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The $5.5B hurdle In-state utilities face open-season commitment more than 2 times assets Kristen Nelson Petroleum News
Under the terms of the fiscal gas pipeline contract negotiated by Gov. Frank Murkowski’s administration with North Slope producers BP, ConocoPhillips and ExxonMobil, Alaska’s in-state utilities will face commitments of $5.5 billion to participate in an open season for North Slope gas.
And those in-state users will only have nine months, including the six-month open season, to make that $5.5 billion commitment decision, Harold Heinze, chief executive officer of the Alaska Natural Gas Development Authority, told the Alaska Oil and Gas Conservation Commission June 28.
To take advantage of North Slope gas, “the local utilities … will have to make firm financial commitments in excess of $5 billion,” Heinze said, the equivalent of some $40,000 for an individual customer who is both a gas and electric user.
In response to a question from Commissioner Dan Seamount, Heinze said the $5 billion-plus includes contracts to buy the gas, contracts for transportation on the main pipeline and contracts for transportation on a spur line. Assuming the sum of those values is $5.50 per thousand cubic feet, the number used throughout the fiscal gas contract, and assuming 75 percent of current gas usage has to be committed for 15 years, that is $5.5 billion worth of “contractual, long-term firm take-or-pay, ship-or-pay contracts. And you are talking about entities that … aren’t worth $2 billion and they’re making a $5-plus billion dollar commitment,” Heinze said.
“To participate in the open season it’s more than signing a document — you have to be creditworthy,” so you have to have assets or a line of credit “that’s worth what you’re signing for or you’re not creditworthy,” he said.
Commissioner Cathy Foerster asked if the customer base of the utilities wouldn’t make them creditworthy and Heinze said the Regulatory Commission of Alaska would have to approve the charges to be passed through to customers. With the approval of the RCA, a utility could go to a bank for a loan or line of credit. The state could also step in to help with a line of credit, he said.
One of ANGDA’s goals, he said, is to help the utilities be prepared to make that commitment. And “it has to be done over a short period of time. … The open season will not wait on us: we’re 5 percent of the deal,” he said.
Reading the contract cold Heinze said the fiscal gas contract negotiated by the Murkowski administration with North Slope gas owners BP, ConocoPhillips and ExxonMobil clearly addresses in-state use of natural gas, but reading it cold, “we don’t take as a given that it will work.”
He said he thinks in-state gas will be “very difficult without some provisions being modified or added.”
The problem is that for in-state gas the state needs to be “prepared to participate commercially and sign these agreements and do all the things that it takes (or) you don’t play.” The opportunity to take gas off the mainline in Alaska is “clearly there,” he said. “Whether we will ever take gas off in Alaska is an undecided issue.”
Foerster asked what a member of the governor’s negotiating team would say and Heinze said he believed the answer would be: “We addressed those issues in the contract.”
Heinze said his question to the negotiating team would be: “Have you thought about how Chugach Electric is going to get gas? And the answer is probably not because it is a very small fish in terms of the things they have in the contract.”
Information needed It will be a struggle for utilities to make the necessary decisions, he said, because information released when the proposed gas fiscal contract was made available did not include information needed to make open season decisions and that information may not be available until the open season process begins.
The North Slope producers are expected to become anchor tenants in the pipeline and when they announce the open season they will probably also announce their commitments, already negotiated, for firm transportation of gas on the pipeline. In-state users will have to scramble, he said.
Heinze noted he’s appeared before the commission before and “complained bitterly about the lack of information” about the composition of the gas that will be going down the pipeline.
Information in the May 10 release of the contract sheds no light on that, he said, other than information from Bill Van Dyke, the acting director of the Division of Oil and Gas, “based on over-20-year-old information.”
The commissioners are the appropriate people to deal with this lack of gas-composition information, Heinze said.
It’s been six months since the commission began studying gas off-take with the producers. “I think at some time we’re entitled to a progress report,” Heinze said, asking for cases that are being studied and facility descriptions.
He said he knows the commission’s work must be finished before the open season process. When the open season process begins and there is a filing with the Federal Energy Regulatory Commission, “there are no secrets at that time. Everything is public information. … If it’s relative to the FERC application … it is a public document at that time.”
Heinze told the commission he thinks it should start pealing back the curtain on its deliberations with the producers on gas off-take issues.
If the curtain suddenly pops up, “there’s a lot of things you don’t understand at that time,” he said. And if information isn’t made public before the FERC open season process begins, “we only have nine months.”
Foerster asked Heinze if he was familiar with the confidentiality requirements in the agreement between the commission and the Prudhoe Bay operator, BP Exploration (Alaska), for the gas off-take study, and Heinze said he was.
He said he wasn’t asking for trade secrets or proprietary information, but asked why the public wouldn’t know, at some point, what “production facility, reservoir case assumptions” are being evaluated.
Foerster said that information would be part of the public process when the commission rules on off-take rates at Prudhoe.
“I hope that is not the day before the open season,” Heinze said.
Heinze said he would not have come to the commission with these comments on May 9. But he is asking for information because on May 10 he saw how “little was revealed on this whole side of the issue” — what’s in the pipeline and how it is processed.
“I think it behooves you all to work with the producers and find a way” to make more information public.
Agreement called for progress reports The decisions to be made will be important and Heinze said he doesn’t want to get caught cold on some things. He said he remembered the commission’s agreement on the gas off-take study called for a progress report, “to at least indicate where you were in the process” and said he thought it would be appropriate that some agreement be reached on that report over the summer.
Heinze said he supported the commission’s agreement with the Prudhoe Bay operator and the work it is pursuing.
“On the other hand … hopefully we have all learned a little bit since May 10th as to why one might want to tell people a few things before the great revelation.”
He cited the petroleum production tax. “None of us were primed for that. It made it very difficult to be hit cold with something of that significance. And again I’m pleading more to the producers than I am to you, frankly, to open up a little bit. Because this process, these decisions … eventually will be public.” The information will come out, he said, and there is an advantage if the interested public is up to speed on the issues.
Commission Chairman John Norman said the agreement the commission reached on the study on Prudhoe Bay “does contemplate that there would be periodic progress reports.” The agreement is vague on this point, Norman said, and will have to be worked out. “And those progress reports may not be entirely satisfying, but we’re going to do our best, and we’ve indicated, our bias is always to make sure we have the maximum amount of public information.”
At the stage of rule making “that absolutely legally will be the case,” Norman said, “and in the interim we will do our best to do a balancing act and respect the confidentiality provisions in the agreements” while releasing periodic progress reports.
In-state NGL use needs to be studied A federal report on in-state natural gas needs has just been released, Heinze said (see page 1 story in June 25 issue of Petroleum News).
Before an open season, a study of in-state use of natural gas liquids is also required from the mainline pipe entity, although individual owners of natural gas would make a commercial decision on in-state sales for NGLs’ processing. In the preliminary fiscal interest finding on the gas fiscal contract from the Alaska Department of Revenue “there is a presumption that NGL processing in Alaska is not something that will happen,” he said. There is “a very limited opportunity to influence that decision the other way,” he said, and the decision has long-term impacts on Alaska manufacture of chemicals and delivery of propane to coastal communities.
Norman asked about the broadly reported information that NGLs are desired in Alberta, noted the Canadians would have “a certain amount of leverage to extract conditions” because the pipeline would need a right of passage through Canada and asked Heinze what his expectations were for NGLs in Alaska and if there was sufficient gas to meet both Alaska and Canadian expectations?
Heinze said about 200,000 barrels per day of ethane would move down the gas line and about 100,000 bpd of propane. “As we understand the contract,” it is possible no NGLs would be available in Alaska; it could all be removed in Canada, he said.
Since Alaska has 20 percent of the gas, that means 20 percent of the NGLs. Heinze said it is “fairly clear in the contract that Alaska would control its share” and would have the choice of what to do with the NGLs.
If the state took only 5 percent of the gas off in Alaska it could always process the NGLs from its entire 20 percent share, which would be 40,000 bpd of ethane and 20,000 bpd of propane. Those volumes are “both at the low edge of … what you’d like to work with.” The general view is that a petrochemical facility requires 50,000 bpd of ethane. That doesn’t mean 40,000 bpd of ethane wouldn’t work, Heinze said although, “it’s a little below the threshold of what people would like to have.” At 50,000 bpd “they’ll start building,” he said, while at 40,000 bpd “they’re going to study it for a while.”
For propane, 20,000 bpd probably exceeds the state’s requirements by 10,000 bpd, giving you about 10,000 bpd for export. “You’d like that (export) number to be bigger,” he said because it’s hard to get economies of scale at 10,000 bpd. “On the other hand, beggars can’t be choosers.”
Heinze said he would argue “the state has every legal right” to take 20 percent of NGLs and said there are “lots of opportunity here in Alaska to develop NGL-based businesses” with propane and ethane.
The others in the line, he said, own petrochemical facilities at the end of the pipe, “it’s logical they would run their … NGLs down to there.”
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