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Gas project proponents square off Advocates of four plans to commercialize Alaska North Slope gas pitch their projects to Commonwealth North Kristen Nelson Petroleum News Editor-in-Chief
It all boils down to answering some basic questions: Who? What? When? Where? And, of course, how much — how much money will it cost and how much gas will it move?
Proponents of four projects to move Alaska North Slope natural gas to market summarized their projects — and answered questions — at a meeting of Commonwealth North Feb. 27 in Anchorage, Alaska. The Anchorage-based public policy group also provided answers to questions the organization had asked proponents in advance of the meeting.
These are all projects that would bring North Slope natural gas south through Alaska. The Alaska Legislature has said the state will not allow an “over-the-top” route taking gas east across the Beaufort Sea and then south through Canada.
That said, there are a number of questions which have not yet been resolved:
• Is the project economic?
• Will Alaska’s North Slope natural gas reach markets in this decade, or not until the next, and how much gas will be shipped — 2 billion cubic feet per day, 4.5 billion or 6 billion?
• Will the gas go primarily to Midwest markets or will portions go to the West Coast, or even to the Far East, and will the gas leave Alaska in a pipeline or on liquefied natural gas tankers — or both? Will there be just a pipeline to Alberta, or a “Y-line” with branches to both Canada and Valdez? And what about a spur to Southcentral Alaska?
• If there is a pipeline taking gas to a liquefaction plant to be chilled and pressurized into LNG, will that line go to a new LNG plant near Valdez or to the existing ConocoPhillips-Marathon LNG plant north of Kenai?
• What about the sequence of projects: should a line be built first into Canada, with a later spur to tidewater within Alaska, or first to tidewater, or simultaneously into Canada, to tidewater and to a connection with the existing Southcentral distribution system?
• Who will build the pipeline — the North Slope gas producers, a pipeline company, a municipal port authority or a state gas authority — and will Alaskans own a piece of the pipe?
• Will the cost for the project be $12 billion, $14 billion, $19 billion or $26 billion?
• What will be included in the project: new pipe all the way into the Midwest or just into Alberta; an LNG facility at Valdez; a liquids extraction plant; and who will build the gas treatment plant on the North Slope? All projects head south — initially All of these projects head south from the North Slope initially, taking North Slope natural gas by pipeline along a route similar to that already used by the trans-Alaska oil pipeline. Some 500 miles south of the North Slope, however, differences appear.
“Our project is basically a three-line project,” said Dave Dengel, executive director of the Alaska Gasline Port Authority. A pipeline runs “from the North Slope to Valdez for LNG,” he said, but with this Y-line concept the line splits at Delta Junction and one pipeline continues to the Canadian border while the other heads south to Valdez, with a spur line coming off at Glennallen to connect to the Southcentral Alaska gas grid.
Ken Thompson of Pacific Star Energy, representing the Alaska Gas Transmission Co., said that company would “design, construct, own and operate this line from the North Slope to the Alaska-Yukon border” where it would meet up with a Canadian line to be built by TransCanada.
The Alaska Natural Gas Development Authority, said its chief executive officer, Harold Heinze, was “specifically authorized by the ballot measure” to build a gas pipeline from Prudhoe Bay to Prince William Sound, with “a spur line coming from Glennallen into the Sutton area so that the Cook Inlet area could be supplied with gas, also.”
Ken Konrad, gas performance unit leader for BP Exploration (Alaska), said the producers’ project is a pipeline through Canada to the North American market. Both gas and LNG proposed Some projects are all pipeline gas, some a mix of pipeline gas and LNG.
“Our project is really all about a large-diameter, high-volume, high-pressure gas pipeline to serve North American markets,” BP’s Konrad said of the producers’ plan. “The North American market is the biggest, deepest, most vibrant gas market in the world. It’s clearly the place we want to sell our gas, and we think … using a leading-edge technology gas pipeline is clearly the lowest cost way to get that gas to market.”
The ballot initiative establishing the development authority, Heinze said, authorized a line to Valdez where gas would be liquefied and shipped by LNG tanker, and included the spur line to bring pipeline gas into the Southcentral grid. LNG would go both into the Pacific Rim — Japan, Korea and Taiwan — and to the West Coast of North America, the development authority said in its prepared response.
Alaska Gas Transmission will deliver pipeline gas “to Canada and the Lower 48 markets,” Thompson said.
And the port authority project would deliver pipeline gas to the North American market and LNG from Valdez to the Pacific Rim and West Coast. How much gas would be shipped? The port authority proposes to ship the largest initial amount of gas, 6 billion cubic feet a day, it said in its written responses, “with necessary flexibility in the allocation between an LNG pipeline, a gas pipeline to the Canada border and a gas pipeline to the Southcentral gas grid.”
Alaska Gas Transmission is proposing 4.5 bcf, but Thompson said deliveries are expected to “grow substantially,” to 6 bcf.
The Alaska Natural Gas Development Authority plans a 2 bcf a day line, the authority said in its written responses, and said that with additional compressor throughput could be increased to 3 bcf a day.
The producers said in their written response that their “preliminary design” is for approximately 4.5 bcf a day “at the inlet of the gas treatment plant on the North Slope” but has the potential to be expanded to 5.6 bcf a day.
They questioned higher initial delivery rates. Joe Marushack, vice president Alaska North Slope gas commercialization for ConocoPhillips Alaska, said the producers think initial delivery rates of 6 bcf per day are “unrealistic” because the known resource on the North Slope is only 32 trillion cubic feet, and to deliver 6 bcf a day over a 30-year period would require a resource of 66 trillion cubic feet. “So we think an initial base project without exploration of 6 bcf a day is … unrealistic.” And how much will all this cost? Pricing for the projects varies a good deal, with part of the variation due to differences in the projects.
Konrad said the producers’ project would cost about $19 billion: $2.3 billion for the gas treatment plant on the North Slope; $4.4 billion for the Alaska segment of the pipeline. In their written response the producers said the total pipeline cost would be $11.8 from Alaska to Alberta, a natural gas liquids plant would cost $400 million and the pipeline from Alberta into the U.S. Midwest would be $4.5 billion.
Heinze said the development authority is looking at a $12 billion project. In its written statement the development authority broke that amount down into: $2 billion for a gas treatment plant on the North Slope; $4 billion for a gas pipeline to Valdez; $4 billion for the LNG plant; $2 billion for LNG tankers; and $300 million for the spur line to Southcentral.
Alaska Gas Transmission is proposing a project that totals some $13.8 billion. Thompson said the Alaska portion of the gas pipeline would cost $6.3 billion, the Canadian segment of the line $5 billion and the gas treatment plant on the North Slope roughly $2.5 billion.
Dengel said the port authority project, at $26 billion, is a “not-to-exceed” cost estimate and “includes all the costs, all the short costs and all the hard costs…” In its written response the port authority noted that this includes “pipelines to both Valdez and the Canada border, and additional statewide distribution system through the Mat-Su to Southcentral.” Who cares what it costs? The cost issue isn’t just a numbers game: the cost of the project directly affects the tariff, the fee companies will pay to move natural gas on the pipeline. The higher the construction cost, the higher the tariff. The higher the tariff, the lower the wellhead value to the producers and to the state, which has royalty gas to move — and the lower the taxes the state will collect on the value of the gas shipped.
Asked how confident they were, on a scale of 1 to 10, of their numbers, the port authority and the development authority were the most confident, the producers the least confident.
Dengel said the port authority has a “high level of confidence,” a 10 on a scale of 1 to 10, based on the more than 55,000 man hours Bechtel Corp. put into the numbers and because the construction cost is a “hard bid number that if it goes over, the contractor will absorb that cost.”
Thompson said he hadn’t asked MidAmerican about their level of confidence in the numbers, but noted that Alaska Gas Transmission has a technical agreement with TransCanada, which “has spent over $400 million in regard to cost estimates and all the issues related to the pipeline in Alaska, as well as the Canadian segment.” And, he said, MidAmerican has assigned a project team “comprised of two executives that worked on the Taps oil line with Bechtel and other companies, so they know and understand Alaska” and “handpicked some of their best from their various affiliate companies and assigned (them) to this project, which is a sign I look for.” He said that while he hadn’t asked David Sokol, CEO of MidAmerican, about the number, based on what he knew of the project, “and on a scale of 1 to 10 of the people they’ve assigned to this, I would definitely rate that as a 10 or close…”
Heinze quipped that “if it was me I’d probably be a 13, but since it’s the state, and I represent you all, it will be an ‘8’ — that’s probably a little more realistic. He said the development authority’s confidence in its numbers is based on the years Yukon Pacific spent studying a standalone LNG project. “And that design has been made available to us to look at” and, since it follows the trans-Alaska pipeline route, “there are basically no unknowns.” Heinze noted that since Yukon Pacific did its work there have been breakthroughs reducing the cost of liquefaction plants. And, he said, another thing that adds to his confidence “of both economics and in terms of the judgments that are being made,” is that Shell is spending $10 billion in Sakhalin to develop about half the volume the authority would produce.
ConocoPhillips’ Marushack said the producers have “a million man hours into this project,” with $125 million spent recently “plus some individual work that’s being done on this,” plus the experience they have building projects on the North Slope and building mega projects worldwide. “We’ve got a cost estimate that’s maybe plus or minus 20 percent,” he said. “We are at least a 4 out of 10 and I really, really question how anybody could be much more than that.”
BP’s Konrad agreed. There is still a lot of work to be done, he said. “We’ve clearly done more work than anybody, but there’s a long ways to go for all parties up here.” Producers, others disagree on how long it will take It was three to one on how long it will take to get the project to market, with the producers in the minority.
The port authority said in its written response that its project would be up in “approximately 2009/2010.”
Thompson, speaking for Alaska Gas Transmission, drew a chuckle when he said: “Of course, this is dependent on regulatory approvals and successful commercialization, (but) we’re targeting December 31st at noon, 2010, for gas sales.”
Thompson said “an early in-service date” is “going to be very important,” and said Alaska Gas Transmission believes a gas line from Alaska will “moderate U.S. gas prices for all consumers, as well as provide some energy security benefits” for the United States and maximize value for the state of Alaska.
Thompson argued the 2010 date was feasible. He said Alaska Gas Transmission has a technical agreement with TransCanada, which has been working on both the Alaska and Canada segments of the project for the last 15 years, to share information.
And MidAmerican Energy’s affiliates in the gas transmission business “own today and operate over 18,000 miles of interstate natural gas transmission lines — the second largest in the United States in terms of gas transmission.”
In May 2003, he said, MidAmerican Energy affiliate Kern River Gas Transmission “completed the largest diameter and largest natural gas expansion project that’s been undertaken in the last 10 years in the U.S. With that Kern River line in California, it had a $1.2 billion expansion. It was completed within nine months, it was on schedule and it was $79 million under budget.”
The Alaska Natural Gas Development Authority said in its written responses that it was targeting to have the project in full operation in 2009.
BP and ConocoPhillips said in their written response that they believe: “It will take about 10 years to plan, engineer, construct and start up a gas pipeline project once the necessary state and federal government legislation is secured.”
“This project will be won or lost in the front end … Errors can cost billions,” said ConocoPhillips Alaska’s Marushack, and reminded the audience of the $800 million trans-Alaska oil pipeline project, which ended up costing $8 billion.
Marushack said the parts of this project — the plants and pipeline segments — are so large each “is a world-scale project by itself,” and coordination is necessary in “logistics, procurement, construction, labor, environmental commit (and) stakeholders’ (issues) … (because) each of these projects has the potential to move the markets in terms of labor and market supply, so we’ve got to optimize.”
He said these cost overrun and coordination issues “are in direct conflict with fast tracking and taking short cuts.”
In “a project of this size and complexity, imprudent speed will destroy all potential value,” Marushack said.
He also said he is “very suspect about those schedules that are clearly not achievable and introduce additional risk…”
The producers have done work on feasibility, he said, and have worked on other large projects, and think it will take about 10 years from approvals before the first gas moves through a line. Projected wellhead price for natural gas? All of the participants were asked what they expect the wellhead price of the gas will be, the price that the producers — and the state for its royalty gas — get from a natural gas sale.
“The equation is wellhead equals market less tariff,” said ConocoPhillips’ Marushack. “And the tariff has to be all the way to the market, not Alaska border, not somewhere else, all the way down to the market.”
“All of us are price takers, none of us are price makers,” he said, and over the last 10 years the market for natural gas “has averaged a Henry Hub price of $3.07.” We’ve quoted a tariff at around $2.50, Marushack said, so that would leave about 50 cents at the wellhead, and “that’s not adequate.”
Over the last two, two and a half years, however, “the average market price has been bumping up against $5,” a much better number. But, Marushack said, “we need a project that works in any environment,” because if prices go back down you could be in a situation where you’d cover your tariff, but that’s all.
“Well I have no idea what the wellhead is going to be, because I have no idea what the market price is going to be,” said the development authority’s Heinze. He said projects need to be tested “against the price of gas that makes sense, and most of the people I know believe that in the long term the test for economics of these gas projects, all around the world, is somewhere in the range of $3 to $3.50 in the marketplace.”
That range is used, Heinze said, because that range is quoted for delivery of gas from Qatar. “They have 900 trillion cubic feet — that’s the 8,000-pound gorilla if you will of the gas world,” he said. He said the $3-$3.50 number is what he used to reflect the general view. “At times when prices are better than that, somebody’s going to realize a lot of extra money above and beyond that. How that’s split, how that’s shared, what it’s used for, all those things, I think is to be worked out through the negotiations,” he said.
Thompson, speaking for Alaska Gas Transmission, said he didn’t have a specific wellhead price, and agreed with Heinze that it’s based on market price. He said the goal at Alaska Gas Transmission is to have the lowest tariff possible, because the lower the tariff is, the most likely the producers and the state are to go with the Alaska Gas Transmission project.
The Alaska Gasline Port Authority has said that at a certain price it would pay $1.48 at the wellhead, Dengel said, “but if the price of gas in Chicago drops substantially, so would the wellhead price that would be paid for gas on the slope.” One of the advantages of the port authority project, he said, is that because they plan to sell both LNG and pipeline gas, the longer-term LNG contract prices would help level out any spikes in the shorter-term market for pipeline gas into Chicago. What are the hurdles? One of the questions Commonwealth North asked was: “What are the principal hurdles your project needs to overcome?”
Not surprisingly, a commitment from the North Slope producers to sell gas or to ship gas showed up on two lists, while “commercialization of the project” on the third non-producer list probably could be construed to include the same item.
BP and ConocoPhillips listed “a clear and durable fiscal contract with the state of Alaska, a federal fiscal mechanism in the U.S. and efficient regulatory frameworks in the U.S. and Canada.”
Asked what it would take for them to sell gas, BP’s Konrad said, “I think what we need is a credible party with a credible engineering estimate and letters of credit, because there’s going to be lots of risk in an exchange we do negotiate with anybody, so there’s no sense in negotiating with somebody unless there’s confidence that either side can pay the other side in the event that things don’t quite work out.”
Standard for a gas pipeline would be “take or pay, long-term commitments,” he said.
“Provided they’ve got a letter of credit that says they’re willing to stand behind their pen, then let’s do business.”
ConocoPhillips’ Marushack said cost overrun potential on big projects is a real risk, so the gas owners would have to be very comfortable that cost terms could be met. “After that, it’s just depending on the terms and the time.
“The gas is for sale. The gas has always been for sale,” Marushack said.
“But we’ve got to have a project that makes sense.” And, he said, “we’re looking at the lowest cost possible tariff. When folks come to us and want to buy the gas, we’re going to have to be very comfortable that that’s the tariff that you end up with, that it doesn’t blow up and you get twice the cost. Because gas isn’t like oil,” he said, there are “very small margins on gas, generally.” Who would build what? BP and ConocoPhillips described their project in their written response as including approximately 3,600 miles of pipeline with 1.2 million to 1.4 million horsepower of compression required to deliver natural gas from the North Slope to U.S. upper Midwest markets. BP’s Konrad said a gas treatment plant would be needed on the North Slope to remove carbon dioxide, compress and chill the gas, and “a natural gas liquids treating plant located somewhere along the line, probably in Alberta, that is to reduce the Btu level of the gas down to a level that is saleable into the market.” Of the four elements, Konrad said, the pipeline from Alberta into the upper U.S. Midwest might not be needed. “There’s a possibility that there will be excess capacity on existing infrastructure at that point in time. Existing infrastructure could be expanded. Some combination of those three — new build, excess capacity, expansion — will take the gas out of Alberta and the market will decide what the lowest cost way out of that basin is.”
The Alaska Natural Gas Development Authority project also involves four major components: a gas treatment facility, the pipeline, the LNG facility and the tankers.
“It may be that the authority is not involved in all four of those components,” Heinze said. “It may be that the producers, for instance, are involved in gas treatment on the North Slope. And we certainly don’t intend to own tankers.”
And it may be, he said, that the authority wouldn’t even be involved in the pipeline, maybe it’s just involved in the liquefaction plant, “maybe it chooses to perform that service at basically no margin, just at cost, like building a highway.
“Why would we do that? Because that’s the same thing that happens in Indonesia and other parts of the world that we compete against.” Heinze said that is one of the things on the table.
“We are not in competition with anybody,” he said, and will only “take on those things that we can uniquely do better than someone else,” because the authority is a public corporation of the state, not a profit-making organization.
Alaska Gas Transmission company’s plan goes only to the Alaska-Yukon border. The company said in its written answers that it “envisions that a gas conditioning plant be constructed and owned by the ANS producers,” and plans just to build the pipeline from the North Slope to the Yukon border, where it would connect with a pipeline built by TransCanada.
The Alaska Gasline Port Authority project is the largest, with pipelines from the North Slope to Valdez, a line from Delta Junction to the Canada border and from Glennallen into the Matanuska-Susitna Borough, an LNG plant and a gas conditioning plant. What about the financing The port authority plans to use debt financing for 100 percent of the project. Tax-exempt bonds would be issued for that part of the project providing gas for in-state use, estimated at 10 percent, the authority said in its written responses.
Alaska Gas Transmission’s equity investors are MidAmerican Energy Holdings, 80.1 percent, Cook Inlet Region Inc. 9.95 percent; Pacific Star Energy 9.95 percent. The company said in its written response that a final financing plan is not available, but it “is interested in pursuing tax-exempt financing.” Thompson told Commonwealth North that MidAmerican Energy Holdings is an affiliate of Berkshire Hathaway, which has “220 billion in assets, very little debt and $26 billion in cash.
“So this is a project of great interest … as an investment,” he said.
Thompson also said that because “Alaskan companies have been brought in, Alaskans will own a piece of the pipe this time, at just under 20 percent.
“This changes the fundamental business model from service and support to equity ownership for Alaskans,” he said. “Equity ownership brings the real wealth in any natural resource industry, and we’re excited to be part of it,” Thompson said.
“The equity element of financing could be zero if we adopt a state infrastructure approach to bonding,” the Alaska Natural Gas Development Authority said in its written response. “A number of bonding consultants have indicated that multi-billion dollar bonding of a gas project is possible,” the authority said.
Heinze told the Commonwealth North audience that because of the authority’s “unique tax status, its unique financing status,” it may be that the authority would treat infrastructure needed to commercialize North Slope gas the way a state treats a highway: “We go out and issue bonds, we retire the bonds and that’s it. We believe that the economic activity we create pays for them.”
That approach, he said, could drop the tariff cost by as much as a dollar.
BP and ConocoPhillips said in their written responses that it is too early to identify equity investors, but that “potential investors must add value and accept the project risks, not simply pass the risks through to the resource owners.”
And, the companies noted: “Regardless of the source of the financing, the project sponsors/producers are the ultimate credit standing behind the pipeline, either through direct investment or supporting with a throughput and deficiency commitment.
“If the project has this backing, we are confident that appropriate financing will be available.”
ConocoPhillips’ Marushack said that people seem to want to address financing first, “but it’s actually a second-tier issue.”
Financing doesn’t make a project work, he said. “Attractive projects stand on their own merit and their own capital.”
And as for all-debt financing, he questioned that concept: “Why would any financier lend money to a massive project if the sponsors weren’t going to do so themselves? We have a lot of experience in project financing and this leads us to put little stock in any sort of 100 percent financing scheme. Equity is the shock absorber … that addresses financial distress and makes creditors comfortable the project sponsors are serious and committed,” Marushack said.
The producers are, however, interested in loan guarantees or Alaska Railroad based funding that has “the potential to reduce the interest rate and make the project tariff a bit lower.
“At the appropriate time, all financing issues have to be addressed,” he said, “but financing is not going to be the panacea to compensate for any fundamentally weak project.”
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