Alaska: Gas Project Could Ensure Energy/Economic Future

July 2014, Vol. 241, No. 7

Richard Nemec, Contributing Editor

In Alaska, energy planning has always been as big and bold as the state’s seemingly endless resources and landscape. But the latest blueprint emerging from the ashes of a series of abandoned plans to tap the state’s vast natural gas resources in the north makes anything that came before it miniscule in scope. Whether it is hubris or overreaching, state officials are ready to roll the dice on a gas scenario that will cost in excess of $50 billion and take a decade or more to pull off.

Alaska government leaders began this year by entering commercial agreements with the principal producers and private sector infrastructure players in the Alaska liquefied natural gas (LNG) project. At the same time Gov. Sean Parnell, a strong backer of the project and state participation in it, sent the state Legislature a string of proposals that would authorize the state taking an equity position in the mega project. The legislation is aimed at allowing the private sector partners and the state to begin spending hundreds of millions of dollars on preliminary planning and conceptual engineering work.

With the Legislature’s action, the state can enter into binding agreements, and the state Senate took affirmative action in March with the lower Alaska House following suit on April 20 before the lawmakers adjourned for the year. Afterwards, a pleased Gov. Parnell commented, “Alaskans have waited a long time for a gasline and for the first time in our history, we have alignment, authorization from the Legislature, and a clear path forward. The Alaska LNG Project has begun.”

The project will now move into the Pre-FEED (Pre-Front End Engineering and Design) phase to further refine the cost and engineering aspects of the project.

Senate passage raised the percentage take on a gas production tax from the governor’s recommended 10.5% to 13%. For the overall project, a political and economic issue is what sort of share the state ultimately has as part of the government “take.” This percentage eventually determines how much of the project revenues end up going to the state, rather than the producers.

One analyst speculated that Alaska’s government take could end up in the 70-75% range, which would leave 25-30% of the revenues to be split among the eventual equity partners – the producers, pipeline and the state. But the same analyst counseled against focusing too much on a specific percentage at this point, noting that the ultimate amount will be established based on the regulatory and fiscal structures established for the project.

Even ahead of this phase, Houston-based consultants with Black & Veatch (B&V) have been working closely with the state on various iterations of plans and proposals for tapping Alaska’s vast North Slope natural gas resources. The goal will only be reached through extensive pipeline, treatment plant and LNG infrastructure that will challenge current state of the industry technology, not to mention the sharpened pencils of economists and cost accountants.

The collective total economic impact for Alaska is tremendous, according to Joe Balash, commissioner in the state Department of Natural Resources.

“If we can get infrastructure installed and companies can have confidence that they will be able to monetize whatever they find, it is going to have a huge beneficial impact on further exploration in Alaska,” Balash says. “Producers have to feel they are going to find more oil in order to say, yes, from an exploration perspective.”

He believes the potential to find a lot more natural gas is even greater than the potential for oil.

“If we are successful in getting the infrastructure built and have access to it, I think the exploration business is going to take off out of sight here,” Balash says. “And no doubt, people will find oil when they think they have gas and vice versa.”

Aside from the political and economic issues that were beginning to be addressed this year and are expected to be resolved in 2015, the Alaska LNG project (AKLNG) faces a host of geologic, engineering, infrastructure and logistical challenges that are expected to unfold over a longer time frame in keeping with the epic size of the undertaking.

B&V has completed a definitive analysis of royalty options for the state in looking at what role to play in the LNG project, and the engineering consultant did not recommend a specific option, but its analysis points toward the state partnering with TransCanada Corp. if it decides to take an equity stake. B&V’s work, completed from July through October 2013, assessed four broad areas: the global LNG market; global supply chain costs (used to do economic analyses to establish a fiscal framework); risk allocation among various parties; and the design of the project’s potential fiscal structure.

The Houston-based consultants examined other fiscal frameworks that an Alaska LNG project would have to compete with globally, says Peter Abt, B&V’s managing director for fuels. The challenge was to envision what Alaska’s project would face in trying to serve emerging markets over the next 10-15 years.

“It was a pretty comprehensive review of all the components that need to be contemplated by the state as it considers whether to take an equity position, how it should then be structured, and ultimately how the LNG would be marketed,” Abt told P&GJ.

While there are other comparable energy projects either under construction or on the drawing board elsewhere in the world, none have the combination of challenges, such as climate, topography, geology, environmental and economic issues facing the proposed AKLNG endeavor. The project involves a one-of-a-kind arctic-based gas treatment plant, an 800-mile large-diameter, high-pressure pipeline and a major liquefaction and storage complex at Alaska’s tidewater on the Kenai Peninsula at Nikiski.

Aside from the three major project sections, there also is a 58-mile, 30-inch pipeline from the Point Thompson field to the North Slope gas treatment plant. It originally had an $800 million estimate in 2010 as part of an earlier North Slope gas project by the producers there. The gas treatment plant involves unique components to deal with the significant amounts of carbon dioxide (CO-2) found in North Slope gas, and the plant’s price tag was placed in the $12-13 billion range several years ago.

Another $11-14 billion was estimated earlier by TransCanada and ExxonMobil to cover the cost of the 800-mile, 42-inch pipeline that will parallel TAPS for much of its route before veering west to the tidelands plant site. The liquefaction plant, which is envisioned as a 900 Bcf annual processing facility, including three 5.8 million tons/year trains, could cost up to $23 billion, based on current worldwide LNG construction costs. There are also two storage tanks, each capable of holding enough LNG to fill a standard-size tanker. The estimate for the storage tanks ranges from $150-500 million.

Overall, Alaska’s project is viewed as a 3 Bcf/d undertaking for both the treatment plant and pipeline, but state and industry officials assure there are adequate reserves on the North Slope to support this size of an endeavor, particularly if multiple reservoirs are tapped.

“There are a few other mega projects under development,” says Abt, naming Chevron Corp.’s Gorgon Project in Australia. “It is $53 billion in the latest cost estimate. Alaska’s proposal would be a world-class project, but it is not the largest of its kind, and there are folks who have managed projects of this kind that are partners on AKLNG. The risk is manageable. The aspect of building an arctic-based project adds another level of risk.”

The liquefaction portion of the overall infrastructure, while the most costly, is not that different from other projects around the world, but the challenge comes as to where it is to be located, says B&V’s Deepa Poduval, the firm’s principal consultant on the work with the state of Alaska. Without hesitation, Poduval can tick off a half-dozen location-related factors that add to AKLNG’s potential complexity:
• Extreme weather creating tough working conditions for construction crews and equipment;
• Logistical challenges from climate, topography and remoteness;
• Short working/shipping seasons;
• A short supply of skilled labor, relative to other LNG development places, such as the Gulf of Mexico (GOM) coast;
• A need to build the proposed gas treatment plant off site (Korea, perhaps) and ship it to its North Slope location because of a combination of weather, logistics and labor issues; and
• Cost multipliers from the arctic impacts that make AKLNG in the range of 20-50% more costly than a U.S. GOM coastal project.

“Basically, for AKLNG, it will be necessary to design for extremes, manage logistics of shipping in large modules, transport to remote locations, install in demanding climate conditions (during a majority of the year), and attract/manage a largely transient work force,” Poduval says. “This all has to be done while ensuring that a sensitive ecosystem is protected. These factors are expected to combine to increase both cost and schedule.”

Another challenge slightly out of Poduval’s engineering scope is the geologic intermix of North Slope oil and gas supplies and how all of this is related to the venerable Alaska oil pipeline (TAPS), for which there is an ongoing political and engineering push in the state to revive the oil flow on the 40-year-old pipeline (see earlier P&GJ article in March 2014).

Mark Myers, vice chancellor for research at the University of Alaska, Fairbanks, and a former head of the U.S. Geological Survey, has something to say about the gas and oil deposits on the North Slope, which he has assessed as part of his past professional life. There are issues related to the geologic fact that natural gas — not oil — is the predominant fossil fuel in the arctic region, and because TAPS oil has been the commercially produced fuel so far with gas being re-injected to help future oil production.

The largest concentrations of gas are within the Prudhoe Bay field, which is historically the largest oil production area on the North Slope, Myers says. “The gas is re-injected for pressure maintenance and solubility, so there are tertiary operations revolving around the recycling of the gas.”

Gas production in an oilfield will lower the pressure and the oil recovery in that field, meaning that the timing of gas production can be critical to minimizing how much oil production and revenues may be lost. The later gas is is pulled off of a reservoir, the less oil production is lost, Myers says. “All of these are tradeoffs involving timing and the rate of offtakes from a field.”

When you have both gas and oil being produced, the combined economics of the overall field should look much better, Myers says. In other words, the best overall outcome for Alaska residents is to have both oil and gas projects going. “I don’t think there is very much disagreement about that,” Myers says.

Along with the geologic and engineering challenges, AKLNG faces some stiff global market challenges as B&V’s analysis has articulated for state officials. On the West Coast of North America there are a series of proposed LNG export projects in British Columbia, Oregon and Mexico (both Baja California and the mainland). Globally there are projects in Australia, Africa and Russia.

“The global LNG commodity is different than crude oil in the fact that the markets are not nearly as liquid, and so the structure of the contracts is much different than what you see in crude oil,” says B&V’s Abt. “Given the complexity of the cost of the projects, long-term contracts are used to underwrite the financing to get the projects moving forward. It is important for the state to understand this. [Alaska officials] understand oil markets, but they really don’t understand the gas markets, and particularly the LNG markets.”

A competitive advantage of the Alaska wet associated gas supplies in the global markets may be their heating value and very high methane content (99.7%), compared to the world’s other major LNG supply regions that range from 87.3% (Australia Northwest Shelf) to 93.2% (Yemen), according to the Office of the Federal Coordinator in Alaska, focusing on gas transportation projects in the state.

“To adopt the gas industry’s jargon, Alaska’s LNG would be somewhat “wet” or “rich” compared with the dry and lean gas other U.S. liquefaction plants produce,” said Bill White, a researcher with the federal coordinator’s office. “The blend of Alaska arctic gas that ExxonMobil, BP and ConocoPhillips might super-chill into LNG could be almost ready-made for the Asian market.”

Earlier this year the federal office launched a new web page ( to track the AKLNG project’s development with background information on global LNG, presentations by project sponsors and consultants and reports by the federal office writer/analysts. “As the sponsors are stepping up their project development work, and as the state considers investing in the multibillion-dollar venture, it’s important that the public have easy access to as much information as possible,” says Larry Persily, federal coordinator for Alaska gas pipeline projects.

Both the federal analysts and B&V’s consultants have looked at a separate area of risk – global LNG prices – aside from the inherent risks of the arctic environment, the overall logistics, and the project’s huge scope. “Price is the driver that can most impact the anticipated revenue stream from the project,” says B&V’s Poduval. “Given that this is a high-cost project, it needs to be supported by global LNG prices [tied to oil] and close to the price levels we’re seeing now in the market.”

It is a widely known secret that Japan would like to diversify its portfolio, and it has had some success in negotiating Henry Hub prices in GOM projects, but there is a shroud of uncertainty regarding how many of those approved Gulf projects will actually get built. The next 12-18 months may reveal much on this part of the U.S. LNG puzzle.

“They’re bringing some Henry Hub pricing into the portfolio, but our forecast shows that the demand for LNG will far exceed the available supply that we expect to see exported out of the Gulf Coast,” says B&V’s Abt.

Both Abt and Poduval note that there are only a “finite number of projects” with a low enough cost structure to support Henry Hub-based prices, and neither Canadian nor Alaskan projects have such a low-cost structure. “Alaska is certainly on par with Canadian projects on that basis,” Abt says.

Other major risk factors are related to capital costs, says Poduval, adding that “there has been significant escalation of costs driven by competition among global LNG projects, and we expect those pressures to continue and that certainly will be one of the challenges for the Alaska, and any other projects not already under construction going forward.”

The Alaska coordinator’s Stan Jones, another researcher looking at AKLNG, has opined that Asia’s growing gas demand is what’s driving the large investment in North American LNG export projects. Globally, Jones says, the cost of construction is an issue of increasing competitive importance.

“But the real price that matters is the cost of LNG landed at the dock in Japan, South Korea, China and elsewhere in Asia,” he says. “That’s the sum of producing the gas, moving it to a liquefaction plant, turning it into LNG and delivering it by tanker.”

Jones notes that some analysts think Alaska may have an advantage because of its relative closeness to the Asian market, although nowhere as close as the western coast of Australia. But compared to the U.S. GOM, East Africa and Qatar, Alaska and the North American West Coast have it made. In the context of the western edge of North America, Alaska may still have a price edge, compared with undeveloped fields in remote parts of British Columbia or coal-seam supplies from Australia, Jones says.

“The competitiveness of North Slope gas in Asia comes down to price, which is not the only factor, but it’s a big one,” he says.

Even with state support and timely regulatory approvals, AKLNG is not a slam dunk. There is much heavy lifting to do before any soil (ice? tundra?) is moved, and many millions of dollars may be spent before the project’s future is ensured.

Richard Nemec is based in Los Angeles and is a contributing editor to P&GJ. He can be reached at

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