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Why $500 million in AGIA? Legislators question amount, what State of Alaska will get for money in gas bill By Kristen Nelson Petroleum News
Why $500 million? And what will the state get in return? Those were questions administration officials addressed in both the House Special Committee on Oil and Gas and in Senate Resources as the Alaska Legislature began taking testimony on the Alaska Gasline Inducement Act.
The bill proposes to match, up to $500 million, work for taking a gas line project up to the submission of an application to the Federal Energy Regulatory Commission or the Regulatory Commission of Alaska.
Commissioner of Revenue Pat Galvin said in presentations March 13 and 14 that what the state gets in exchange for the $500 million is that the project moves forward, and there are lower tariffs, expansion commitments and rolled-in rates.
“We need to get this gas line project moving and we need to get it moving quickly,” Galvin said. It costs the state money, he said, for every year the gas line project slips.
Lower tariffs also drive value to the state because the state collects taxes on the net value at the wellhead, which is lower the higher the tariff is; and the state pays tariff on its own royalty gas.
The prototype project that the administration used to run its models is a 4.3 billion cubic feet a day line into Canada; with 70-30 debt-to-equity ratio; and a 14 percent return on equity. Galvin said the administration assumed the gas production tax that is in the Petroleum Profits Tax would be the gas tax on into the future.
The estimate is based on a $20.5 billion project, he said. “This number comes from taking the current producer number of about $30 billion” for a project from the North Slope to Chicago, “and anticipating that you only really need to get into Alberta in order to get the gas ultimately into the Lower 48” the $30 billion has been prorated based on the distance.
What does the state get?
The $500 million is an incentive the pipeline builder is eligible for in exchange for financial terms and other terms the state will mandate.
Kurt Gibson, acting deputy director of the Alaska Division of Oil and Gas, said that what the state receives for the $500 million “begins with the project moving forward.”
“There is a bit of a disconnect in alignment between the urgency felt by the State of Alaska in terms of developing natural gas resources and that felt by … the energy industry as a whole,” he said.
The administration wants to change certain behaviors, he said, and is willing to put up money to do that.
Using a graph to illustrate what delays cost the state, Gibson said the state “recoups the $500 million capital contribution largely by speeding by the process.” At a $5.50 price in Chicago, he said, “the state recoups three times the capital contribution” some $1.8 billion “simply by accelerating the project by a single year.”
At current Chicago market prices of $6.75, he said, the state would recover five times the capital contribution by accelerating the project a single year.
The bill requires a licensee to complete an open season within three years of award of the license and allows another 24 months for FERC certification, taking into consideration “the assumption that project sponsor will engage in certain pre-filing activity,” Gibson said.
Asked by Rep. Mike Doogan, D-Anchorage, why 36 months to an open season, Galvin said it was a balance of industry comments, and provided some time for exploration companies to find gas and be able to participate in an open season. “The 36 months was kind of the middle ground” between the state’s desire to accelerate the project and when most companies the administration talked to thought they could be ready.
Rep. Ralph Samuels, R-Anchorage, asked about the relationship between work prior to the open season and work required by FERC, Galvin said some work could be done before or after the open season, and the open season could be held earlier if an applicant was ready and thought it could be successful. “But what we recognized, and will be part of the evaluation process, is that there needs to be a certain amount of work that goes into putting together the terms for that open season in order for it to be successful,” Galvin said. Applicants will propose when that open season will occur.
Lower tariff Because the state’s contribution is in the form of a grant, and is not paid back, it reduces the pipeline tariff by 4 cents to 6 cents for the next 30 years, Gibson said. In real financial terms “for every penny change in the tariff, the state realizes $45 million in royalty and production tax” over the life of the project, he said. For 4 cents, that would be $180 million and 6 cents it would be some $270 million.
What the $500 million does, Gibson said, is buy a list of must haves, what any project proponent must do, “but in addition you’re getting something back by locking in certain debt-equity ratio percentages. … (And) by including the $500 million capital contribution as a grant to the project rather than an equity position, you’ve improved the economics of basin development for everybody.”
Because of how FERC ratemaking works, the $500 million would actually result in a $900 million reduction in the rate base.
Antony Scott, acting chief of the Division of Oil and Gas commercial section, said that the bill’s requirement of 70 percent debt and 30 percent equity also ensures a lower tariff, increasing the present value of state revenue from the project by some $2.5 billion, compared to ratemaking based on 50 percent debt and 50 percent equity.
In response to a question from Samuels about companies not being able to get the debt-equity ratio they propose when they go for financing, Scott said “the debt-to-equity ratio that’s built into the rate is not necessarily the debt-to-equity ratio that’s used to finance the project; they’re not the same. They can finance the project with a different percentage based upon what they can get from the bank than what they ultimately submit to FERC to build into their rate base.”
Scott also said there is an expectation that debt for the project will be guaranteed by the federal government, “which means that there’s a reasonable expectation that the cost of debt for this project will be fairly invariant to who the pipeline developer is.”
Required expansion also adds to state revenues “Without an expansion provision that we are offering in AGIA, I think that the exploration for new gas in the North Slope will be hampered considerably,” said Kevin Banks, acting director of the Division of Oil and Gas. On the timeline proposed, he said only a few explorers would be able to commit gas in the first open season. The estimates by the federal government of 200 trillion cubic feet of technically recoverable undiscovered gas onshore and offshore the North Slope are not necessarily economically recoverable, he said, but the requirement to expand would allow explorers to have “a regular opportunity” for open season for expansion, and would make more discoveries economic because of a known timeframe.
The bill requires rolled-in rates for expansions as long as the increase is not more than 15 percent, Rolled-in rates, Scott said, make exploration prospects more economic.
Rep. Carl Gatto, R-Palmer, asked if that wouldn’t mean all existing shippers would oppose expansions.
“Initial shippers, if they have an interest in exploring themselves, in general will favor rolled-in rate treatment for expansion costs,” Scott said, “assuming that they don’t also own the pipeline.” Rolled-in rates, Scott said, make exploration prospects more economic.
“But the short answer to your question is yes,” said Galvin. “If you are an initial shipper and you don’t have any more gas that you intend to ever ship other than the steady stream of your initial, then you would oppose rolled-in rates simply because you would see an increase because … basically there’s more demand for what you’re taking advantage of than what there was before.”
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