Econ One Research President Jeffrey Leitzinger told the Alaska Legislative Budget and Audit Committee June 14 that his firm’s analysis of the proposed North Slope gas pipeline project, and of the state’s preliminary fiscal interest finding on the proposed contract, show the project to be economic.
If there is an issue, Leitzinger said, it is that the North Slope producers proposing to build the line are exploration and production companies and want an E&P rate of return from a pipeline project, not a pipeline return, which is generally in the 11 percent to 12 percent range.
The state’s fiscal interest finding on the contract the administration has negotiated with project sponsors BP, ConocoPhillips and ExxonMobil, said a North-Slope-to-market natural gas pipeline project is competitively disadvantaged compared to other projects worldwide because of limited capital and high transportation costs.
Leitzinger said he disagreed, citing more than $120 billion of expected net flow in 2006 dollars to the producers from a line to Alberta, making the Alaska project one of the highest net-flow projects in the world and very attractive by any normal economic metric. The expected net present value is among the highest worldwide, he said, and the expected rates of return on total capital greatly exceed costs of capital for the sponsors.
The project, he said, has ample revenue to support its expected costs.
Disadvantaged compared to what?
The state’s fiscal interest finding compared transportation costs of more than $2 per million British thermal units for the Alaska project to $1.20 per million Btu for liquefied natural gas. Leitzinger said Econ One’s estimated tariff of $2.17 per million Btu is lower than the $2.25 the state used.
More significantly, the state’s transportation cost for LNG includes only tanker transportation, he said, and does not include per-million-Btu costs of 75 cents for liquefaction, 40 cents for regasification and 10 cents for transportation from the regasification facility to market.
This kicks the total LNG transportation cost up to more like $2.50 per million Btu, he said, somewhat higher than either $2.17 or $2.25, which are levelized nominal dollar figures for the life of the project. Since the ANS gas pipeline project wouldn’t start moving gas for some 10 years and then continues for several decades, a comparison with today’s LNG transportation rates in inappropriate, he said. In today’s dollars the pipeline tariff is about $1.20.
Leitzinger said he sees no comparison with LNG transportation costs that places the Alaska project at a disadvantage.
The net present value per barrel of oil equivalent reflects net value for energy including the cost of transportation, he said, and achieves a target level at prices above $4 in Alberta. At $5.50, the number the state used, there is plenty of revenue left over after transportation to support costs, Leitzinger said.
Transportation, investment implications
What are the investment implications of the transportation costs? Eighty percent of the money for the project will come from lenders as limited recourse loans backed by federal government loan guarantees that will reduce the loan costs and will be secured by shipping commitments, Leitzinger said. Tariff rates are set on debt to allow recovery of the loan costs, he said, and if the regulators do their job the rate allowed on equity will be sufficient to attract capital to the project. Leitzinger said the willingness of independent companies to build the project subject to regulated returns indicates those rates are not too low.
He said the fiscal interest finding discussion indicates the state believes the producers are not willing to supply gas to a project they don’t build and that it would take years to wrestle the gas away from them.
Because the sponsors are exploration and production companies they want an E&P return for the project, he said, not a pipeline return, and part of what is driving the state’s analysis is how to get more than a regulated return for the project.
The sponsors have combined equity capital of $676 billion, 95.9 percent of their capital structure, he said, with only 4.1 percent debt. Taking on the debt to build the pipeline would only increase the companies’ collective debt by 2 percent. Leitzinger said he didn’t think the difference between 4 percent and 6 percent debt would have any significant impact on the cost of capital to the companies or on their ability to raise it.
At a $6 per million Btu expected price and a transportation cost of around $2, Leitzinger said there is little shipping risk over the life of the project, noting that a $2 gas price in Alberta seemed to him a remote possibility.
IRR poor investment metric
Leitzinger said the state’s fiscal finding called internal rate of return the project’s “Achilles’ Heel,” but said IRR shows the relationship between early cash out and later cash in and is a poor investment metric especially with different risk profiles between projects, different time frames and different costs.
The fiscal finding treats the $21 billion project cost as a cash outflow at the beginning, he said: but it’s not a cash outflow from the sponsors and not a correct use of IRR.
In the comparison with projects around the world from PFC in the fiscal finding there are some projects which don’t include full capital costs, he said, and unless you put all the right costs in other projects you won’t get valid comparisons.
The Alaska project is also compared to both oil and gas projects, and transportation economics are fundamentally different between oil and gas projects, he said, with different expected returns, different uses for the oil or gas, different returns and different reasons to pursue the projects.
Leitzinger said he doesn’t believe it, but even it if were true that it makes sense to put all transportation costs into IRR and compare projects, you would have to recognize that the regulated gas pipeline business has a lower risk profile than energy marketing and energy development. The Alaska project is heavily weighted with pipeline costs so an across-the-board comparison of oil and gas projects is like comparing apples to oranges, he said.
Leitzinger said that as an economic matter he fails to see the case that the Alaska North Slope gas project is challenged today based on market prices and costs. It is economically viable on its own terms in today’s market, he said, and with the needs of companies to replace reserves it holds out the prospect for adding one of the largest known reserves bases and has one of the highest net present values.
Leitzinger also said he sees no reason to believe the Alaska project stands behind other projects because other projects on the comparison list are sanctioned and moving ahead.
As for risk, the net present value of 10 percent is more than enough to offset and compensate for risk, he said.
How risky is the Alaska project?
Tony Finizza, an Econ One consultant, compared the Alaska project with other investment projects and said the project is not disadvantaged under present fiscal terms.
He also assessed the cost overrun risk and price risk cited by administration consultant Pedro van Meurs in May testimony. Van Meurs had concluded that because of the combination of cost overrun risk and price risk there is a 20 percent to 30 percent chance that the project will not be built, even with a fiscal contract in which the state gave substantial financial incentives to the builders of the line.
Finizza said Econ One believes the probability of having an uneconomic project is “far smaller” than 20-30 percent. If you examine two low-chance events the chance of both happening at the same time is significantly smaller than either happening by itself, he said.
The Econ One analysis assumed the risks are correlated because high capital costs are more likely when prices are high because there is increased industry activity and competition for materials.
Finizza said the risk of an uneconomic project under various price and cost overrun distributions ranges from less than 1 percent under a U.S. Department of Energy, Energy Information Administration scenario to about 5 percent under the fiscal interest finding scenario.
