When Marathon and ConocoPhillips asked the U.S. Department of Energy in January to extend their export license for the Alaska LNG plant from its current 2009 expiration date to 2011, most people seemed to support the idea. The Nikiski liquefied natural gas plant is a major economic driver on the Kenai Peninsula, which is part of Alaska’s Cook Inlet basin. Plus, the LNG facility was needed to support the economics of a possible future pipeline that would deliver gas to Southcentral from the North Slope.
But some of that support for an extension came with strings attached. The State of Alaska, for example, is concerned about gas supplies for Southcentral Alaska consumers and demanded cast-iron assurances from the two inlet gas producers that there would be enough natural gas for gas and electricity utilities. Their concerns were exacerbated by peak demand in the winter of 2006-07 during which gas supplies to some industrial gas users were cut in order to have enough gas for Southcentral consumers.
Supply assurances
The State of Alaska wanted those assurances to come in the form of Regulatory Commission of Alaska-approved contracts for supplies to the utilities and a commitment by the gas producers to maintain Cook Inlet gas reserves during the LNG license extension period, as per its subsequent filing on April 9 with DOE in regard to Marathon and ConocoPhillips’ application. And, to ensure an industrial gas market for all gas producers, the state also asked that the LNG plant to open its doors to the purchase of gas from producers other than the plant owners (see “LNG extension if…” in the April 15 edition of Petroleum News).
Chugach Electric Association concurred with the state’s views on the need for firm utility gas supply contracts. In its April 9 motion to intervene in the application, the major Anchorage-based electric utility, said “Chugach hereby asks DOE and its Office of Fossil Energy to approve the export application only if the applicants first give assurances, through contractual commitments, that local domestic supply and deliverability needs in Anchorage and the Cook Inlet region will be met for a reasonable future period.”
Enstar, the main gas utility in Southcentral Alaska, wants to see DOE enforce priority for local Alaska gas use over LNG exports.
“Enstar generally agrees with the (license extension) applicants that continued operation of the Kenai LNG facility would provide certain benefits to the regional community,” Enstar said in its April 9 motion with DOE to intervene. “… These potential benefits, however, will be of little value to Enstar or the region generally if there is insufficient gas available to meet the community’s needs, including the critical need for seasonal deliverability. … The Department of Energy must therefore either require the applicants to demonstrate conclusively that adequate supplies will be available or … require the applicants to limit their exports during periods when available supplies are unable to meet domestic demand.”
Gas for the fertilizer plant
Agrium, owner of the Nikiski fertilizer plant, objects to the license application because, the company says, the LNG plant would use gas that would be otherwise available for the manufacture of fertilizer at Nikiski. Because of lack of gas, the plant has been operating at half capacity and was shut down during the winter of 2006-07.
The fertilizer plant employs many more people, triggers more indirect jobs and contributes more to the local economy than the LNG plant, Agrium said in its April 9 motion to intervene. And, because the fertilizer plant manufactures product locally from the gas, DOE should view gas usage by the Nikiski fertilizer plant as local usage rather than usage for export, the company contends.
Agrium also asserts that Marathon and ConocoPhillips have significantly understated the gas demand from the fertilizer plant, in the data that the two companies presented to DOE in justification of the export license extension. The companies have assumed, on the basis of recent statements about the plant, that the plant would close at the end of 2007, but that in a high demand scenario the plant might continue operating at half capacity, as at present, Agrium said.
“Applicants have made a fundamental error in assuming that Agrium’s reduced consumption of natural gas in recent years reflects declining demand,” Agrium said. “… To the contrary, the only cause of Agrium’s reduced natural gas use has been a lack of available supply of natural gas.”
Tesoro, owner of the oil refinery at Nikiski, has also objected to the LNG export license extension, saying that the Nikiski refinery has already experienced cutbacks in winter gas deliveries because of gas supply shortfalls. The Tesoro refinery uses natural gas both as a fuel and as a feedstock for its hydrocracker unit.
“As the gas supply curtailments continued throughout November and into December 2006 (until around Christmas) Tesoro was forced to increase its electricity purchases, and divert normally valuable Kenai refinery products (such as ultra-low sulfur diesel, propane and butane) to use as Kenai Refinery fuel,” Tesoro said in its April 9 motion to intervene. “… During this period, Tesoro’s natural gas supply was reduced by 42 percent below its required volumes.”
Is there a shortage?
The various issues raised about the proposed extension of the LNG terminal all come down to one basic question: Is there enough gas available from the Cook Inlet basin, on and offshore, to supply both the LNG terminal and other Southcentral Alaska gas users?
For their export license extension application, Marathon and ConocoPhillips commissioned an analysis of Cook Inlet gas reserves by Netherland, Sewell and Associates, one of the world’s most respected consulting firms in independent reserve reporting. Its impressive client list includes DOE.
Netherland, Sewell’s analysis resulted in an estimate of 1.726 billion cubic feet of proved and probable reserves for the Cook Inlet basin (that estimate compares with a December 2005 estimate of 1,648 bcf by the Alaska Department of Natural Resources). And, according to an economic report by Resource Decisions prepared for the license extension applicants, the Potential Gas Committee, an independent entity linked to the Colorado School of Mines, has estimated a minimum volume of 600 bcf, and a most likely volume of 1,050 bcf of probable undiscovered economically recoverable Cook Inlet gas (according to the Potential Gas Committee analysis, those numbers increase substantially if you add in estimates for possible or speculative resources).
A Resource Decisions analysis of projected Cook Inlet gas demand, suggests that total cumulative gas usage between 2006 and 2011 will be 813 bcf, although in a high-demand scenario the demand figure could be 917 bcf. Both of these estimates are substantially less than the sum of the estimated gas reserves and probable undiscovered gas cited above.
The supply and demand estimates demonstrate that there is more than enough gas in the Cook Inlet to support LNG exports as well as local gas demand in the Cook Inlet area, on the assumption that new gas reserves would be developed in response to pricing and demand, the Resource Decisions report says.
“The data filed by applicants in support of their export application demonstrate that Cook Inlet natural gas supplies are more than adequate to satisfy both regional demand and the requested export volumes during the export term,” ConocoPhillips and Marathon said in their May 8 response to the comments by the various interveners. “No party has introduced — or suggested that it has any basis for introducing — any probative information to indicate otherwise.”
Utilities need to fix deliverability
The license applicants contend that, in citing recent Cook Inlet gas shortages, some of the interveners are confusing deliverability (the rate at which gas can be delivered at a specific time) with supply capability (the extent to which there is enough gas in the ground to meet demand over a period of time). In recent years there has been a deliverability crunch during peak winter demand, and that has resulted in some curtailment of industrial gas delivery.
But deliverability should primarily be the responsibility of the utilities, not the gas producers, ConocoPhillips and Marathon argue.
“Contrary to the claims of the state, Chugach, Enstar and Agrium, applicants are not required to demonstrate deliverability under DOE precedent, nor is there any compelling reason to require them to do so here,” the license applicants said. “In fact, DOE/FE (Fossil Energy) has recognized that responsibility for deliverability, including natural gas storage, lies with the utilities. … There has been virtually no direct investment by Enstar, Chugach or any other utility in deliverability projects. … Simply put, responsibility for fixing the system should not be demanded solely of (export license) applicants. Instead, market forces should be allowed to implement a natural gas supply system that specifically addresses base load, peak and needle peaking requirements.”
No enforced supply
And the applicants dismissed as unwarranted interference in the gas market any question of enforced gas supply contracts or the mandatory diversion of gas from the LNG plant to meet peak demand.
“These arguments are nothing more than an attempt to use the Natural Gas Act section 3 public interest standard to create a right of eminent domain to take natural gas from applicants’ export operations for the private use of Chugach, Enstar, Tesoro and Agrium,” the applicants said (the Natural Gas Act section 3 says that DOE must grant an export license unless the export “will not be consistent with the public interest”).
The existence or absence of contractual agreements for the supply of gas to utilities relates to the commercial dealings of private businesses and not to the question of whether enough gas exists to supply the market, ConocoPhillips and Marathon argue. Any attempt to enforce a contract that, in effect, sequesters gas for a local gas user, would result in gas prices at below market levels, at the expense of the LNG exporters and to the potential detriment of future investment in gas exploration, the companies said.
“Although the state’s argument may be consistent with its desire to achieve an artificially low natural gas cost for Alaska consumers, it has nothing to do with whether or not there is sufficient natural gas supply to meet both utility and export requirements,” the two companies said.
Market supply issues
ConocoPhillips and Marathon also lambasted Agrium’s arguments regarding gas supply shortages at the Nikiski fertilizer terminal, saying that Agrium is short of gas because the company is trying to obtain gas at below-market prices.
“Agrium’s situation is more indicative of commercial decision-making than a lack of available natural gas,” the applicants said. “Agrium fails to discuss the fact that its level of operations is impacted by both the price of natural gas in Cook Inlet and the price of fertilizer in the world marketplace. Hence, Agrium’s commercial interest lies with depressing the cost of natural gas feedstocks in order to maximize its profit margins on fertilizer sales.”
For similar reasons, the applicants dismissed Tesoro’s objections to the LNG export license extension — Tesoro has chosen not to obtain a gas supply contract that guarantees supply, the applicants said. Tesoro is now trying to use the export license issue as a means of ensuring firm gas supplies at low cost, they said.
“Tesoro need not contract with any natural gas supplier on a ‘firm’ basis as it can always switch to alternative fuels (such as propane, diesel etc.) to fuel its operations,” the applicants said. “It is clear that such fuel-switching capability allows Tesoro to enjoy cost savings as it permits Tesoro to contract for natural gas on a non-firm basis. … Tesoro presumably sought to trade-off security of supply for economic benefit.”
No enforced exploration
ConocoPhillips and Marathon also rejected the state’s call for exploration investment that would ensure maintenance of the Cook Inlet gas reserves during the period of the LNG export license extension.
“Exploration and production decisions should be influenced by market forces, not regulatory fiat,” the companies said, adding that a stipulation of this type could result in an open-ended financial obligation for the companies, were exploration wells not to encounter gas.
“In addition, the state’s condition would require that investments be made whether or not they are required to meet contractual demands and regardless of economic merit,” the companies said. “This places a unique and unfair economic penalty on applicants.”
And the companies also rejected the state’s call for open access to the LNG terminal for the sale of gas from producers other than the terminal owners. The Federal Energy Regulatory Authority, not DOE, has jurisdiction over whether the terminal should have open access, and “by law and policy, open access is not required by FERC of any new receiving terminal in the Lower 48 states,” the companies said.
Purchase of third-party gas for the terminal only makes sense if the terminal has capacity for the gas and satisfactory commercial terms for the purchase can be reached.
“Purchase and sale arrangements must be left to voluntary, arms-length negotiations between the affected parties,” the companies said.
