Termed by some a “Cook Inlet renaissance,” the upsurge in exploration activity coupled with some new gas finds in Alaska’s Cook Inlet basin has perhaps led to a sense that what had appeared to be a growing crisis over utility gas supplies for Southcentral Alaska is turning instead into a new era of plentiful and cheap energy in the region.
Unfortunately, however, the region still faces potential gas supply shortfalls in the next few years, with the possibility of power cuts or worse, should the flow of gas from Cook Inlet gas fields fall short of peak gas demand, especially during the winter. That was the overriding message from a Sept. 26 meeting of the Anchorage Mayor’s Energy Task Force, in which some Southcentral utilities presented their analyses of the short- to medium-term gas supply and demand situation, as projections of available gas supplies show continuing declines.
Short of time
While expressing satisfaction with new, heightened levels of gas exploration and development in the Cook Inlet region, utility executives pointed out that the lead time involved in finding new resources, developing new fields and bringing new gas to market renders it highly unlikely that sufficient new gas will come online before currently dwindling supplies drop below demand levels. And so, while there may be reason for cautious optimism about the gas supply situation a few years into the future, the short- to medium-term situation is worrying and requires decisive action.
Consulting firm Petrotechnical Resources Alaska, or PRA, has been monitoring the Cook Inlet gas supply situation on behalf of several utilities. PRA has recently changed its prediction of when annual gas supplies are likely to fall short of demand from 2013 to 2014, with that shift in the forecast resulting from the drilling of new gas wells and the addition of new gas compressors to gas fields.
But that potential gas shortfall is just two years from now.
James Posey, general manager of Municipal Light & Power, or ML&P, told the task force that the usual timeline for developing a new field and bringing new gas online is anywhere from two to seven years, especially for the size of field required to have a major impact on the Cook Inlet gas supply decline curve.
“There is no one-year miracle for a large amount of gas,” Posey said. “There are no miracles out there within the two-year timeframe.”
And Posey cautioned that as more and more wells are drilled into existing fields, to boost both gas production and the rate at which gas can be delivered, the production decline rates for new wells become progressively higher — it’s a bit like pushing an increasing number of straws into a deflating balloon.
Whereas production from most of the Cook Inlet gas fields is declining at a rate of 19 percent or more per year, production from new wells now typically declines at rates of between 25 and 30 percent, Posey said.
And then there’s the question of deliverability: the rate at which gas can be flowed from the fields, especially to meet peak utility gas demand on cold winter days.
Posey said that a recent gas compressor failure in the Beluga gas field had caused ML&P to request 2 million to 3 million cubic feet of gas from Cook Inlet Natural Gas Storage Alaska’s new gas storage facility on the Kenai Peninsula, to enable the power utility to meet its gas supply needs for a day.
“That’s how close we are,” Posey said.
Cook Inlet Natural Gas Storage Alaska, or CINGSA, brought its new gas storage facility online in April and since then has been filling the facility’s underground reservoir, in preparation for the coming winter.
The utility executives said that they are working on “plan B,” a contingency plan to keep the lights and heating on in Anchorage and other Southcentral communities, should local gas supplies drop below needed levels. And, given the short timeframe available to put a contingency plan into place, the only feasible options seem to be the import of liquefied natural gas or compressed natural gas from elsewhere into the region, to supplement local gas resources. Should these two options fail to materialize, the only other possibility would appear to be a periodic switch over to the use of liquid fuels such as diesel, rather than gas, for power generation.
But liquid fuels have become increasingly expensive in recent years, as anyone in the habit of fueling a motor vehicle knows to their cost. Electricity generated using liquid fuels might be five times as expensive as natural gas fueled power, Lee Thibert, senior vice president of Chugach Electric Association, told the task force.
For some time the utilities have been investigating the possibility of importing liquefied natural gas, or LNG, into Southcentral Alaska, perhaps by converting the LNG export facility at Nikiski on the Kenai Peninsula into an import and regasification terminal. The utilities have been looking into LNG markets, pipeline transportation, shipping opportunities and the question of the optimum import point, including the Port of Anchorage, Kenai and Whittier, Thibert said. The concept of importing compressed natural gas, or CNG, has also gained some traction — this option would offer the advantage of the ability to purchase gas at relatively low prices on the U.S. West Coast.
“The problem is the transportation component is very expensive and, to do that, it’s a long term commitment,” Thibert said.
Thibert cautioned that the timeline to establish CNG or LNG imports “at the very best is 24 months,” while also adding that he couldn’t disclose any potential cost data, given the confidential nature of negotiations with potential suppliers. Given the short time window for establishing the supplies the utilities are not looking to the state for financial assistance, other than perhaps for the engineering for an LNG regasification facility, he said.
“We are at the point where we cannot wait for another legislative session for this to happen. We have to move forward,” Thibert said.
Brad Evans, CEO of Chugach Electric Association, said that Chugach Electric anticipates passing the cost of contingency gas on to its customers through the electricity rates, although the utility is a “bit skittish” about this, given past experience of recovering costs through rates. The utility’s balance sheet does not accommodate the millions of dollars that would be required for the out-of-state fuel supplies, he said. Evans also commented that the development of transportation routes presents the biggest hurdle in negotiations over the supply of LNG or CNG from out of state.
During presentations from the utilities it became apparent that the new CINGSA storage facility now plays a pivotal role in Southcentral gas supplies, accepting gas produced during the summer and then delivering that gas during the winter, when gas demand is high, keeping winter gas supplies up to required levels at least for the time being.
Mark Slaughter, Enstar Natural Gas Co.’s manager of gas supply, told the task force that although the CINGSA facility has been accepting gas all summer, the facility still does not have as much gas stored as planned — CINGSA is working on that issue and anticipates continuing to build up its gas stockpile until the end of October. The goal is to obtain an additional 2.4 billion cubic feet of “base gas,” the gas used to maintain the facility’s reservoir pressure, Slaughter said, adding that CINGSA may have to pay more than originally planned for that gas. The rate of gas injection over the summer fluctuated quite widely, mainly because the storage facility has been competing for gas with the Nikiski LNG export facility, Slaughter said. In its original plans CINGSA had envisaged the LNG plant shutting down, but in the aftermath of the 2011 tsunami in Japan there has been a resurgence of LNG demand, enabling the LNG plant to continue to operate.
Slaughter presented a graph of Enstar’s estimated gas deliverability for the coming winter and the winter of 2013-14, showing that gas demand on a peak possible winter day at temperatures around minus 20 F could only be accommodated by withdrawing gas from the CINGSA facility. And a graph of Enstar’s annual gas supply forecast shows a growing unmet gas supply need from the end of this year — in other words a shortfall in gas supplies that are needed but not currently available under firm contract. A Marathon gas supply contract ends on Dec. 31 and contracted gas supplies from Hilcorp Alaska LLC are set to drop after that same date. Slaughter emphasized that, although these contracted gas supplies drop out at the end of the year, the gas that is potentially available does not suddenly disappear: The problem is that the supplies are no longer guaranteed and the price of the gas is uncertain.
As a gas utility “that is not where we would like to be,” Slaughter said.
One complication in the gas supply contract situation is the Hilcorp purchase of Marathon’s Alaska assets — negotiations over that purchase are still in progress, thus making it difficult for Enstar to negotiate a new supply contract for gas that Marathon would produce, Slaughter said. If the company merger is delayed, there should be enough gas available but the gas will be sold in a spot market and prices will likely rise.
“It’s a free market and oil companies are very good at making profits,” Slaughter said.
On the other hand, Enstar feels encouraged by Hilcorp’s aggressive development plans in the Cook Inlet basin and the utility is building a new gas pipeline to Hilcorp’s Red Pad on the Kenai Peninsula, Slaughter said.
Thibert said that Chugach Electric has enough gas under contract to meet its needs until 2015, at which point it currently starts to see a growing shortfall in supplies under contract, despite a drop in demand in 2015 when it stops supplying power to Matanuska Electric Association, and despite an earlier drop in demand when a new highly efficient gas-fired power station in Anchorage comes online in the first quarter of 2013. Currently, none of Chugach Electric’s gas needs are under contract from 2017 onwards.
In the longer term, the utility is trying to diversify away from its high dependence on natural gas for power generation, and energy conservation has been playing a significant role in damping down electricity demand, Thibert said.
Posey said that ML&P is increasing its generation efficiency by participating with Chugach Electric in the new Anchorage power plant and by installing more efficient turbines in its existing plant. But, following the results of recent drilling, ML&P now anticipates the Beluga gas field, the utility’s main source of gas, to cease operating much sooner than the 2027 date originally anticipated, he said.
Matanuska Electric Association
Donald Zoerb, chief financial officer for Matanuska Electric Association, or MEA, said that MEA would not require gas until 2015, when the utility will stop obtaining power from Chugach Electric and start operating MEA’s new gas fired power station, currently under construction at Eklutna, north of Anchorage. The gas required for the Eklutna power plant represents a displacement of gas demand from Chugach Electric and is, therefore, not incremental to the existing gas load, Zoerb said.
“We are aggressively pursuing all credible options” for gas supplies for the new plant, which is also capable of using diesel fuel or heating oil, he said.
One point not discussed during the task force meeting is the possible impact on a power utility of Enstar experiencing a shortfall in gas deliverability during the winter, even if the power utility has all of its needed gas under contract. In that case the power utility would probably have to divert some of its gas supplies into Enstar’s system, to ensure the maintenance of adequate gas pressures in Enstar’s transmission and distribution pipelines. The consequence could be rolling power cuts in Southcentral.