THE LINK: OCTOBER 2023 36 Renewable energy can’t fill needs from decline in Cook Inlet Two consultant studies done independently now agree: Imports of liquefied natural gas will be needed to offset a looming decline in natural gas production in Cook Inlet. Major utilities in the state’s “rail belt” corridor — the major population centers from Southcentral to Interior Alaska — have been saying that for some time. Now there is independent verification. One study is sponsored by Chugach Electric Association and done by Black & Veatch, a consulting firm. A second study is sponsored by all the major utilities, led by Enstar Natural Gas Co., and done by Berkeley Research Group. Natural gas fuels most space heating and power generation in the region, so shortfalls in production from Cook Inlet are a matter of concern. A decline in gas production from existing Cook Inlet Basin gas fields is expected to begin in 2027, according to Alaska’s Division of Oil and Gas in a report issued in early 2023. Gas storage can cover utilities’ needs for two to three years but some form of imported liquefied natural gas, or LNG, will be needed by 2030, the Black & Veatch and Berkeley studies say. New renewable energy projects can help but they can’t be built fast enough to forestall LNG imports. It’s also unlikely enough of them can be built to even dent the problem. They won’t be cheap, although the costs are unknown. The large Alaska LNG Project, which would have an 800-mile pipeline built from the North Slope, could nicely fill needs and at reasonable costs, but it also can’t be built in time. The long-discussed Susitna hydro project, if built, could fill all of the rail belt electricity needs, and then some at very low costs but it can’t be built in time, either. Both of the consultant studies agree that LNG imports will be costly and will raise fuel costs for utilities and consumer costs for heating and electricity. Fuel costs for utilities could rise from about $8 per thousand cubic feet (mcf) to about $12 to $15 per mcf. Only part of this is passed through to consumers, however, because fuel is only part of electric utilities’ costs. But there will still be a big impact for consumer, particularly in space heating. Expansion of renewable energy, like solar, wind and hydro, can help the electric utilities not for Enstar Natural Gas, which supplies the gas used in heating of most homes and buildings in Southcentral Alaska. While this will affect heating bills in the short-to-medium term, in the long run it will also spur more aggressive home energy conservation and insulation efforts, likely backed by the government, which have been successful in the past. For homeowners using gas, there is likely to be resurrection of the popular home energy rebate program, where government subsidies helped pay for insulation and other improvements. A previous rebate program was funded by the state. A new energy rebate may be partly funded by the federal government, authorized by the federal Inflation Reduction Act, an act passed by Congress in 2022, authorizes such a program and the U.S. Department of Energy is now working on regulations. Major building owners, meanwhile, will likely pursue other strategies, including electrification of buildings, if that offers savings. This could be combined with power storage. Microreactors, the new generation of small-scale nuclear reactors now being licensed by the federal government, might be installed in some places for large users. However, renewable energy projects will help even if on a limited basis. Chugach Electric is considering two large 100-megawatt projects, one wind and one solar, in the Matanuska-Susitna Borough. The cost of these is still unknown. Some projects are already showing they are viable and can be competitive with natural gas at present prices. Two privately-owned solar projects in the Mat-Su, one near Willow and a new one near Houston, sell power to Matanuska Electric Association at rates competitive with gas. The same company is planning a larger solar project on the Kenai Peninsula. But to fill the near-term gap, imports of LNG most likely from British Columbia are likely. The most practical options, agreed in both the Black and Veatch and Berkeley Research studies, are for a floating LNG storage facility in Cook Inlet, a moored vessel linked to an onshore gas pipeline. This would be supplied by a small or medium-sized LNG tanker transporting the liquefied gas. LNG tank barges could also be used. The mothballed LNG export plant at Nikiski, on the Kenai Peninsula, is another possibility. LNG tanks and other machinery at the plant are in place and can be used for imported as well as exported LNG but upgrades are likely needed. The cost of converting the plant from an export to import facility would also have to be paid for. The utilities studies put these as high as $150 million. Marathon Petroleum Co., which owns the plant, would also have to negotiate an agreement for it to be used. Both the Berkeley group and Black and Veatch are now in phase two of their studies to define costs around best options. This is to be completed this fall. The expectation is that both of the utilities’ efforts Studies: LNG imports needed to offset gaps
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