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More perspectives on the CI gas market Banks says 470 bcf could be developed in existing fields; CEA wants resource management plan; ML&P pushes for state intervention Alan Bailey Petroleum News
The Cook Inlet gas cliff — the apocalyptic graph that shows a precipitous decline in gas production over the next few years — has the capability of making even the hardiest resident of Southcentral Alaska shudder, as he or she sits in the warmth of a gas-heated home on a 20-below January evening.
But what does this graph really mean? And what steps can be taken to ensure that Alaskans who depend on natural gas are not left “out in the cold?”
On March 13 Kevin Banks, director of Alaska’s Division of Oil and Gas, told the House Special Committee on Energy that the data on that graph assume that future gas would only come from continued production from existing wells in existing fields.
“It’s based on an assumption that no further investments are made in the inlet,” Banks said.
In addition, the graph depicts average annual production, rather than the theoretical maximum production capacity of the Cook Inlet gas fields.
Look at capacity As an alternative perspective, Banks presented a graphic in which that theoretical capacity is overlaid onto the familiar gas cliff, together with a plot of historic and projected natural gas demand in Southcentral Alaska. The graph shows that in the past the theoretical capacity has significantly exceeded average production while, in the future, capacity comes into line with the production cliff.
Total gas usage has shown a steep decline, with Agrium’s Kenai Peninsula fertilizer plant closing down in 2007 and throughput in the neighboring LNG plant dropping. And, on the assumption that the export of LNG from the Kenai Peninsula would cease when the current export license expires in 2011, the annual gas demand after that date would level off somewhat below 100 billion cubic feet, the quantity primarily required to supply local gas and power utilities.
But the production capacity of the current gas wells would also drop below that projected demand level at about the time that LNG exports cease, according to the division data.
470 bcf However, the division thinks that there are 470 billion cubic feet of additional gas that the gas producers could access in existing fields through the drilling of new wells.
“This is gas in those discontinuous (Cook Inlet) sands that has not been reached by the existing wells,” Banks said.
And spreading 470 billion cubic feet of gas across the multiyear gap between projected demand and projected production from existing wells extends the shortfall in Cook Inlet gas production out to 2019. Any further supplies would then have to come from new gas exploration.
But the producers need a market outlet for their new gas if they are to drill for that extra 470 billion cubic feet.
“A producer will not drill a well until it knows that it has a place to sell (the gas),” Banks said. “What we’ve seen in the past … is that a producer will enter into a supply contract with a customer and meet the supply requirements for that customer by additional drilling.”
And if the federal government allows LNG exports to continue beyond 2011, some of that extra gas would likely head for the LNG terminal. So, in the negotiations for the next LNG export license renewal, the state needs to ensure that the producers commit to developing these new reserves “and then some,” Banks said.
Extreme swings Any consideration of the Cook Inlet gas market also needs to take into account the extreme swings in Southcentral Alaska utility gas demand between summer and winter — rather like a day-to-day cash flow problem when operating an otherwise viable business, a gas deliverability shortfall during peak winter demand will cause extreme difficulty, even if there is enough gas to meet total demand on an annual basis.
“In the past there was sufficient capacity in all of the fields to simply produce more gas from the existing wells (in the winter),” Banks said. “Now it has become more of a delicate balancing act.”
Utilities that anticipate extreme “needle peaking” demand can cushion that demand by increasing gas pipeline pressure, to step up the line pack. But it is mainly the Cook Inlet producers who accommodate demand swings by using producer-operated underground gas storage, drilling more wells into existing gas fields and by diverting gas intended for the LNG plant, Banks said.
The division would like to see new gas storage facilities available to any business that needs storage, rather than just to a producer that operates the facility.
“Those kinds of market mechanisms are common in the Lower 48 and I think there is a wonderful opportunity to have those sorts of things working here, so that the market can respond as it should,” Banks said.
Bradley Evans, CEO of Chugach Electric Association, the main Anchorage electric utility, expressed frustration at the lack of information transparency in the Cook Inlet gas market. Chugach generates 90 percent of its power from natural gas and has been trying to negotiate new gas supply contracts with the Cook Inlet producers. And although Chugach wants to move toward a high degree of renewable energy usage, thus lowering the gas demand for power generation, the continued use of natural gas is an essential stepping stone to that renewable future, Evans said.
“The Cook Inlet (gas) resource is vitally important to us,” he said.
Chugach wants to see the development of a Cook Inlet resource management plan and the formation of a Cook Inlet public gas authority, which would represent consumers and would probably include the gas and electric utilities as members.
“There are organizations out there that combine the interests of consumers — there’s a large gas authority in the southern United States,” Evans said.
The resource management plan would be designed to address fuel supply security and information transparency, and it would lead to well-timed investments and rational management decisions. The plan would dovetail with the state’s Railbelt integrated resource plan.
“We have some (gas) storage options we’re working on,” Evans said. “The timing of those investments is critical.”
Needs to be supercharged James Posey, general manager of Anchorage electric utility Municipal Light and Power, supported the resource management plan concept but called for much faster action.
“The whole process that we’re going about, looking at the Cook Inlet, needs to be turbocharged,” Posey said. “… We’re going to have some real problems if we don’t find new gas.” Posey said that he is really worried about gas supplies between 2014 and 2020 and that gas supply problems need to be resolved within three years.
“We need to put the state in front of that engine to make sure that we look for another trillion cubic feet of gas, to get us to where a bullet line or a line to the North Slope or LNG imports can grant us some security beyond 2020,” Posey said, suggesting initiatives such as persuading the federal government to open more of its land for exploration, or making sure that a jack-up rig comes to the Cook Inlet for offshore exploration drilling.
The dream of a North Slope gas pipeline has been floating around since 1975.
“We’re still waiting on it,” Posey said. “So it is important for the state to play a role in the Cook Inlet exploration. … Whatever that role is … it is going to require some allocation of resources.”
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