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Vol. 13, No. 31 Week of August 03, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Enstar cutbacks?

No new contracts could mean no service for some commercial consumers

Alan Bailey

Petroleum News

The initial sparring is over and the contestants have entered the ring for the next round of the tussle between Enstar Natural Gas Co., the State of Alaska and various gas users over Enstar’s multi-year attempt to establish new gas supply contracts with Cook Inlet gas producers.

Enstar’s latest try at filling future supply shortfalls, the signing of new gas supply contracts with Marathon Oil Co. and ConocoPhillips Alaska, met the full gaze of public scrutiny on July 28 during the first day of the Regulatory Commission of Alaska’s two-week public hearing on the contracts.

When Enstar submitted its revised tariff under the new contracts to RCA in April, Colleen Starring, Enstar’s regional vice president, told the commission that the new contracts fill a gap of some 2.1 billion cubic feet in Enstar’s gas supply portfolio for 2009. Enstar, the local natural gas distribution company for Southcentral Alaska, only has contracted supplies to meet all of its customers’ needs until the end of 2008.

What happens in January 2009 if RCA has not approved the new supply contracts, state Assistant Attorney General Steven DeVries asked Eugene Dubay, chief operating officer of Semco Energy Inc., Enstar’s parent company, during cross examination at the RCA hearing.

We have identified a slice of our commercial customers that we might not be able to serve, Dubay said.

“It’s possible for instance that those commercial customers could be represented by an enterprising marketer and that marketer could go directly to Conoco and Marathon, and they could get the same gas that we’re trying to get under contract … at whatever price they could negotiate,” Dubay said.

However, Dubay said that Enstar has not made any decision about what to do in the event of a gas supply shortfall — other options would include trying to negotiate another agreement with the producers.

“Obviously we’ll do our best to see that the community is served,” Dubay said. “But I don’t have an answer for you today as to how that service will come about if these contracts aren’t approved.”

2006 rejection

In September 2006 RCA rejected an Enstar contract with Marathon that would have filled the 2009 shortfall. That contract involved gas pricing based on a trailing average of Henry Hub prices in the Lower 48. A contract with Union Oil of California (now part of Chevron) approved by RCA in 2001 used a similar Henry Hub-base pricing model, but in the 2006 decision a majority of the commissioners said that the Henry Hub pricing was unjustifiably high for the Cook Inlet gas market.

Enstar and the gas producers have long argued that Lower 48 pricing is necessary in Cook Inlet to provide gas producers with an incentive to explore and develop in the region.

The pricing in the new Marathon and ConocoPhillips contracts uses indexes based on baskets of North American gas price points. Price tiering increases the price paid for “swing” gas during periods of high gas demand, during the cold Alaska winters. In keeping with the State of Alaska agreement with Marathon and ConocoPhillips over the extension of the export license for the Nikiski LNG terminal, the contracts include provision for the curtailment of LNG production to meet any shortfall in the deliverability of gas to Enstar.

The contracts anticipate that by 2011 Enstar will establish gas storage facilities to reduce the need to purchase gas at the more expensive high-demand price tiers.

Request for proposal

In his opening remarks at the RCA hearing, Enstar’s attorney William Saupe said that following the 2006 RCA rejection of the 2005 Marathon contract, Enstar issued a request for proposal for gas supplies. Only Marathon and ConocoPhillips responded to that RFP, Saupe said.

World gas prices have increased since Enstar’s previous tariff proposal and the pricing in the new contracts reflects new market conditions. And although the prices would result in an increase in Enstar’s weighted average cost of gas, the composite indices used in the pricing are preferable to pricing based on LNG prices, Saupe said.

Current LNG prices in Japan would net back to a price of $15 to $17 per thousand cubic feet of gas in Cook Inlet, he said.

“Under these market conditions the proposed contracts priced at domestic U.S. market prices are unquestionably a better deal for customers,” Saupe said.

The tiered price structure reflects common practice at Lower 48 hubs, where higher prices for peak gas supplies reflect the cost of gas storage or the need to purchase additional gas on the spot market, Saupe said.

“The swing premiums are far lower than other peak shaving options that Enstar might have available in the Cook Inlet at the present time,” he said.

LNG curtailment

Saupe emphasized the value of the provisions to curtail LNG production, to divert gas to meet high Enstar demand when necessary. The decades-long track records of Marathon and ConocoPhillips in meeting their obligations to customers also added confidence to the security of the gas supplies that Enstar had now contracted, he said.

“The new contracts do reflect the best terms and conditions that were available to Enstar,” Saupe said. “… These contracts necessarily reflect conditions in a wholesale gas market that is unregulated and is experiencing tight supplies and constraints on deliverability that are well-documented in the record. … These two contracts … achieve a reliable supply of gas for our customers at reasonable prices that do reflect the realities of the market.”

Saupe addressed arguments put forward by Chugach in written testimony that the continued operation of the Nikiski LNG plant demonstrates the existence of plentiful Cook Inlet gas and that the gas producers have obligations under their leases to sell gas to Enstar as long as they can make a profit.

“Our witnesses have explained in great detail all of the reasons why these theories don’t work in the real world,” Saupe said. Cook Inlet gas is not as abundant as it was 20 years ago and the producers have alternative customers to Chugach and Enstar, he said.

Presumably Enstar needs to wait for the Alaska Department of Natural Resources and other lessors to take action to enforce lease obligations to market gas beyond what the producers are doing now, he said.

“We hope these contracts will bridge us to a different market in the future,” Saupe said, referring to prospects for new gas storage facilities and gas pipelines that he said may make the gas market more favorable to consumers.

Redman: no doomsday

In an opening statement for Chugach Electric Association, a major Anchorage electric utility, attorney Eric Redman said that while Chugach doesn’t underestimate the uncertainties and difficulties in the Cook Inlet gas market, there is no evidence for a pending doomsday scenario.

“The doomsday scenario is that Enstar customers begin to freeze in their homes and businesses on Jan. 1 while Conoco and Marathon … ship Alaska gas from Alaska leases off to Japan to make sure no one freezes in their homes and businesses in Tokyo,” Redman said. “No business has yet suggested a doomsday scenario on the record.”

Redman said that the entire case relating to the new Enstar contracts revolves around whether Enstar has met its burden of proof that the gas pricing in the new contracts is reasonable and, if not, what action RCA should take. And Redman characterized the price formula in the new Enstar contracts as “Henry Hub supersized.”

But the case is not about a scarcity of gas in the ground, Redman said.

“ConocoPhillips and Marathon … have just proven to the U.S. Department of Energy the existence of an abundance of … reserves,” Redman said. “They had to do that to get their LNG export authorization.”

Scarcity pricing can reflect a scarcity of competing sellers and in the Cook Inlet mergers have reduced the number of producers to three, he said.

And the case is not about prices going up or being high; it’s about which market price should apply, Redman said.

Price mark-up

The new contracts don’t just use index prices for the Lower 48, Redman said. They mark up the prices using tiering to include storage costs that have previously been bundled into the base price. And the new price formula looks likely to result in prices that are higher than Henry Hub all or much of the time.

“In the Lower 48 there are market prices at points of receipt and production areas. There are market prices at gas trading hubs and there are market prices further downstream at city gates. They are all market prices,” Redman said.

Price analogues for Cook Inlet should be at the production end of the pipelines where there are drilling rigs, production platforms and roustabouts, not at hubs or city gates, Redman said. To do otherwise would, for example, allow pricing based on delivery to some hypothetical LNG terminal on the U.S. West Coast without allowing for the transportation costs from Alaska.

In fact, Redman questioned the whole principle of linking Cook Inlet prices to the Lower 48, since there is no way of delivering Cook Inlet gas to Lower 48 markets.

And Redman lambasted the argument that Lower 48 pricing is required to encourage new investment in Cook Inlet gas exploration and development. A gas boom in the Lower 48 is driving investment there and investment decisions depend on expected returns, not on price levels, he said.

“It’s not enough to suggest that other things being equal if you raise the prices it’s more profitable. It doesn’t tell you about the flow of capital,” Redman said. And then there’s the question of the duty of the companies to produce gas under the terms of their Cook Inlet leases, he said.

Redman commented that there is evidence to link the Cook Inlet gas market to the gas market in Japan, because of the export of LNG from Cook Inlet. However, federal limits on both the amount of LNG that the companies can export and the time period over which the exports can take place complicate that market linkage.

“Chugach’s witnesses point out that there’s no way Conoco and Marathon can simply toss into the current export hopper another 37 bcf earmarked for Enstar under these contracts,” Redman said. “… They also can’t simply shut in production and silo away this extra gas for export later.”

Difficult decision

And Redman commented on the difficulty of RCA’s pending decision over the new Enstar contracts.

“The record shows that in the absence of effective competition in the Cook Inlet among producers, the price ceiling that you approve in one Enstar contract becomes the price floor to negotiate the next Enstar contract,” Redman said.

On the other hand, if RCA rejects the pricing there’s no way to know what will happen next, he said.

However, there are some other possible options such as approving the contracts subject to required modifications or allowing the contracts to go into operation, subject to later reconsideration of the pricing. Alternatively, without RCA approval, the producers could legally sell gas to Enstar at prices that reduce Enstar’s average price of gas, Redman said.

In pre-filed testimony the State of Alaska Attorney General’s Regulatory Affairs and Public Advocacy Section had also taken issue with the gas pricing terms in the new Enstar contracts.

However, on the first day of the hearing Assistant Attorney General DeVries spent much of his cross examination of Dubay exploring the extent to which terms of the contracts ensure a reliable supply of gas. DeVries particularly focused on the term “proven and risk-probable reserves,” used as an assurance for the availability of gas under the contracts.

DeVries said that the Marathon contract defined “risk-probable” as reserves with a probability of 50 percent or better.

“Is it your testimony that 50 percent certification is reliable?” DeVries asked.

“My testimony is that when you look at what we’ve got in the contract we believe that Marathon and Conoco can perform and meet their obligations under the agreement, and I include with that the expectation that they would convert from the LNG plant when so required,” Dubay responded. “.… When we go back to everything in the contract I think we get the reliability.”

However, the ConocoPhillips contract has a provision that deliveries to Enstar can be suspended if the state elects to take its royalty gas in kind (i.e. take delivery of actual gas rather than royalty payments), DeVries said.

“The agreement is what it is. … I think that these agreements provide us the gas with the certainty that we need and I’m absolutely certain … that the producers intend to meet their obligations under these agreements,” Dubay said.

DeVries asked if it was reasonable to expect customers to pay 5 to 10 percent above the base index price for gas in the tiers for high demand. Cristina Klein, witness for the Attorney General’s office, had stated in pre-filed testimony that the price index in the ConocoPhillips contract, for example, should reflect an average price for gas across the various tiers, not the base price.

“No one wants to pay any more for any commodity or service than they have to,” answered Dubay. “… We think we’ve ended up with the best deal that we could craft.”

The hearing continues until Aug. 8.



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