Colleen Starring, president of Enstar Natural Gas Co., is on the spot this winter.
Her utility supplies natural gas to virtually all commercial buildings and most homes across Southcentral Alaska.
Starring’s problem is ensuring there’s enough gas to supply her customers. Enstar is short 4.2 billion cubic feet of about 33 billion cubic feet it needs to keep the heat on.
This is the second year Enstar has faced a deficit in gas supplies at the start of winter, but last year the gap was only about a billion cubic feet and most of that was made up through a short-term auction system the utility set up for producers to sell small quantities of surplus gas they may have.
The 4.2 billion cubic foot gap this year, however, is too big to make up through the auction system.
Things may yet work out.
A Consent Decree just negotiated by the state with Hilcorp Energy on its pending acquisition of Marathon Oil Co.’s Cook Inlet assets could clear the way toward sales of more gas from the Marathon fields to the region’s utilities.
Alternatively, if ConocoPhillips decides not to ship more cargos of liquefied natural gas from its Kenai LNG plant in 2013, and decides not to renew an export license for the plant that expires next March, the company could make more gas available.
Hilcorp and ConocoPhillips are already major gas suppliers to the region’s utilities.
However, at the root of the problem is declining production from gas fields Southcentral Alaska. For example, the Beluga gas field, long a main supplier of gas to the utilities, is declining at rates of 17 percent to 19 percent per year, said Jim Posey, general manager of Anchorage’s city-owned Municipal Light and Power.
ML&P owns one third of the Beluga field.
By 2014 or 2015, production from fields in the region will fall below annual demand, requiring that gas be imported either as LNG or compressed natural gas. Explorers are busy in the area but it’s considered unlikely that enough new gas can be found and put into production quick enough, said Tom Walsh, managing partner of Petrotechnical Resources of Alaska, or PRA, a consulting firm hired by the utilities to study the gas situation.
On the positive side, there’s a new gas storage facility operating on the Kenai Peninsula that now has gas in storage for peak cold weather demand this winter. The first withdrawals of gas from the Cook Inlet Natural Gas Storage Alaska project have already been made, Enstar spokesman John Sims said.
Beluga budget dispute
But another twist for now, however, is a disagreement among the Beluga field owners about funding a $50 million budget for servicing and other work on producing wells in the field.
ConocoPhillips, Hilcorp and ML&P each own one-third of the Beluga field with ConocoPhillips as the field operator.
Posey, of ML&P, said Hilcorp has declined to fund its full one-third share of the budget.
Hilcorp spokeswoman Lori Nelson confirmed this.
“We certainly recognize the need for enhanced production. Hilcorp did reject the $50 million proposed budget,” Nelson said. “We have a long and successful record with this kind of work and believe it can be done for a smaller price tag.”
Posey doesn’t buy that.
“When they decide to pull in their horns (on spending) it means less gas supply,” he said.
He said he’ll take up the matter with his boss, Anchorage Mayor Dan Sullivan, and the issue may also be appealed to Houston, where Hilcorp and ConocoPhillips are headquartered, Posey said.
Walsh, of PRA, is fairly pessimistic, however.
In terms of the supply gaps, Walsh told the Regulatory Commission of Alaska in an Oct. 24 briefing that, “we don’t believe there is a lot of uncontracted gas (reserves) out there. There’s just not enough drilling. There’s not enough new gas coming into the system,”
Cook Inlet producers’ own information on the extent of their reserves is the best data there is, and while some of this must be shared with the state Division of Oil and Gas, state officials are required to keep it confidential.
Information, supply gaps remain
The lack of having this information available to the utilities, and the public, is a sore point with Chugach Electric CEO Brad Evans, who has pushed unsuccessfully for the state to do a regional Cook Inlet resource plan putting all information into one place.
Walsh said the companies will drill to meet contract commitments, and the fact that there are large gaps in contracted supplies for 2013 and the years following probably means the companies don’t believe there is a lot of untapped gas, or that gas that is there can be profitably produced at least at present prices.
PRA has estimated that the number of new production wells being drilled would have to double for new reserve additions to make up for the annual depletion of the fields, and the increased drilling isn’t happening.
Also, some of the new wells being drilled are not successful. Of three production wells drilled in the Beluga field in 2012 one is not producing as expected.
There is a great deal of exploration planned for Cook Inlet, and although most of it is aimed at oil, some gas will inevitably be found too.
“It’s great to see this, and it’s all due to the state exploration incentives,” Walsh said. “There has been virtually no exploration in Cook Inlet in 40 to 50 years.”
But few, if any, of the explorers will be able to develop their discoveries in time to meet the utilities’ shortfall.
“Their timeline will not resolve this issue,” he said.
As for the needed work in the existing fields, Walsh said, “we are not seeing the kind of activity we need, and based on recent history we don’t expect it to occur.”
Bob Pickett, one of the commissioners of the state regulatory commission, thinks the situation is precarious.
“We’re in a conundrum. We’ve moving out of an era with the ‘legacy’ (older) fields where there was a lot of gas and prices were low. Today Cook Inlet has the nation’s highest gas prices. Now, with discussions of gas imports, we could see those prices double,” Pickett said.
The possibilities of mechanical and geologic failures must also be considered, Walsh said. Mechanical failures could include the malfunctioning of gas field compressors, as has happened, which would impair the flow of gas to utilities — not good if it happens during cold weather — or there could be geologic failure, such as disappointments in drilling or encroachment of water into the gas producing wells.
Enstar’s Starring said her gas utility can’t switch fuels, unlike the electric utilities who can do it to some extent. Enstar’s customers also can’t conserve on heating enough to make a significant difference.
“There are only so many sweaters you can put on,” she said. “Our only option is to go to curtailment (of supply). We have a curtailment plan and we are awaiting an opportunity to present this,” to the regulatory commission.
Starring said a new system Enstar initiated to allow producers to bid small quantities of gas they may have to meet Enstar’s short-term peak requirements worked well last winter.
Enstar spokesman John Sims said the amounts of gas bid under this system for 2012 were about 700 million cubic feet. While this mechanism works well to meet short-term needs during periods of peak demand it will not supply large volumes of gas.
“The gas simply isn’t available,” Sims said.
Chugach Electric Association is in better shape than Enstar in that it has other alternatives than natural gas, such as hydro for a long-term base, wind power as a supplement and, in an emergency, bringing power down from Fairbanks over the Intertie.
Chugach now uses about 25 billion cubic feet per year of gas, and after Homer Electric Association and Matanuska Electric Association stop buying wholesale power from Chugach, the utility’s annual need for gas will drop to about 9.5 billion cubic feet per year, Lee Thibert, Chugach’s senior vice president for planning, told the regulatory commission.
More efficient gas turbines and “combined cycle” (using waste heat) facilities at the new Southcentral Power Plant now under construction in south Anchorage will result in an expected savings of 3 billion cubic feet of gas yearly.
Wind power will help, too. The new Fire Island wind project will allow Chugach to reduce its annual gas need to just under one-half a billion cubic feet. Additional hydro power in the regional grid is also important.
Hydro power from Bradley Lake near Homer is now the least expensive source of power along the Railbelt and additions to its capacity are planned.
Consumer conservation is already playing a role: Consumers are using new, more efficient appliances and lighting systems and the savings in electrical use have translated to an estimated 700,000 thousand cubic feet, or mcf, of gas saved over the last 10 years, a trend which is expected to continue.
Despite these developments, Chugach faces its own gas supply shortfall of about 3 billion cubic feet in 2015 and 6 billion cubic feet in 2016, Thibert told the RCA.
Matanuska Electric Association will be generating its own electricity in 2015 at a new power plant being built at Eklutna, north of Anchorage, MEA’s general manager, Joe Griffith, told the regulatory commission.
The project is under construction now and is ahead of schedule and under budget so far, Griffth said. The plant is to be in operation in January 2015.
MEA has yet to contract for a long-term supply of gas, however, although talks are under way with producers, Griffith said. The plant will need about 5 to 6 billion cubic feet of gas per year when when operating, he said.
Anchorage’s city-owned Municipal Light and Power has agreed to make gas available initially to test the Wartsila engines in the plant, but this supply is only temporary, Griffith said.
However, the Wartsila engines do have dual-fuel capabilities, so MEA could also generate power with diesel if need be, Griffith said. The engines can make the transition seamlessly, he said.
A four-day supply of diesel will be kept on site, and additional fuel can be efficiently brought in by rail if needed. MEA is also investigating the possibility that a propane-air mixture can also be used as fuel, giving the co-op another option for a backup, Griffith said.
Some improvements in the region’s pipeline network are also needed to move more natural gas efficiently to the northern end of the system, Griffith told the RCA. The conversion of two cross-Cook Inlet pipelines, the Cook Inlet Gas Gathering System, or CIGGS, to a two-way flow instead of one-way will ease this, but it may not be the total answer, Griffith said.
Griffith said any discovery of new gas will take time to bring into production. Griffith said his concern is for the next two to three years.
“Getting through the next two to three years will require us to do something heroic,” he told the commission.
Anchorage’s Municipal Light and Power now relies mainly on its one-third share of gas production from the Beluga field for its supply of gas, although ML&P also shares in hydro power as do other regional electric utilities.
However, gas production from Beluga is declining and by 2015 ML&P will need to purchase gas from other sources, its general manager, Jim Posey, told the regulatory commission.
ML&P will need about 3.6 billion cubic feet in 2015 and about 5 billion cubic feet in 2016, Posey said. After 2016 its requirement for new gas may decrease because of the efficiency of the new power plant being built with Chugach Electric, and other improvements in the ML&P system.
Posey said there can be some benefits from energy conservation but there are limits to this for many ML&P customers, who are mainly owners of large commercial buildings in the downtown core of Anchorage.
Still, Posey said ML&P has seen 40 percent reductions of electricity use by homeowners through conservation, and he singled out one large Anchorage building, the Performing Arts Center, which achieved a 20 percent reduction several years ago after a series of efficiency measures.