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Vol. 14, No. 38 Week of September 20, 2009
Providing coverage of Alaska and northern Canada's oil and gas industry

What price CI gas?

RCA gleans views on breaking utility supply contract approval logjam

Alan Bailey

Petroleum News

While concerns rise about whether natural gas supplies from Alaska’s Cook Inlet basin will be able to keep up with local utility demand, especially during the depths of the winter, a debate continues regarding whether Cook Inlet gas prices are too low to entice sufficient new gas exploration and development, or whether the Cook Inlet gas producers are crying wolf over the gas supply situation, to increase their profits by pushing gas prices up.

Since 2004 the Regulatory Commission of Alaska, in its role of regulating the utilities and protecting energy consumers from unnecessarily high energy prices, has rejected as too expensive every gas supply contract that Enstar Natural Gas Co., the main Southcentral Alaska gas utility, has negotiated with Cook Inlet gas producers. A recent supply agreement between power utility Chugach Electric Association and gas producer ConocoPhillips is the only utility gas supply contract that the commission has approved in that time.

But what is a reasonable price for Cook Inlet natural gas?

On Sept. 16 RCA convened a technical conference to seek views on how to provide regulatory oversight of gas pricing, to help change the regulatory process for gas supply contract approval from what has all too often become an expensive and time consuming minefield, possibly delaying new gas development, into more of a well-marked pathway.

Producer view

The major Cook Inlet gas producers declined to participate in the conference, citing anti-trust issues that might be raised by their involvement in discussions about how gas prices might be set. But a written statement by Marathon, one of those producers, reiterated an often expressed oil company view that supply contracts, including gas pricing arrangements, should be “freely and fairly” negotiated between the producers and the utilities, rather than be specified in some way by regulators.

“The regulators should regulate the regulated, not the gas market,” Marathon said. And negotiations between the producers and the utilities need to recognize that producers are driven by the balance between risk and reward, in a situation where gas projects in Alaska compete for finite funding with other projects on a global basis, the company said.

But the isolated nature of the tiny Cook Inlet utility gas market and the lack of a spot market for Cook Inlet gas have made it impossible to determine a market-driven local gas price and have led gas contract negotiations into some creative ways of establishing contract prices.

A few decades ago, prior to the formation of dynamic national and global natural gas markets, negotiations between Southcentral utilities and the Cook Inlet gas producers led to long-term contract gas prices indexed to the price of oil. And, with a large glut of Cook Inlet gas, those prices were low relative to other part of the United States.

Changing market

Then in the early 2000s, as tightening Cook Inlet gas supplies started to draw people’s attention to the need for more Cook Inlet gas exploration, and as a burgeoning North American and global trade in natural gas drove the establishment of many gas trading hubs, Cook Inlet gas contract negotiations moved toward the indexing of Cook Inlet gas prices to gas markets elsewhere, in particular to the Henry Hub market in the Lower 48.

Indexing Cook Inlet gas prices to Lower 48 prices would enable Cook Inlet gas exploration to compete for capital with gas exploration projects elsewhere, the gas producers argued.

In 2001 RCA approved a Unocal gas supply contract with Enstar that used a Henry Hub index, and in 2004 the commission approved a similar contract between Enstar and the NorthStar Energy Group. However, the commission subsequently dropped its support for Henry Hub indexing, and for other proposed indices involving North American trading points at the demand or downstream end of gas transmission networks, saying that these markets did not model the market situation in the Cook Inlet and resulted in over-priced Cook Inlet gas.

The commission proposed instead a price index based on a basket of producer basin markets, an approach that the producers rejected for contracts with Enstar but which forms the basis of the pricing in the recently approved Chugach contract.

Market index?

Is the use of this form of market index appropriate as a benchmark for gas prices in Cook Inlet, the commissioners asked at the Sept. 16 conference? And should the commission specify a “safe harbor” range of prices that would be acceptable to the commission and guarantee contract approval?

Some conference participants cautioned about the difficulty of restraining prices within a narrow range, an approach that seems akin to price controls. And Dan Dieckgraeff, Enstar’s manager of rates and regulatory affairs, argued the case for price mechanism flexibility, given the inevitable differences between different contract situations and the evolving nature of gas markets.

Trying to pick a pricing mechanism that works perfectly today is not useful for determining gas prices in the future, given that gas markets around the world are changing continuously, he said.

And Commissioner Janis Wilson commented that experience of linking Cook Inlet gas prices to Lower 48 market indices has in practice demonstrated how little connection there is between the market dynamics in the Lower 48 and the gas supply and demand situation in the Cook Inlet.

“Here we are with a (gas) surplus in the Lower 48, prices going way down, and we’re facing gas shortages (in the Inlet),” Wilson said.

Another possible Cook Inlet gas price model discussed at the conference is a price cap indexed to the estimated price of imported LNG, imports that would form an obvious alternative to the Cook Inlet basin as a gas source.

And Aurora Gas, the one producer to participate in the conference, would like to see some percentage of the total gas demand set aside for bidding in an open spot market that would give small producers like Aurora market access, while also establishing a market gas price. However, utilities have expressed concern about this concept, because of utility needs for assured supplies from medium- to long-term contracts.

No cost data

One problem that the commission faces when it comes to assessing a reasonable gas-price level is the absence of information regarding the cost of Cook Inlet gas production, information that the gas producers are unwilling to divulge, said Commissioner Anthony Price.

“One emphasis in prior gas contracts is that there’s more cost in the Cook Inlet, and yet there’s no evidence put on the record of the cost in the Cook Inlet,” Price said. “… There’s nothing we can land on.”

Dieckgraeff said that, although costs factor into gas producer decision making, in his experience it is gas prices that determine gas producer investment commitments. On the other hand, the cost of servicing the extreme swings in Alaska utility gas demand between summer and winter must be taken into account when comparing Alaska gas prices with those in the Lower 48, he said.

In fact, the commission is seeking views on whether it should allow seasonal price variation, or possibly gas producer cost add-ons for the storage of gas for winter use, in approved gas supply contracts. The conference participants seemed to share a view that new gas storage in the Cook Inlet basin will prove to be a key factor in managing gas supplies for winter use, and that the necessary storage facilities will come at a cost. Storage facilities could also provide a gas market for small producers such as Aurora Gas, said Alan Dennis, royalty manager in Alaska’s Division of Oil and Gas.

Price flexibility

However, as in models for the base pricing of gas, there needs to be flexibility from one contract to another in the way in which storage costs can be recovered, whether cost recovery comes from tiering the gas prices to different levels of delivery, or from a single, year-round “bundled” price. Dieckgraeff argued.

“One size fits all isn’t the way we want to go here,” he said.

RCA is also considering whether there may be value in legislative changes to state statutes, to specify how the commission should review utility gas supply contracts, perhaps with a specified pricing mechanism for the gas. These possibilities did not provoke any response from the conference participants, other than one comment that a statutory standard of the review for the contracts might be helpful in improving the review process.

Other topics discussed during the conference included the fact that the utilities in general support RCA pre-approval of their gas supply contracts, prior to tariff approval, as an essential means of eliminating the significant financial risk that would otherwise result from the possibility of the commission rejecting a contract after a tariff has gone into effect. Some conference participants also expressed concern that a too broad participation in utility tariff hearings, including the involvement of entities with unclear or inappropriate agendas, had in some cases unduly increased the length and cost of the hearings.

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