the mine”: they were the first ones to have problems with gas supply, he said. Agrium has shut down half of its operation and runs during the winter based on the availability of gas.
But it isn’t the only one with current problems, Dieckgraeff said. Those who have been buying gas from parties other than Enstar have been purchasing on a short-term basis, “and we’re already seeing those customers having problems getting gas and trying to return to the supplies that Enstar has had under contract.” This is about to be before the Regulatory Commission of Alaska “and it is a grave issue,” he said. “Long-term supplies for utilities and the utility customers are essential. Unfortunately not everyone has them at this point in time.” (See Fairbanks Natural Gas story in this issue.)
ML&P a one-third Beluga owner The local electric utilities are also running on natural gas and want to know what will be available in the future as they look to upgrade gas-burning generators.
Anchorage’s Municipal Light and Power is both a natural gas user and a natural gas owner of one-third of the gas at the Beluga field.
ML&P originally thought the 200-plus billion cubic feet of natural gas it purchased from Shell at Beluga in 1996 would last to 2026. Now, said Jim Posey, the utility’s general manager, it looks like that supply will only last until 2018-20, so the utility is “very interested in what we’re going to do starting in say 2017, 2018 to 2020.” ML&P has to have additional supplies of gas, he said, because the utility is “looking at making some rather expensive investments in new generation,” and that would be gas-fired turbines.
ML&P is working over one of its power generating units now and early next year will install a “race-horse type turbine that we can spin up and spin down once a day to take our peak shaving requirements.”
These are investments in increments of $25 million to $50 million, with in excess of $200 million invested by 2011 for new heavy-load generation “that will take us out for another 20 years.”
ML&P is using 13 bcf of gas a year and with the upgrades it can cut its usage to 9.5 bcf because the new equipment is more efficient. ML&P is also working with Enstar, Chugach Electric, Golden Valley and Homer looking at how power will be supplied in the future, including wind power, additional gas generation “and hopefully … getting Healy Clean Coal back online.”
And they’re counting on a spur line bringing North Slope gas by 2017 or 2018, Posey said.
CEA 85% dependent on natural gas John Cooley, Chugach Electric Association director of system control, said 85 percent of CEA’s power is from gas-fired generation and 15 percent from hydroelectric. CEA buys gas from all three Beluga producers, including ML&P, under “requirement” type contracts: in exchange for producing all its power from gas, the producers agreed to provide all the gas CEA needs. Cooley said CEA has about 122 bcf remaining under contract and believes that will last to about 2011.
The current contracts were signed in 1990 and included a reservation of 120 bcf of gas for CEA’s future use under terms to be determined. “We’re at that time, trying to figure out if we can come up with the right terms to secure that 120 bcf,” Cooley said. CEA is also talking with Marathon about additional volumes beyond an existing agreement. Like ML&P, CEA is looking at more efficient gas generation, “probably within the next three years” and is investigating wind power.
Cooley said probably the biggest problem with wind power is that the towers have to be out of town and so you have to pay for transmission lines. Fire Island is a prime candidate, and a transmission line from Fire Island “is a significant cost,” he said.
CEA is also looking at new hydro resources, but that would also be expensive. Cooley said Bradley Lake was built for about $350 million; new hydro could cost twice as much. The initial capital cost for coal generation would be very high.
CEA thinks gas will continue to be available in Cook Inlet, through new discoveries, LNG or possibly from a spur line. “We’re still heavily gas dependent and we haven’t found a way to economically choose a different path,” Cooley said.
Industrial users backstop residential users Utilities aren’t just dependent on buying enough gas, but also on being able to get additional gas during the coldest days of winter, something provided by the industrial gas users.
Will Nebesky, a commercial analyst with the Alaska Department of Natural Resources Division of Oil and Gas, said the division estimates there are about 1.6 tcf of proven developed reserves remaining in the Cook Inlet basin, about eight years at the current consumption rate of about 200-plus bcf a year.
The reserves-to-production ratio in the Cook Inlet basin has been dropping steadily, Nebesky said: it was 24 years in 1980, 18 years in 1990, 12 years in 2000 and is now eight years.
The main industrial users of natural gas are the Nikiski LNG and fertilizer plants. Agrium, which operates the fertilizer plant, has recently had its gas supply extended through October 2007, Nebesky said, but will only operate at 75 percent of its current 50 percent of capacity. There is an export license renewal required for the LNG plant in 2009.
If those industrial plants close down, “it implies a pretty substantial structural change in the composition of the industry sector in Southcentral Alaska,” he said. And it would also impact residential users because “industrial users backstop residential users.”
In addition to the loss of deliverability backstop service if Cook Inlet lost the industrial natural gas users, it would also impact exploration: “If I were an explorer I’d have some comfort in knowing that there was one or more large industrial users that could take all the gas I could possibly deliver if I happened to stumble on a moderate or even a major discovery,” he said.
And because the industrial users represent 64 percent of the throughput in the system they help share system costs, costs that will become more concentrated among other users “in the event that the industrials exit,” Nebesky said.
Loss of industrial users could also hurt a spur line, where they would play “an important role in the base-load throughput,” having an important implication “in terms of how the economics on a unit-cost basis will pencil out for the spur line.”
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