Through to 2015?New Cook Inlet gas producers help stretch supplies for another few years Alan Bailey Petroleum News
With temperatures in Southcentral Alaska dropping as winter approaches, local gas and power utilities are gearing up for another nail biting few months, trying to ensure that severe cold or an equipment malfunction will not trigger power outages as utility gas supplies from the Cook Inlet basin tighten. And on Oct. 21 four utilities — Enstar Natural Gas Co., Chugach Electric Association, Municipal Light & Power and Matanuska Electric Association — provided the Anchorage Mayor’s Energy Task Force with overview of the current gas supply status.
In summary, the utilities said that the storage of summer produced gas for use in the winter has become a critical factor in the battle to ensure the availability of sufficient gas to meet peak winter demand; new Cook Inlet gas producers are starting to have an impact in the gas supply situation; and utilities will probably have enough gas to meet total annual demand until 2015, from which point the import of liquefied natural gas may be necessary to bolster local gas supplies.
More gas needed James Posey, ML&P general manager, told the task force that recent Cook Inlet gas discoveries have not been sufficient to avert the LNG import option. Without new discoveries leading to 50 million to 80 million cubic feet per day of production “we’re nowhere out of this box,” he said.
And Colleen Starring, president of Enstar, told the task force that, with the utilities still determining the cost parameters for LNG imports, it is too early to comment on the specifics of import options. Posey said that the utilities anticipated having more information to impart some time in 2012.
Starring said that Enstar continues to negotiate long-term gas supply contracts with local gas producers. However, starting in January 2011 the company has had to tender for daily volumes of “bid gas” from qualified producers, to supplement gas obtained under the terms of contracts for guaranteed gas supplies. The future gas supply situation depends on discoveries by companies currently exploring in Cook Inlet — there has been significant investment in this exploration in the past couple of years, Starring said.
New contracts with new producers are already appearing in Enstar’s contract list for future supplies, she said.
Growing gap Enstar sees a significant and growing gap between its current contracted gas supplies and gas demand from 2013 onwards. However, the company hopes that new Cook Inlet gas coming on line will delay any need to import LNG until 2015, Starring said. Enstar is also keeping an eye on gas pipeline options for obtaining gas from the North Slope, she said.
Meantime, Cook Inlet Natural Gas Storage Alaska, Enstar’s sister company, is forging ahead with its new gas storage facility on the south side of Kenai, on the Kenai Peninsula. CINGSA plans to start accepting gas for storage in the spring of 2012, to support the delivery of utility gas in the winter of 2012-13. At the CINGSA site the buildings have been constructed, one well has been completed, a second well is ahead of schedule and the drilling of a third well will start soon, Starring said.
At the beginning of 2011 Enstar moved to a quarterly gas cost adjustment for its customers, thus enabling the company to pass on the higher cost of winter gas, Starring said. The Enstar gas cost adjustment ranged from $7.12 per thousand cubic feet in the first quarter of 2011 to $5.74 in the third quarter.
“We’re trying to send the right price signals to customers,” Starring said.
Bid gas Enstar now has seven companies signed up to potentially supply bid gas during the coming winter, with the company expecting bid gas to account for about 3 percent of its overall supplies. Buccaneer Energy, one of the companies that have a contract for bid gas, also has a contract to supply gas to Enstar for storage in the CINGSA facility, starting in the spring, Starring said.
It is not possible to say how much bid gas might be available to Enstar on any particular day, but on one especially cold day during the last winter the company was able to obtain all of the bid gas that it needed, Starring said.
Phil Steyer, CEA’s director of government relations and corporate communications, said that CEA uses natural gas as a fuel to meet 90 percent of its power generation needs. The company has gas supply contracts to meet its needs through 2013, possibly through 2014, with increasing unmet needs thereafter, he said. Meantime, the tightening gas supply situation has led to increasing complexity in the delivery of gas to power plants, although modifications to the pipeline infrastructure will improve the flexibility with which gas can be transported. And starting in 2012 the company will be storing some of its winter gas supplies in CINGSA’s new facility. Along with other Southcentral utilities, CEA is considering the option of importing LNG to fill gaps in future gas supplies.
CEA is working with ML&P to build a jointly owned, state-of-the-art, combined cycle gas-fired power plant in Anchorage. That plant is scheduled to go into operation by Dec. 1, 2012, and its use will greatly increase the efficiency of the two utilities’ power generation, thus reducing their gas demand from the beginning of 2013, Steyer said. And CEA’s overall retail power load has remained fairly flat, with customers power usage actually dropping in recent years, thanks primarily to improved efficiency in people’s use of energy.
Multifaceted approach Although CEA expects to remain a gas fueled utility for some time to come, the utility is taking a multifaceted approach to meeting its long-term energy needs, Steyer said. Increments to the power capacities of the Bradley Lake and Cooper Lake hydropower systems on the Kenai Peninsula are planned, although increased power output from Bradley Lake is contingent on some transmission line upgrades on the Kenai Peninsula. Increasing the capacities of the transmission lines running north and south out of Anchorage would also allow greater flexibility in power generation. Looking further into the future, there is also the proposed major hydropower system at Watana on the Susitna River.
Posey said that, in addition to investing with CEA in the new Anchorage power plant, ML&P has been improving its own power plant, replacing turbines and some pipe work. The utility is investing in upgrades, including a new well and compressors, in the Beluga gas field, the field that it part owns with ConocoPhillips and Chevron and that forms its primary source of gas.
Turning point ML&P expects its gas needs to drop as its power generation efficiency improves, but gas output from the Beluga field is also declining.
“Our turning point is 2018, when we will turn the corner of having to buy more and more gas each year,” Posey said.
Joe Griffith, general manager of MEA, told the task force that MEA is moving ahead with a new 135-megawatt power station that the utility has been planning to build at Eklutna, at the base of the Chugach Mountains. The utility has the necessary air permit for the plant but is still seeking fuel supplies for the power generation. The plan is to use natural gas as fuel, but the generators will be also be able to operate with other fuels — MEA plans to keep diesel fuel on site as a backup but is investigating the potential use of propane.
MEA is making improvements to the utility’s transmission and distribution networks, including the rebuild of some very old substations, Griffith said.
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