Change has become the norm for the Southcentral Alaska gas utility business. While the winter gas deliverability crunch from the Cook Inlet oil and gas fields has been keeping the gas dispatchers on their toes on a day-to-day basis, the tight balance between supply and demand is also impacting longer-term issues relating to gas supply contracting and pricing.
Since the Regulatory Commission of Alaska rejected a proposed new gas supply contract between Marathon and Enstar Natural Gas Co. in September 2006, Enstar has been seeking new contracts to meet its projected supply shortfall in 2009. In February 2007 the company issued a request for proposals for new contracts and is now negotiating contracts with Cook Inlet gas producers Marathon and ConocoPhillips. Those contracts will break new ground.
“The contracts we’re negotiating now are very different from what we’ve seen in the past in a number of ways,” Colleen Starring, Enstar’s regional vice president, told Petroleum News Nov. 28.
Full serviceThe Marathon contract that RCA rejected was a full service contract in which Marathon would have taken full responsibility for both the regular base gas load and peak winter gas demand all within a single gas price. The contract would have run until 2016.
The new contracts, which Starring said should be ready for submission to RCA by the end of the year, will unbundle the pricing into three separate price tiers for base load, seasonal swing during the winter and needle peak supplies during the coldest days of the year. And the contracts will only run for five years.
With tight gas deliverability from the mature oil and gas fields of the Cook Inlet basin, the cost of supporting the extreme demand swings for utility gas between summer and winter has become a significant issue — the new unbundled pricing will take into account the cost of meeting high winter demand. The new contracts will also represent a move towards Enstar taking responsibility for handling the seasonal swing.
“The contracts shift the deliverability to Enstar and they’re volume driven,” Starring said.
Detailed contractual terms are still under negotiation, but Enstar expects a mechanism in which the utility will forecast demand 12 months in advance for both the base load and the demand swings.
“They’re required to commit to volumes, based on our forecast,” Starring said. “If we were to have volumes over and above what the producers have agreed to give us, then that’s Enstar’s obligation to fill those wedges.”
Contract pricing for the three demand tiers is still under negotiation — the prime reason that RCA rejected the Marathon contract was that a majority of commissioners viewed the pricing in that contract as too high. The Marathon price formula used a price indexed to the Henry Hub market in the Lower 48 (Cook Inlet gas producers have argued that gas prices in the Cook Inlet need to reflect Lower 48 prices, to attract investment in new Cook Inlet gas exploration).
RCA approvalEnstar hopes that RCA will view the new contracts favorably. The regulatory procedure can take a year to complete, a timeframe that would run close to the projected 2009 gas shortfall.
“As we negotiate we believe we have a good thing that might be approved, and of course the producers have an opinion of what they can sell internally as well as what they believe the commission will approve,” Enstar spokesman Curtis Thayer said.
Enstar, rather than the producers, will make the case before RCA for the new contracts — Marathon spent one year and $1 million trying unsuccessfully to get the previous contract approved, Thayer said.
“They don’t want to have that experience again,” he said.
But the shorter-term contracts this time around may present opportunities for independent gas producers to enter the Cook Inlet utility market. Enstar is also open to discussions with independents on filling any potential gas shortfalls during demand peaks, Starring said.
If a small producer wants to sell gas to Enstar “we’d love to buy it,” Thayer said. But the current regulatory process inhibits that possibility, he said. Enstar can’t purchase gas under a contract without RCA approval and an independent producer is reluctant to invest in exploration without a contract, he said. The regulatory process takes a long time to complete and may end up with contract rejection — there needs to be some way of fast tracking this arrangement.
“We’re in a regulatory environment where we’re reacting to situations and not being pro-active in solving things. That’s just the way it is set up,” Thayer said. “… It’s just the way we’ve done business for 40 years and times are changing.”
Gas storageOne symptom of change in the Cook Inlet gas business is the introduction of gas storage to ensure winter gas deliverability — excess gas produced during the summer is stored to help meet high demand during the winter. Gas producers Chevron and Marathon now operate gas storage facilities in the Swanson River, Pretty Creek and Kenai fields.
But faced with the potential for a deliverability shortfall as early as 2011 under the new supply contracts, Enstar is moving towards operating its own gas storage.
One possibility is an LNG facility, with excess gas liquefied for later use, that would primarily serve as a peak shaving unit, to ensure adequate deliverability during extreme demand on the coldest winter days. An LNG peak shaving facility would likely cost $180 million to $200 million and take more than three years to build, Starring said.
“If we were to build a peak shaving plant, if we were to start today, it would be 46 months out before we had this plant in place,” Starring said. “… It’s a huge time consideration.”
Another possibility would be to use the existing LNG plant at Nikiski on the Kenai Peninsula for gas storage, if that plant loses its LNG export license in 2011. The current export license expires in 2009, but the plant owners ConocoPhillips and Marathon have applied for a two-year license extension — Enstar has supported the license extension, provided that local gas needs are also met.
The Nikiski plant has LNG tank capacity of 2.2 billion cubic feet, Thayer said.
“It’s a little larger than our needs, but it might be something where we partner with somebody or an electrical facility for their peak shaving,” Thayer said.
Enstar is also looking into the possibility of obtaining an underground in-field gas storage facility by 2011, Thayer said. Because of the relatively low rate at which it is possible to retrieve the gas from this type of facility, in-field storage tends to support general increases in demand during the winter rather than needle peaking.
Energy conservationEncouraging energy conservation is another approach to the issue of tight gas supplies from the Cook Inlet basin — Enstar provides information on energy conservation on its Web site. But the current rate structure, in which Enstar’s service charge for transporting gas to a customer is based on the volume of gas that the customer uses, encourages Enstar to sell more gas rather than less. So Enstar is considering a flat fee, perhaps in the range of $20 to $30 per meter, for gas delivery.
“Basically, it’s like your cable television — you get a flat fee for the service and it doesn’t matter how much television you watch,” Thayer said.
Because the bulk of a typical gas bill consists of the charge for the gas used, rather than the fee for the gas delivery service, gas consumers would continue to have a strong incentive to conserve gas. But, at the same time, Enstar would have no incentive to increase gas throughput.
“It’s something we’re looking at for the next rate case,” Thayer said. “… It makes sense. It helps conservation. It helps the customer, especially the low-income customer.”
But with new supply contracts in the offing, a new rate case to put before RCA in 2008 and the need to look at new ways of dealing with gas deliverability issues, Enstar is in for a busy time.
“We’re going to be spending a lot of time downtown,” quipped Thayer, referring to the location of the RCA office and hearing room.