“Might As Well Jump”—Will Alaska Jump-Start Gas Exports?

Housley Carr (RBN Energy)

Alaska officials, concerned the state’s once-dominant role in U.S. energy production will continue slipping, are taking a fresh look at helping to jump-start a combined natural gas treatment plant, gas pipeline and LNG export project that would free vast volumes of natural gas now stranded at the state’s North Slope. A new study commissioned by the state found that it could make sense for Alaska to take a 20% or higher equity stake in the project, but that there are significant risks the state would need to mitigate. Today we look at whether the 49^th state can make a long-stalled plan by producers to move North Slope gas to market a reality by the mid-2020s.

Ask any American about Alaska and one of the first things that will come to mind is oil, and the oil pipeline that was built in the 1970s to move crude south from the North Slope’s Prudhoe Bay. “Alaskan natural gas” doesn’t roll off most tongues. But as we explored a few months ago in “’Some Plans Are Bigger than Others’—Alaska LNG Exports” the North Slope has some of the world’s biggest gas reserves. The Alaska Department of Natural Resources (ADNR) estimates there are 200 Tcf of unproven and 35 Tcf of proven conventional gas reserves onshore and offshore on the North Slope’s Prudhoe Bay and Point Thomson areas and in waters off the north coast of Alaska. Still, despite years of talk about possible gas pipelines, there is still no outlet—no way out--for all that gas. Instead, Prudhoe Bay producers continue to re-inject 8 Bcf/d of gas into oil wells.

Since the 1970s there has been hope of piping North Slope gas south to the Lower 48, but the last of those plans dried up by 2011-12 after the shale revolution led to the development of major new gas resources in the Barnett, Marcellus, Haynesville and other shale plays much closer to U.S. gas users. That shifted the discussion among Alaska energy giants like ExxonMobil, ConocoPhillips and BP—and TransCanada, which has been working with the state under the Alaska Gas line Inducement Act--to the idea of building about 800 miles of south-bound gas pipeline, a gas treatment plant, and an LNG export terminal in south-central Alaska (see Figure 1).

Figure 1

Source: Alaska Gas Pipeline Project Office (http://gasline.alaska.gov/)
Click to Enlarge

The primary market for the resulting LNG would be Asia, which buys about 70% of the LNG produced worldwide and whose LNG demand curve has been rising 8%/year the past five years. The catch is, the capital costs associated with all the required infrastructure are high—even by energy industry standards—and gas/LNG producers from Qatar, Australia, western Canada and the Lower 48 already are racing to reach long-term supply deals with Asia’s largest gas consumers. Time’s a-wasting, as they say, and in recent months there has been a new push to assemble the complex financial package needed to make Alaska’s gas export dreams finally happen.

Just last week (week of November 17), a top executive at ExxonMobil laid out the project’s challenges at the Alaska Resource Development Council Conference, and ADNR released a Black & Veatch study it commissioned on how the state might change its gas royalties or taxes—or even take an equity stake in the treat-pipe-and-export project—to help make the project a “go.” Two primary challenges the project faces, ExxonMobil said, are:

• LNG projects with a capacity equivalent to more than 50 Bcf/d are being planned around the world, but less than 40 Bcf/d of additional LNG capacity is likely to be needed by 2030 to keep pace with expected LNG demand growth.
• Big LNG customers prefer to enter into supply deals with LNG exporters whose terminals and other infrastructure can be built quickly, because that reduces the risk of entering into a long-term LNG supply deal based on too-high prices. The Alaska project would likely take five years or more to come online from the time of final investment decision (FID). The target FID for the Alaska project is 2017-18, with a commercial operation date of 2023-24, or several years behind the first group of LNG exports terminals planned for the U.S. Gulf Coast, West Coast and western Canada.

Black & Veatch said in its study that the Prudhoe Bay and Thomson Point areas have the gas reserves to supply the project’s total needs, at least into the early 2040s, and by then those reserves could almost certainly be supplemented with new, “yet-to-find” fields nearby (see Figure 2). It also said the international LNG market is “illiquid” and “opaque,” with few participants and based primarily on long-term, 20-year-plus contracts. And, it said, the Alaska project would be costly: $10 billion for the gas treatment plant; $12 billion for a 42-inch diameter pipeline with eight compressor stations; and $23 billion for a three-train, 17.4 Mtpa liquefaction plant and export facility.

Figure 2

Source: Black & Veatch/ADNR Study (PBU = Prudhoe Bay, YTF = Yet to Find - Click to Enlarge)

A real challenge, the Black and Veatch study said, is that with Alaska’s existing royalty and tax set-up, the $45 billion that producers would owe the State puts the project “out of the money” compared with other worldwide LNG projects under development that would provide sufficient volumes of LNG to meet 2025 demand. Some lower-cost projects may not get built, of course, for a variety of reasons. But even if the Alaska project inched toward being in the money, several other projects would be nipping at its heels, working to undercut it. The bottom line, Black & Veatch told the state, is that the Alaska project has the potential to compete for Asian business, but only if the state of Alaska adjusts its fiscal terms to improve the project’s economics. Like governments elsewhere, Alaska could reduce or even eliminate its royalties to help make the project work. But state officials are concerned that would undermine the Alaska Permanent Fund, whose support comes almost entirely from oil and gas royalties. The study concluded that instead of collecting existing taxes and royalties, a 20 to 30% equity investment in the project by the state could provide the same or better revenue.

One other thing is worth noting. The study found the state would better protect its interest by taking its royalties “in value”—that is, in cash—rather than taking them “in kind”—that is, by being paid by receiving a portion of the gas being piped south. If the state had to market LNG itself, the reasoning goes, it would need to enter into complex commercial agreements, and would be disadvantaged by its inexperience in LNG negotiation and its lack of an LNG supply portfolio to optimize. Producers, after all, are better than state governments at managing exposure to market risk.

A full-day hearing at the Alaska House of Representatives’ Natural Resources Committee last Friday (November 22) laid out the range of options the state should consider. What seems likely is that over the next few months, the Alaska DNR, state legislators, and the three North Slope gas producers will try to work out a series of interrelated tweaks to the state’s royalty and tax set-up that would help advance the project—with its treatment plant, pipeline and LNG export terminal--probably resulting in a direct investment in the project by the state. Whether that compromise will be enough remains to be seen. Because with significant amounts of new LNG capacity already under construction elsewhere in the world, and with several other LNG projects poised for construction starts in the U.S. and western Canada, Alaska may need to jump soon or find itself with a lot of still-stranded gas.