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Vol. 11, No. 36 Week of September 03, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

AGPA aims for early start

Econ One: Without 3-year head start, economic value of LNG project can evaporate

Kristen Nelson

Petroleum News

As the Alaska Gasline Port Authority project economic compared to a highway project?

The Alaska Legislature asked Econ One Research to do an analysis of the liquefied natural gas project and Aug. 24 and 25 in Fairbanks the Senate Special Committee on Natural Gas Development heard the results.

Tony Finizza told legislators that while a 4.3 billion-cubic-foot-a-day natural gas highway project has a higher netback than LNG delivered to the West Coast, if the port authority can get gas to market three years before the highway line the lower netback for LNG is more than offset by the net present value of monetizing gas early.

That advantage disappears if the LNG component is delayed, said Finizza, an Econ One consultant and chief economist for ARCO from 1975 to 1998.

Project description

The port authority, represented by its board chairman, Jim Whitaker, mayor of the Fairbanks North Star Borough, attorney Bill Walker and Radoslav Shipkoff of Greengate LLC, financial consultant to the port authority, told committee members it proposes to build a big gas line from the North Slope to Delta Junction and a smaller line to Valdez. It would only move 1.2 bcf a day of gas for liquefaction and delivery to the West Coast as LNG.

The main line from the North Slope to Delta Junction would not be full until the highway project is built, which the port authority estimates would be at least three years later.

Major points in the wide-ranging discussion, which included the port authority, legislators, Murkowski administration officials, producers and consultants, were as follows:

• whether the port authority project would be subject to Federal Energy Regulatory Commission jurisdiction;

• whether the port authority project could deliver gas at least three years before a highway project;

• whether financing could be obtained without a ship-or-pay contract, long-term impacts of beginning gas shipment with the LNG project, and;

• how returns would compare to those from a highway project taking natural gas to Lower-48 markets in the Midwest.

Three-year head start crucial

The port authority would ship 1.2 bcf a day to Valdez for LNG.

Finizza looked at two port authority options once the highway segment was complete: 4.3 bcf with 1.2 bcf going to Valdez and 3.1 bcf going to the Lower 48 and 5.5 bcf with 1.2 bcf going to Valdez for LNG and 4.3 bcf going down the highway pipeline.

Finizza said the LNG segment offers a lower netback than the highway project, but the three-years of early cash flow produces a better net present value than just the highway line.

If the LNG project doesn’t start until the highway project, however, the combined net cash flow is below that of a highway project alone, and the economic value of an LNG project can evaporate, Finizza said.

Rep. Ralph Samuels, R-Anchorage, said he recalled TransCanada telling legislators that below 3.3 bcf the economics of a highway line fall apart: if you took 1.2 bcf for an LNG project out of 4.3 bcf, you could hurt the highway economics. If 3.1 bcf a day is not economic for the highway project and you can’t get an off-take rate of 5.5 bcf, then if you start with 1.2 bcf on LNG, that’s all you get, Samuels said. If you can’t take 3.3 bcf it’s not economic until you discover more gas, but there won’t be gas exploration without a gas line.

Finizza said he thought Samuels had identified a risk.

Port authority would amend YPC permits

The port authority believes its access to permits developed by Yukon Pacific Corp., which the authority doesn’t believe would take long to amend, provide the earliest opportunity to provide gas to Alaskans. Gas could be flowing by 2013, Walker said.

Samuels asked about FERC regulation and Walker said a pipeline owned by the port authority would be FERC-exempt because of its status as a municipality.

Shipkoff said downstream of Valdez components of the project would be regulated by FERC. He also said if the port authority owned the conditioning plant on the North Slope that would also be FERC-exempt.

The FERC process for an environmental impact statement and a certificate of convenience and necessity is expected to take a substantial amount of time, and gas pipelines cannot begin construction until they have completed FERC certification.

Sen. Ralph Seekins, R-Fairbanks, the committee chair, said FERC told the committee its permitting timeframe is at least 48 months. Seekins does not believe FERC is going to ignore one of the largest gas projects.

Walker said the port authority has been talking with the U.S. Department of Energy, and has assured FERC it’s not out to do battle with them.

Price makes project work

Shipkoff said the port authority’s numbers show the project to be commercial, and called it a project ready to proceed.

The LNG project will carry the costs of a line sized for the highway project to Delta for three years. That is possible because of current prices, he said.

The reverse does not hold true. He said if the highway project goes first, LNG would have to wait and by the time the highway project was completed, LNG markets would be lost.

Shipkoff said the port authority has been asked, if you have such a good project, why aren’t the producers coming to you, and he said the port authority believes that when the producers are ready to seriously consider a project out of Alaska they will implement an LNG project.

Samuels asked about the risk if gas prices dropped dramatically.

Shipkoff said the port authority has proposed a netback purchase agreement. If gas prices drop to $2, he said, the producers would shut in the wells and the investors would absorb the loss. The question is can you convince investors to commit money, he said, noting that the port authority believes it’s a remote possibility that the gas price will drop. Many multi-billion-dollar projects which “look just like ours” are proceeding, he said.

Seekins asked whether the port authority anticipated ship-or-pay contracts and Shipkoff said that would depend on the outcome of discussions, but the proposal was netback with just performance risk for producers.

Seekins said it had always been his assumption that it would be very difficult to get financing without ship-or-pay contracts and asked if the port authority was saying that the federal loan guarantee would act as a guarantee so ship-or-pay contracts wouldn’t be required.

Shipkoff said that would have to be negotiated, but said government backing of private loans is common and while ship-or-pay commitments are a very common way to provide surety they are not the only way: lenders have accepted alternate arrangements, he said.

An issue of risk

Steve Porter, deputy commissioner of the Alaska Department of Revenue, said the port authority project is important to the state, and thinks it is important to the state to understand the project.

It is also important to understand the risks to the state, he said, quoting from a book on mega-projects and risk to the effect that project promoters are happy to go ahead with highly risky projects as long as they themselves do not carry the risk and are not responsible for cost overruns.

The key, Porter said, is to track risks and costs. True believers sometimes emphasize the positive over the negative, he said, calling the port authority “quite optimistic” and saying the port authority “generally has no risk,” but would transfer that risk to the producers, bond holders or downstream, taking incremental benefit without shouldering risk.

When you transfer risk, Porter said, you transfer costs: if you transfer the risk to the bondholders, the bonds are going to cost more.

Bechtel, which did cost estimates for the port authority, looked at a turn-key project, he said. That’s a fair approach, but leaves money on the table and the producers are looking for leakage — where does money leak from their project? They’re not going to like turn-key, Porter said, because it can add cost and make the tariff higher.

Shipkoff said some of the extra cost that came with the turn-key approach has been stripped out of the port authority’s numbers; without turn-key, he said, the project takes on that risk of cost overruns.

Whitaker said North Slope producers BP, ConocoPhillips and Exxon are transferring significant risk to the State of Alaska through the fiscal contract they negotiated with the Murkowski administration. He told the committee that he thought the plug should be pulled on that contract.

How likely is three-year head start?

Roger Marks, an economist with the Department of Revenue, asked Finizza how plausible he thought it was the port authority could begin production three years before a highway line and Finizza said he’d taken that as a given.

Marks said he questions how plausible it is.

He also said the administration believes the port authority will be under FERC jurisdiction. Projects within municipalities could be FERC-exempt, he said, but a project for inter-state transportation of natural gas would be under FERC jurisdiction.

Marks said for a 4 bcf pipeline to Delta Junction with 1 bcf going to Valdez and no commitment for the other 3 bcf he didn’t think FERC would allow the tariff to cover the cost of the remainder of the pipe.

Shipkoff said the port authority had asked its FERC counsel for an opinion on that issue, even though the port authority doesn’t think it would be under FERC jurisdiction. The port authority wouldn’t build a pipe bigger than needed to go to Valdez, he said, unless it had an agreement with the producers to build the larger pipe to handle a future highway project. There would be a negotiated rate, and he said he didn’t believe FERC would disallow a negotiated rate. FERC has agreed to sizing pipe to allow for future volumes and he said the port authority’s FERC counsel didn’t think FERC would approve a line that wasn’t large enough to allow for future volumes.

Producers disagree

In response to the assertion that all parties to the deal might approach FERC supporting an LNG-highway Y-line as the best commercial deal, BP Exploration (Alaska)’s gas commercialization manager Dave Van Tuyl said “all parties do not believe this is the best commercial deal.”

Van Tuyl said the cost of delivery for LNG is higher than for pipeline gas and markets are not known. The LNG project has a higher cost and would reduce the highway volume, making the combination project worse than a highway gas pipeline.

Marks said the very small limited West Coast market for gas is a concern with the LNG project. He said gas sells for 50 cents less on the West Coast than in Chicago, noting that the need for gas is in the upper Midwest, not on the West Coast.

On that same issue Porter said that if the profit on gas going through Canada is $2 and the profit from LNG is $1, then LNG is not producing the maximum value to the state. It’s not that you couldn’t make money on 1.2 bcf for LNG, he said, it’s that it’s more economic — you make more money — taking the gas through Canada.

Conflicting views on role of FERC

Counsel for the legislative committee told members that FERC would likely allow a larger line to be built, but would require investors to eat the cost of the entire line until it was full. Van Tuyl said BP’s FERC attorney had a very similar response.

Shipkoff again said the port authority wouldn’t build the pipeline in isolation. There will be a commercial agreement with the producers, he said. He didn’t think FERC would overrule a commercial agreement.

Seekins asked if the port authority has had talks with the producers on a commercial agreement and Shipkoff said the port authority would like to engage in such talks, and that it wouldn’t have a project without discussions.

Whitaker said there’s no conversation if there’s no gas. He said if the Legislature would exercise its responsibility it could make the gas supply available.

Seekins said he appreciated the state’s responsibility, but thought it would be best if the port authority tried to cut a commercial deal.

The committee’s counsel said the more he thought about it, the more convinced he became that FERC would take control of a port authority project. The Energy Policy Act of 2005, he said, strengthened FERC’s authority over LNG projects.

He said FERC is saying that a municipality is not subject to its authority, but if a municipality chooses to do things within FERC’s authority — such as move gas in inter-state commerce — then that project would come under that authority.

FERC has said once you come to “our party” you have to abide by “our rules,” he said.

Walker said because the port authority has kept its ownership within the state, it is FERC exempt. He said the authority can get a declaratory order that it is exempt and plans to sit down with FERC in the next 30 days and discuss the issue.

Three years not FERC-related, says Walker

Seekins said he didn’t wish FERC on anyone, but if the port authority is not exempt, he asked, does its advantage disappear?

Walker said the authority’s three-year time advantage comes from the Yukon Pacific work and is not FERC related.

Marks noted that the Yukon Pacific environmental impact statement was done 20 years ago for a non-FERC project, a different project than this one. An EIS under FERC would add two years, he said, questioning whether a 20-year-old EIS would be considered out of date.

The committee’s FERC attorney said there is explicit timing in the 2004 act for an EIS; if the old one were sufficient that wouldn’t be in the act, he said.

Walker agreed that permits would need updating, but said the port authority does not believe it will have to start over.

Commitment same as debt

Sen. Gene Therriault, R-North Pole, asked Van Tuyl why, since companies make commitments to ship on other pipelines, that this one is different.

Van Tuyl said it’s the same for everything they invest in: auditors treat it as debt. They are real obligations and need to be counted, he said.

Dan Dickinson, formerly director of Revenue’s Tax Division and now a consultant to the department, said the effect of long-term financing is the same for the company as if cash came out of its pocket.

On costs, he noted that Bechtel did some 55,000 hours of work on the port authority project while the producers have done more than a million hours. Neither of the cost numbers is the final number Dickinson said, and further technical work on both projects may make a difference in either narrowing or widening the cost gap.

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MMS includes Chukchi in new five-year plan

Alaska would see federal outer continental shelf lease sales in four areas under a proposed five-year plan and draft environmental impact statement issued Aug 24 by the Minerals Management Service.

The Chukchi Sea has the most proposed sales in the Alaska OCS — Sale 193 in 2007, Sale 212 in 2010 and Sale 221 in 2012. MMS said the Chukchi Sea sale area has been modified from the draft program it issued in February: a 25-mile buffer area along the coast has been removed from the proposed program, since there is no existing oil and gas activity in the area and the State of Alaska made no request to include leasing closer to shore.

Two Beaufort Sea OCS sales are proposed, Sale 209 in 2009 and Sale 217 in 2011.

There are two Cook Inlet sales on the proposed schedule, Sale 211 in 2009 and Sale 219 in 2011, but MMS said the Cook Inlet planning area is included as a special interest sale, which will take place only if enough interest is shown by industry in answer to a nomination call.

The North Aleutian basin also appears on the proposed sale schedule.

MMS said Alaska Gov. Frank Murkowski and the majority of local governments and tribal organizations requested that proposed sales in this area take place only in the area offered in Sale 92, held in 1988. The North Aleutian basin planning area is currently withdrawn by presidential order under section 12 of the OCS Lands Act, MMS said, but the governor has requested that the president modify his withdrawal to allow sales in the Sale 92 area. If held, those would be Sale 214 in 2010 and Sale 223 in 2012.

The Department of the Interior’s MMS said the second draft of the new leasing plan would succeed the plan expiring on June 30, 2007. The agency will accept comments through Nov. 24; the draft EIS is open for comment until Nov. 22.

—Kristen Nelson