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North Slope gas producers team challenges governments to get onboard Risk and reward different for pipeline than for overall gas commercialization project, BP’s Konrad tells Resource Development Council’s annual conference Kristen Nelson PNA Editor-in-Chief
The Alaska North Slope gas producers’ team is close to completing the work it set out to do in 2001, but needs cooperation of governments to move the work forward, the team’s leaders told the Resource Development Council for Alaska’s annual conference in Anchorage Nov. 29.
Robbie Schilhab, business development manager for ExxonMobil, said the team is completing the conceptual design work, and by the end of the fourth quarter, can start working on the economic analysis and putting together draft environmental reports.
In the key technical area, Schilhab said the team has done conceptual design for a world-class gas treating plant for CO2 removal and chilling and compressing the gas; for a natural gas liquids extraction plant; for more than 5,000 miles of 52-inch pipeline and some 25 compressor stations; and has looked at more than 1,200 stream crossings and more than 1,500 road crossings along the route.
A significant thing that came out of the work done so far “is the challenges that surfaced. There are several things that we really, really need to go back and do some more extensive engineering work on.” Schilhab didn’t specify areas needing more work, but did say: “We’ve obviously identified more work that we’ll want to continue to do to drive down the overall project cost.”
What’s next? Schilhab said that as the cost work is completed, those estimates will be conditioned and put into an economic model and “each of the companies will be able to put their analysis on this.”
The 2001 work programs will probably be completed in December and January, with some report out on the results in the first quarter next year.
And work will continue in Washington, D.C., on enabling legislation.
The pace of the 2002 work program, Schilhab said, “will be dictated by what we find from these economic results and also dictated by the political climate,” including the federal government’s activity on enabling legislation and the state’s willingness to provide fiscal certainty.
Enabling legislation essential “The project is a huge commercial and technical challenge and is going to remain that way,” Joe Marushack, Phillips Alaska Inc.’s ANS gas vice president told the RDC conference, citing project cost, political challenges, technical aspects and volatility of the gas market.
“We’re truly disappointed” that enabling legislation the team proposed this summer has not moved forward, he said. Securing enabling legislation “for competing projects — not only the producers, but available to any group — is extremely important.”
“We believe it’s in the best interest of Alaskans that a low-cost project is allowed to move forward with a rapid permitting process and we ask you to support this in the future.”
In addition to the enabling legislation, the team also supports accelerated depreciation. Phillips, not the team, has also asked for fiscal tax incentives which would come into play in a low-price environment, Marushack said.
“Within the state,” he said, “we need a stable fiscal environment and that is being addressed. Current law allows the state to unilaterally change both the economics and relative competitiveness of the project that has already been built. This creates unacceptable exposure for such a large and risky project. There’s nothing new here and a lot of people understand it. The state recognized this when they passed the Stranded Gas Development Act, but it was limited to LNG… What we’re really trying to do is find a set of rules that we all understand that we agree to live by for this project.”
In 2002, Marushack said, we will “work to achieve the required federal legislation — the enabling legislation, the fiscal legislation” and to advance state fiscal certainty.
Project probably not commercially viable Ken Konrad, performance unit leader of BP’s Alaska gas group, told the RDC conference that progress with governments is one area where “we’ll need to match forward spend with overall progress.” More than $100 million has been invested this year, he said, and we “simply cannot continue to invest at this pace absent more clarity on key issues.”
The oil and gas business is fiercely competitive, he said, and companies need to focus scarce human and financial resources where they can best be put to use.
“Massive pre-investment, absent a clear path toward success, is a fool’s game,” he said.
Governments said at the beginning of the year that they wanted to help, Konrad said, and were asked for help in three areas — U.S. federal regulatory legislation; fiscal predictability in Alaska; and efficient regulatory processes in Canada.
The producers’ regulatory legislation, he said, would provide clear and timely regulatory process, meet all modern-day environmental regulations and leave intact the historic Alaska Natural Gas Transportation Act.
“We remain hopeful we’ll see success on this bill sometime next year, but in the meantime we’ll need to pace our investment activity accordingly.”
Alaska fiscal certainty, he said, is not a request “for any reduced taxes or subsidies: just clear, simple, predictable rules.”
In Canada, he said, the companies are “discussing with regulators and First Nations how to develop a thorough but efficient regulatory process that meets the needs of all groups, while avoiding unnecessary duplication of efforts and delays.”
“So, three important areas where government can help — and three important areas where we have not yet been able to achieve success,” Konrad said.
Different levels of risk Konrad said that while he hadn’t yet seen results of this year’s study, he thinks it “will show a project with lower unit costs to market and lower fuel uses to market than any other major ANS gas study to date, including pipeline studies and LNG studies.” Unit costs will be “not quite competitive, but close to it” and those costs will be based, he said, “on thorough engineering analysis, not wishes and assertions.”
“Unfortunately,” Konrad said, “I expect our analysis will also indicate the project is not at this point in time commercially viable. The risk and reward balance is simply not sufficient to attract the required multi-billion dollar investment.”
What does being commercial mean? There has been some confusion, Konrad said, about economics for the project. There are two different kinds:
There are pipeline investors — who could include producers, financial investors, pipeline companies — who “generally earn what is known as a utility rate of return, reflecting the generally low risk, stable nature of their investment,” he said.
“Effectively, pipeline investors enter into long-term binding contractual commitments with customers — in this case producers.” The producers would agree, he said, “to pay capital costs, financing costs, operating costs and reimburse any applicable taxes to the pipeline investors — whether gas is transported or not.”
The main risk to pipeline investors is the creditworthiness of its customers. “With companies like BP and ExxonMobil as key customers,” Konrad said, “I think it’s probably a pretty safe bet.”
Pipeline investors also look at life of reserves, “which in the case of Alaska is quite high” with additional potential from yet-to-find resources.
The pipeline investors also, he said, assume a portion of construction cost risk.
With financially strong customers like the ANS producers and “an unrivaled resource base, we would expect no shortage of prospective pipeline investors seeking a relatively secure return. And indeed, we have seen this to be the case when we’ve talked to all the pipeline companies across North America,” Konrad said.
There’s more than just the pipeline “Overall project economics encompass a much wider realm than just the lower risk utility portion of the project,” Konrad said. “It is this wider view of the project that will ultimately drive investment decisions.”
“Producers — and the state — will shoulder most project risk by guaranteeing pipeline investors will be paid regardless,” Konrad said.
“In addition to paying for a pipeline — either directly through ownership or indirectly via firm transportation commitments — producers must also consider things like gas production costs, the impacts on oil production from gas sales, price risk in the market, … the risk of higher than anticipated tariffs from shared-cost overruns, pipeline operating costs, risks associated with project delays and the risks of changing taxation.”
Producers are not afraid of these risks, Konrad said: “These are risks we live with and manage on a regular basis.”
But the producers need to understand the risks, seek to minimize them when possible and balance them against potential rewards in assessing commercial viability, he said.
“While we absolutely, positively want to monetize our very sizeable gas reserves on the North Slope — because that is the business we’re in, that is what we do for a living — we simply cannot invest in projects where risks outweigh rewards.
“If we did, it wouldn’t be long before we were out of business.”
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