Invited Article: The Economic Challenges for a Natural Gas Pipeline in Alaska

As background for our 32nd USAEE/IAEE North American Conference in Anchorage,

Alaska (July 27-31, 2013), USAEE Dialogue is pleased to present this invited paper.




Larry Persily

Federal Coordinator

Alaska Natural Gas Transportation Projects

(Anchorage, AK)

 


(Photo: Associated Press)

So close, yet so far away. Alaska’s North Slope storehouse of natural gas is less than two hours away from the state’s population center by jet. But it’s billions of dollars away from reaching the burner tip. This is a story of economics, markets, competition — and the Alaska public’s unrelenting desire to overcome all of the above.

The North Slope has had a profitable 36-year history of oil production. And though the natural gas that comes up the well at the same time has been reinjected back underground to coax out additional oil, Alaskans want something more. They want a pipeline to carry the gas to market to turn into cash for public spending. And they want to burn some of the gas for their own heat and light, too.

Alaska’s 720,000 residents pay some of the highest prices in the nation for diesel fuel, a strong incentive to deliver affordable North Slope gas into their furnaces, boilers and electrical generating plants. But there are issues — serious issues, with serious dollar amounts — in the way of building a pipeline to move the gas to market.

Construction costs for the gas treatment plant, large-diameter pipeline, liquefaction plant, storage tanks and marine terminal were estimated in the fall of 2012 at as much as $65 billion, which could make it the most expensive natural gas project in the world.

The project would need long-term, take-or-pay sales contracts for the gas to underpin financing for the venture — and there is a lot of competition in the global trade for customers.

In addition, Alaska’s high construction costs and the public’s high expectations of tax and royalty benefits from the project present formidable challenges for pipeline developers.

Alaskans love their oil revenues. The state could end the fiscal year on June 30, 2013, with more than $58 billion in three major savings accounts — all of which are fed by oil tax and royalty revenues and investment earnings.

The next couple of years may provide the answer to when, or if, a natural gas pipeline could add to the state’s financial future. Proponents have tried over the years to put together a deal, but economics always got in the way.

 

HISTORY LESSON

Recent history provides an example of the frustration Alaskans have faced through the years. It’s a story of how quickly the North American natural gas market changed from a land of impending shortages to a land of plenty, killing off one more plan for an Alaska gas line.

Less than a decade ago, gas buyers started to worry that North America would be unable to meet its natural gas needs in the years ahead. Mature, conventional fields were in decline, the economy was strong and demand for the fuel was building.

Natural gas price spikes in 2001, 2005, 2006 and 2008 at times pushed the fuel into the painful range of $9 to as much as $15 per 1,000 cubic feet, causing financial distress among utilities and their ratepayers, manufacturers and their customers.

Industry embarked on a planning binge, preparing blueprints for liquefied natural gas import terminals up and down the U.S. West, East and Gulf coasts; Canada, too. North America would meet its gas needs by unloading LNG tankers from Russia, Qatar, Norway, Trinidad and Tobago, several African nations – anyone who had gas to sell and ship.

Billions were spent expanding existing LNG import terminals and building new ones.

In addition to welcoming foreign natural gas to its shores, North America looked north, far north, to Alaska. Maybe the time had come to build a pipeline to deliver Alaska gas to market through a pipeline connecting to the North American grid in Alberta.

Calgary-based TransCanada teamed up with the state of Alaska in 2008 on a plan to design and permit the project, figuring that the North Slope producers would sign up to ship their gas on the line. ExxonMobil joined up with TransCanada in 2009, and it looked like the project might just happen.

 

SHALE GAS CHANGES THE PLAN

But what happened instead was hydraulic fracturing and horizontal drilling in shale rock formations. It changed the market and ended the hope for an Alaska line.

North America now is awash in gas, so much so that gas producers – and just about all of those LNG import terminal operators – want to get into the natural gas export business. It’s an easy call.

Natural gas is fetching higher prices abroad, especially in Asia, attracting the interest of North American gas producers. Those LNG import terminal operators in Texas, Louisiana, Mississippi, Georgia and Maryland already have storage tanks, pipes, loading docks and supply connections – all they need is a liquefaction plant and they can reverse the flow of their operations and make money.

Alaska producers in 2012 saw the same higher-price markets in Asia and joined the quest.

 

LOOKING TOWARD ASIA

After putting the North American gas line project on the shelf, TransCanada and ExxonMobil teamed up with the other two big North Slope producers, BP and ConocoPhillips, to take a hard look at shipping Alaska gas overseas aboard LNG tankers.

Now, in 2013, the producers are working to determine the best site for a liquefaction plant, the best routing for the pipeline, the best configuration and location for gas treatment facilities. They committed in 2012 to working as a team to see if they could put together an economically viable project.

Their hope, if all goes well, is to achieve what they call “concept selection” by the end of the first quarter of 2013. Then, if all is still going well, pre-front-end engineering and design would be on the work list for 2013/2014, with front-end engineering and design 2015/2016. Maybe project sanction in 2016 and first gas flowing into tankers in 2022.

Maybe.

That timeline – not a schedule, just a theoretical timeline at this point – assumes customer interest in the gas, a cost-competitive project, commercial agreement between the producers and TransCanada, and a state fiscal regime that helps, not hinders, the mega-project.

The timeline also assumes no regulatory, permitting, litigation or construction delays. But we’re getting ahead of ourselves. The international LNG market and the state’s fiscal expectations are the biggest hurdles for the project.

 

PROJECT COST ESTIMATES

September 2012 estimates from the producer-led project team included:

  • $45 billion to $65 billion to build the gas treatment plant to remove carbon dioxide and other impurities, about 800 miles of pipeline and compressor stations along the route, liquefaction facility, storage tanks and marine terminal.
  • The estimate does not include the LNG tankers.
  • The pipe would be 42 or 48 inches in diameter, carrying gas pressurized at 2,000 pounds per square inch – maybe higher.
  • The pipe would be capable of moving as much as 3.5 billion cubic feet of gas per day.
  • The liquefaction plant would be comprised of three production trains, capable of producing 15 to 18 million metric tons of LNG a year – as much as 2.4 bcf a day.

The competition will be tough in the global marketplace. More than $180 billion in LNG export projects are under development in Australia, with more capacity scheduled to come online in Papua New Guinea and Africa over the next few years. Qatar has plenty of spare capacity to protect its market share, while Russia’s Gazprom is lurking around the LNG trade as it looks to sell more gas by tanker and reduce its reliance on pipeline sales to European nations.

Not to mention all of the proposed LNG export projects on the U.S. Gulf Coast and the West Coast of Canada, focused on moving North American shale gas production to the same higher-priced Asia market as Alaska.

 

FEDERAL JURISDICTION

But back to permitting. In addition to needing Federal Energy Regulatory Commission approval to build and operate the liquefaction site, an Alaska LNG project would need multiple other federal and state permits, approvals, rights of way and reviews.

FERC jurisdiction over the liquefaction terminal is a matter of federal law. It was a bit ambiguous until Congress passed the Energy Policy Act of 2005, which settled the issue and gave FERC jurisdiction to license onshore LNG import and export facilities nationwide. FERC would take the lead on a terminal’s environmental impact statement, coordinate reviews by other federal agencies and set deadlines for environmental analysis.

The commission, however, would not regulate the LNG facility’s rates. That’s between the private parties operating the plant and paying for the services.

Step outside the LNG terminal’s perimeter, start walking the pipeline route, and FERC jurisdiction is uncertain. The commission could assert jurisdiction over the pipeline to an LNG export plant, depending on several factors.

The decision, in great part, would come down to whether the pipeline in an integral part of the LNG project, and whether the public’s interest would be served best by a single environmental review and decision rather than separate reviews and possibly conflicting decisions.

That decision would be up to the staff and commissioners at the independent agency after they see the specifics of a project.

 

FEDERAL APPROVAL FOR EXPORTS

As for other federal issues, the project developer would need to obtain Department of Energy approval to export gas overseas. Approval is just about automatic for sales to nations that have signed free-trade treaties with the United States. But other than South Korea, none of the free-trade nations are really in the market for LNG.

China, India and Japan do not have free-trade-nation status, and approval for exports to those nations is a tougher hurdle. A dozen large-project LNG export applications were stacked up at the Department of Energy as of the first of the year, with the agency working out the issues it needed to consider in making its rulings on those applications.

Proponents say selling U.S. natural gas overseas would serve the public’s interest by helping to reduce the nation’s balance of trade deficit; spur more exploration and production (and jobs) at home; would not significantly drive up natural gas prices for U.S. consumers; and generally would be good policy for a nation that believes in free trade.

Opponents, or doubters, worry that shipping U.S. gas overseas could someday in the future put the nation in the position of finding itself short of gas again. Domestic energy security means keeping domestic energy at home, they say. Others, most notably utilities and petrochemical manufacturers, prefer an oversupplied domestic market and the low prices that come with it as opposed to a more balanced market with possibly higher prices.

Alaska really isn’t part of the export debate for the simple reason that there is no way to deliver North Slope gas to Lower 48 states’ customers, so shipping Alaska gas to overseas buyers wouldn’t deny it to U.S. consumers.

The Department of Energy essentially acknowledged as much when it directed a consultant to look at how LNG exports of domestically produced natural gas could affect the U.S. economy and told the consultant not to consider Alaska gas exports in the mix. That study will be a key part of the department’s decisions on pending and future Lower 48 LNG export applications.

 

STATE ASSISTANCE

Turning to state, rather than federal issues, TransCanada, as the state licensee for North Slope gas pipeline financial assistance, as of early 2013 had run through about half of the $500 million the state promised to reimburse toward development costs. The state in 2008 agreed to cover much of TransCanada’s project development costs as an incentive to proceeding with design, environmental work and FERC application, even if the project lacked financing and customers.

TransCanada, and its colleagues in the latest LNG project, the North Slope producers, will have access to the remaining balance of the $500 million while they work to determine if it’s a viable project.

Many Alaskans, however, believe the deal has been for naught and figure it’s time for the state to cut its losses, cancel the contract with TransCanada, save what’s left of the $500 million, and embark on a new plan. No doubt the argument will come up as the state legislature meets this spring to adopt a budget for the next fiscal year.

 

PLAN B FOR ALASKA

There also is a growing effort among some Alaskans not only to scrap the TransCanada deal and give up on the large-diameter, producer-involved gas line, but to turn to what’s called Plan B: A state-owned, state-developed smaller gas line, something in the range of $8 billion (though a soft estimate), capable of moving 500 million cubic feet of gas a day to serve local needs and smaller export sales.

Supporters of that effort, managed by a new state agency called the Alaska Gasline Development Corp., say the project’s economics work if it can find an anchor customer(s) to carry much of the cost. And they remind Alaskans that the line may be the best — and only — way to get North Slope gas to local utilities within the next decade if the bigger project stalls out.

Be it large-scale mining operations or an LNG export customer for the gas, the state-supported project, even at its small size, would need those large customers to help carry much of the project costs — otherwise, the price to local users in the small Alaska market would be too high unless the state steps in to provide direct financial assistance.

Detractors say the small line’s finances are weak, lacking economies of scale to hold down costs to local customers. They question whether the gas delivered to Alaskans would be affordable. They question whether those potential large-volume customers exist. And they question the wisdom of the state taking on such a large risk.

 

FISCAL TERMS ARE CRUCIAL

State fiscal terms are a key issue for the larger gas line project under review by the producers and TransCanada. North Slope producers have long said they need stable fiscal terms before embarking on such a costly investment.

Oil and gas production generates four revenue streams for the state: Property tax, production (or severance) tax, corporate income tax, and royalty. The state generally owns one-eighth of any oil and gas produced from state lands, with the state holding the option of taking its share in-value (the producer sells the oil or gas and sends the money to the state), or in-kind (in which the state takes ownership of the oil or gas and sells it on its own).

The property tax is assessed on equipment, personal and real property used in the exploration, production or transportation of oil and gas. A natural gas treatment plant, pipeline, compressor stations and liquefaction plant would fall under the state property tax. The oil and gas industry is the only sector to pay a property tax to the state. All other businesses and homeowners pay only their municipal property tax.

Corporate income taxes are collected on a portion of oil and gas companies’ worldwide earnings, with a formula that assigns a share of those earnings to Alaska.

 

HIGH-STAKES TAX BATTLE

The big political battle in Alaska is over the production tax, a net-based tax on the value of the oil and gas after transportation and allowable production costs are deducted. The state’s production tax had been based on gross revenue for years, until the legislature in 2006 went to a net-based tax with an escalator in the rate as the value of the oil and gas climbed higher.

The legislature raised the tax rate again in 2007, effectively quadrupling the tax rate at high prices from 2005 to 2008. The Legislature in 2006 and 2007 also instituted a generous array of tax credits for exploration and capital expenses. (It is important to note that downstream capital, such as a gas pipeline and LNG plant, are not eligible for the tax credits.)

The industry has complained that the steep progressivity curve in the production tax rate takes away much of the upside earnings potential — diminishing the attractiveness of investing in Alaska. For example, at a $100-a-barrel market price for oil, at current costs, the marginal government take on North Slope production, including all state and federal taxes and royalties, is about 84 percent. In other words, when the price of oil goes up one dollar, 84 cents of that dollar goes to government, 70 percent of which is from the production tax.

The Legislature is expected to take up the tax issue again in 2013, with the governor and many legislators pushing hard to scale back the progressivity curve and add incentives for new oil production. The Alaska oil pipeline is almost three-quarters empty, as production declines at mature fields, and the state has a strong interest in attracting investment dollars to stem or reverse that decline.

Stable fiscal terms are especially important for the gas line because LNG is sold in the global marketplace on long-term deals, often 15 or 20 years (unlike oil, which is sold on the spot market or in short-term deals). The North Slope producers want to know two things:

  • Can they sign an LNG sales contract and know that the state’s fiscal take will not significantly change during the life of the contract?
  • And can they run the numbers and make an investment decision on the project, assured that the state will not significantly change the tax terms at some point in the future?

The producers realize they will always be the deep pocket for Alaska. They worry that they are the only pocket, especially if the state (and the public) needs more revenue in the years ahead.

 

CONCLUSION

At some point, if there is to be a natural gas pipeline in Alaska’s future, state officials will need to negotiate fiscal terms that work for the producers and work for Alaska and the Alaska public. A deal that recognizes the price competitiveness of LNG projects in a world full of new suppliers. A deal that recognizes a gas pipeline would bring tremendous benefits to Alaskans through decades of affordable energy.

There are constitutional issues to deal with – one legislature cannot bind future legislatures, and lawmakers cannot relinquish their taxing authority. That will make the job tougher, but not impossible.

The solution is a deal that recognizes the risk of a project of this size, yet finds a way for all parties to benefit.

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* Mr. Persily was confirmed by the U.S. Senate in February 2010 as Federal Coordinator for Alaska Natural Gas Transportation Projects, an agency  created to assist with permit coordination for an Alaska North Slope natural gas pipeline.

 

 

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