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Lawyer says RCA statutes need overhaul Aging laws do not accommodate rapidly changing energy scene as gas storage, LNG imports, new energy sources cause complications Alan Bailey Petroleum News
The Regulatory Commission of Alaska occupies a critical position in decision making over Alaska’s energy supplies and energy infrastructure. But in a rapidly changing energy scene, the state statutes that govern the commission’s actions have not kept abreast of modern regulatory needs, Julian Mason, a lawyer with Ashburn & Mason, told Law Seminar International’s Energy in Alaska conference on Dec. 1.
“The commission operates with a statute that’s roughly 50 years old,” Mason said. “It has in many respects little relevance to what’s going on right now.”
Transition With the energy supply situation in Southcentral Alaska in transition from an era of surplus natural gas into a future of more diversified energy sources and tighter energy supplies, the energy industry now needs to deal with issues such as gas storage, contracts for peak winter supplies, alternative energy sources and gas pricing indexed to external markets. The statutes do not deal directly with any of these issues, Mason said.
Mason complemented the RCA on what he said was the excellent job that the commission has done so far in navigating the energy transition, despite the statutory shortcomings. The commission has rapidly approved Cook Inlet Natural Gas Storage Alaska’s new gas storage facility on the Kenai Peninsula and has also approved a contract between Chugach Electric Association and Cook Inlet Region Inc.’s Fire Island wind farm, Mason said.
Approval of the gas storage facility involved recognition of what are called “inception rates” for the facility, a form of rate new to the commission, Mason said. Inception rates are the initial fess for facility use, calculated from estimates of facility costs and needed to ensure recovery of those costs by the facility operator.
Approval of the Fire Island contract involved consideration of both long-term and short-term power costs, and the acceptance of a slight increase in current power rates in the interests of bringing a new form of energy on line, Mason said.
Balancing incentives But one of the challenges looming in the future, as new gas discoveries start to appear, is the question of balancing business incentives to export new Cook Inlet gas from the state against the need to assure future in-state utility gas supplies, Mason said. State tax incentives for gas exploration and development do not place any constraints on what the gas is ultimately used for — to ensure adequate local gas supplies, the commission may have to deal with questions relating to the appeal of the local utility gas market relative to the exporting of gas.
Another potential problem relates to the length of time it may take for new gas supplies to come on line, Mason said. Utilities are talking about importing liquefied natural gas, or LNG, to fill future shortfalls in Cook Inlet gas supplies. But it might cost upwards of $200 million to implement new LNG import facilities. And, since it would take time to implement those facilities, it is not practical to wait until local gas runs out before starting the implementation.
“You’ve got to start the LNG project now, not later,” Mason said.
Cost recovery So, what happens if meantime a new Cook Inlet gas discovery makes the LNG importation unnecessary? Under current statutes, the commission would require utilities to use the cheapest gas sources, leaving the LNG facility developer with the problem of how to recover the facility development costs. The upshot would be a kind of “crazy loop,” with a decision-making impasse, Mason said.
“To get out of that the legislature and the utilities and the commission need to work together to do something that they did recently in changing the (statutory) standard for approving gas supply contracts,” Mason said, referring to statute changes in 2010 allowing the commission to consider reliability of supply, rather than just cost, when approving utility gas supply agreements.
The statutes now need to allow the commission to make a decision based on the best available evidence, recognizing for example that there is no current evidence that all needed Cook Inlet gas will be available for utilities in three to four years time, Mason said. The risks and potential costs associated with not pursuing an LNG project need to be allowed to weigh into the decision making. And utilities need to be able to recover the costs associated with LNG imports, even if cheaper sources of gas become available, he said.
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