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ANGDA goes local Alaska Gas Market System looks at 1.25 bcf line to Southcentral, Valdez Kristen Nelson Petroleum News
Hung out to dry during the Murkowski administration — which focused exclusively on a project by the major Prudhoe Bay owners to take Alaska North Slope gas to the Lower 48 — the Alaska Natural Gas Development Authority is in a better position with Alaska’s new governor, Sarah Palin.
ANGDA is moving ahead on a challenge from Palin, who took office in December, to do what Alaskans wanted when ANGDA was created by voter initiative in 2002: an Alaska-based project to connect North Slope gas to market.
The authority’s proposal, the Alaska Gas Market System, would take 1.25 billion cubic feet a day of ANS natural gas to Alaska markets in the Interior and Southcentral and to Valdez for use in an LNG facility.
ANGDA Chief Executive Officer Harold Heinze described AGMS in a memo to the board as a project which would be advanced simultaneously with other projects. He said ANGDA would work “with any and all interested experienced parties” on a cooperative and non-exclusive study effort “leading to a project definition and open season within one or two years.”
Andy Warwick, re-elected ANGDA board chairman at a Jan. 29 meeting, described the project at the meeting as “generally the result of Gov. Palin suggesting that we get on with what we were appointed to do,” a suggestion the governor made when she met with ANGDA in one of a series of meetings with natural gas pipeline proponents immediately after her inauguration in early December.
Heinze said the 1.25 billion cubic feet a day line is a proposal — “a starting point” — that would be refined through a joint-study effort. The proposal is meant to be cooperative, he said at the Jan. 29 meeting: “This is not a competition; we’re not looking to win. We are looking to succeed in the sense of developing a project that goes forward and works.”
Canada not involved One of the virtues of AGMS is that it doesn’t involve Canada. “All the other proposals that are on the table tend to have a problem if they are based on a Canadian throughput,” illustrated by the difficulties proponents of a Mackenzie gas pipeline have encountered, Heinze said.
Another virtue of AGMS is that it doesn’t require unanimous approval of the Prudhoe Bay owners, which, he said, has been one of the difficulties the state has had in reaching agreement on a project to the Lower 48.
The technology of AGMS is “very doable,” Heinze said, since the largest line it involves is 24-inch diameter, a pipe size industry has a lot of experience with, and a pipe size which steelmakers can readily produce.
The reserve base for a project this size “is very strong — that’s important when you look at financing,” Heinze said, and “the market pull for this project is very strong.”
“The biggest reason for Alaskans to support this is, it gets done for Alaska what we need — it gets energy here, it gets jobs here” and in a timely fashion.
The timetable for the project is six years: project definition would begin this year; permitting and design in 2008; financing in 2009; right-of-way preparation and construction beginning in 2010; a three-year construction season; and startup in 2013.
1.25 bcf a day AGMS would move 1.25 bcf a day to natural gas markets on the Yukon River, in Fairbanks, Southcentral and Valdez. The line would follow the general alignment of the trans-Alaska oil pipeline, with a connector gas pipeline linking Glennallen to the Beluga gas field in Cook Inlet. Gas going to Cook Inlet would be delivered to Beluga where it would be stored and would “even out the flow of pipeline gas and recharge that field over time,” Heinze told the board.
Gas and propane would be available along the route with connections on the Yukon River, Fairbanks, North Pole, Delta Junction and Glennallen. A two-train LNG plant and loading dock would be constructed at Valdez.
Initial delivery (0.25 bcf a day) would be to Fairbanks and Cook Inlet, with the first increment adding a pipeline to Valdez and providing enough gas for a single-train LNG plant for gas export and natural gas liquids separation (total 0.75 bcf). The final phase would add compressors to increase throughput to serve a second LNG train in Valdez and new petrochemical plants, bringing throughput to 1.25 bcf a day.
Delivery would cost $5 billion Heinze pegged pipelines at $4 billion and a North Slope gas conditioning plant at $1 billion, with a tariff in the range of $1 to $2 per million Btu from the North Slope to Valdez and Cook Inlet. An LNG plant would cost some $3 billion for 7 million tons per annum, with an estimated $1 to $1.50 per million Btu tariff and downstream cost-of-service charges for marine LNG transportation and re-gasification of $1 to $1.50 per million Btu using available ships and terminals.
Heinze told the board that there would probably be different investors in the three major segments, and the pipelines may have different investors.
“It’s our concept that the LNG plant would be built by people that are in the LNG business, people that already are used to owning those plants, having ships that haul the LNG away and deliver it to markets that they already have arranged for.”
Heinze said that while commitments would have to be in place for all the gas, gas would be available first for in-state use because the pipeline portion could be up and running before either a gas conditioning plant or an LNG facility were constructed.
“This project could come on stream without a gas conditioning facility on the North Slope and without an LNG plant in Valdez. The reason is that this gas is rich enough in NGLs that even with the 12 percent CO2 content it is a rational fuel to be burned,” Heinze said. The pipeline could be delivering gas as much as two years before the LNG plant was ready, he said.
Potential joint-study participants The proposal ANGDA has put on the table is for a joint study whose participants could include: oil and gas companies currently producing or exploring in Alaska including the major Prudhoe Bay leaseholders; pipeline companies; LNG manufacturing, shipping and/or marketing companies; experienced energy project investors; Alaska utilities; State of Alaska; and the U.S. federal government.
The joint-study process would be a year or two years of participants studying the project and determining whether or not it can move forward. It would move the project to the point “where people can make a rational decision on continuing on,” Heinze said.
Heinze said he hoped to see at least two major study teams: pipelines and LNG plant, and possibly a third for gas conditioning.
Monthly steering committee meetings would be public, and include a summary of study results.
Participants would contribute in-house expertise. ANGDA will ask the administration and the Legislature for $5 million as its contribution and would hire contractors. The $5 million, the public money, would be recovered from the other parties if the project happens, Heinze said.
ANGDA has done a lot of work, he said, and $5 million will get it to the next step; the step beyond that would be in the tens of millions of dollars.
Big pipe could follow The total requirement for a 1.25 bcf a day project would be 10 trillion cubic feet, Heinze said. The state has about 3 tcf in royalty gas at Prudhoe Bay and could make that gas available. One way to come to a total of 10 tcf is to have one of the Prudhoe Bay owners participate. Or Point Thomson, with undeveloped reserves of 6-9 tcf, could be a source. Or explorers with acreage close to a gas pipeline route could make discoveries and participate, he said.
Heinze said a big system could follow AGMS and the 24-inch line could be used for in-state gas delivery and to carry NGLs from the big pipe for in-state petrochemical use.
People have worried that AGMS could be a threat to the big project, which is based on 50 tcf, Heinze said, and board members Dan Sullivan and Bob Stinson asked whether using 10 tcf for AGMS would mean that there isn’t enough gas for a big project.
“Number one, several of us believe that you can’t do a project that’s based on 50 tcf, because you don’t have 50 tcf,” Heinze said. “… The people who actually pull the corporate purse strings, the controllers and treasurers, the financiers, the bankers, all those people, they do not commit to projects beyond what’s right in front of them in terms of reserves.”
Heinze said he thinks it will at some point come down to a decision of “if the 10 (tcf)’s in the hand, are you really going to worry about the 40 (tcf) in the bush that actually may be only 15?”
He said the current environment is highly competitive and geared to “picking the winner. And the reality is in the long term Alaska may be very well served to have more than one project that can be expanded and sort of come at this from multiple points of view.”
“The biggest issue we see is until somebody cracks it open and makes a start, we’re not going anywhere.
“It doesn’t matter what project … how big it is, if I can’t get started then nothing happens.”
And what could a later big project look like? Would it have to follow an Alaska Highway route? Heinze said he didn’t think so.
If AGMS were built and a large amount of additional gas were found, “then there’s no doubt that you would revisit the potential of going over the top (east across the north of Alaska and down through Canada). Because this system (AGMS) basically provides everything Alaska wants,” Heinze said. At that point, what would be at stake would be revenue at the wellhead.
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