State role in gas pipeline, LNG plant will require cash
Partnering with industry on a major gas pipeline and natural gas liquefaction plant will expose the state to multi-billion-dollar cash calls from 2019 through 2024 while the project is in construction.
Those also are the years when the state’s liquid cash reserves will be nearing exhaustion if the state budgets continue even modest growth and new oil revenues fail to appear.
It’s a big gamble. The upside for the state is a potential new revenue source of $2 billion to $3 billion per year from sales of state-owned gas, as LNG, after 2024, which could grow substantially if the project is expanded.
But if the state doesn’t enter the partnership, there would still be costs to the treasury even if the project proceeded without public participation, consultants to the Legislature told the Senate Resources Committee Feb. 20.
That would happen because certain costs of the project will be eligible for deductions against the producers’ oil tax liability under the state’s net profits production tax.
In that case, the reduction of state revenues would be $1.9 billion between 2019 and 2014 with $590 million of that revenue loss coming in both 2024 and 2025, the final year of construction. That’s according to estimates by Janak Mayer and Nikos Tsafos, of Enalytica, a consulting firm under contract to the Legislature.
The producing companies have said, however, the pipeline-LNG project is unlikely to proceed without state participation.
The Senate Resources Committee finished its review of the governor’s Senate Bill 138, which would allow state participation, and has passed it to the Senate Finance committee with only technical changes. The bill allows the state to take its gas production tax in kind and to begin detailed negotiations on a participation agreement.
The House Resources Committee is conducting its own review of the House version of the legislation but will wait until the Senate sends SB138 over before acting, House leaders have said.
If the state does enter the partnership, the cash calls could peak at $1.1 billion to $1.5 billion in 2023, the peak year of construction, depending on how the deal is structured.
The proposal on the table is for the state to take 20 percent to 25 percent of the project, with the Legislature to settle on a number this year, and to partner with TransCanada Corp., a pipeline company, on the North Slope gas treatment plant and the pipeline.
The state would invest in, and own, 20 to 25 percent of the large LNG plant now proposed to be at Nikiski, near Kenai, through the state-owned Alaska Gasline Development Corp.
The state would have options to purchase 40 percent of the Slope gas treatment plant and pipeline from TransCanada prior to construction beginning, or 100 percent of TransCanada’s interest later in the project life.
There is no real schedule for the project yet because it isn’t certain whether it will even happen, but under a possible scenario laid out for the Senate committee Feb. 20, the cash calls would begin in 2019.
Were the state to opt for 25 percent ownership, partner with TransCanada, and not exercise the 40 percent purchase option, the annual cash call is the lightest, beginning at $100 million in 2019 and increasing to $1.1 billion in 2023.
The total state outlay between 2019 and 2024 would be $3.4 billion.
If the state does exercise its 40 percent option, the cash call would be $100 million in 2019 and $1.2 billion in 2023, an increase of $100 million for that year.
Under this case, the total state outlay between 2019 and 2024 would be $3.97 billion.
If the state were to do the deal without TransCanada as a partner, which consultants advise against, the state’s outlay between 2019 and 2014 would be $4.82 billion and the peak cash call in 2023 would be $1.52 billion.
The assumptions are that the project would be financed with 25 percent equity and 75 percent debt, Mayer and Tsafos said in the presentation.
Having TransCanada as a partner to shoulder a large share of the capital investment would lighten the state’s responsibility for raising funds by $1.7 billion, but it would also reduce the state’s cash earnings from the project by $430 million to $660 million per year, Mayer and Tsafos said.
Being a partner in the project has one other big advantage for the state, however, Mayer said. Construction expenses and the resulting tariffs, or transportation fees, are a huge part of the project and they are “fixed” costs, meaning they must be paid no matter what the LNG is sold for.
LNG sold at $16.67 per million British Thermal Units, which works out to being equivalent to a $100 per barrel crude oil price, leaves room for a modest production tax and royalty payment to the state as leaseholder, if the tax and royalty were paid in cash.
Most of the sales revenue, about $66 per barrel of oil equivalent, would go to pay for the “midstream” costs: the treatment plant, pipeline and LNG plant.
If the LNG price were to drop to $12.08 per million British Thermal Units, or the equivalent of a $70 per barrel crude oil price, the state’s royalty and production tax would vanish, although the money paid to the midstream pipeline and plant owners remains at $66 per barrel, Mayer and Tsafos said.
“This shows where the value in the project is. It’s in the midstream,” Mayer told the committee. “If the state is only a tax-taker at the upstream (the producing field), its value can be easily wiped out by changes in LNG prices, or the cost of the project,” he said.
Having a part ownership of the midstream pipeline and plants provides some protection.
If the cash calls and overall financial obligation are a concern, “nothing prevents you from off-loading part of this two or three years into the project development. My sense is that there would be a lot of people interested in taking some of the share off your balance sheet,” Tsafos told the committee.
This is actually quite common during the long development period of major LNG projects, he said. There are many instances where new partners buy in, and old partners sell out or sell shares, as a project advances, he said.
State administration officials have already spoken about the possibility of bringing in a partner with AGDC’s share of the LNG plant, perhaps a Japanese company that also is an LNG purchaser.
In a separate hearing in the Senate Finance Committee on Feb. 21, Deepa Poduval, of Black & Veatch, a consulting firm retained by the state administration, discussed the benefits for the state in having TransCanada as a partner and additional risks of going in alone in the partnership with the North Slope producers.
“You can’t look at TransCanada as just a bank,” to lessen the state’s financing burden, Poduval said.
“TransCanada is a very experienced pipeline builder and owner, and its experience includes a high level of expertise on northern pipelines. TransCanada is one of the few pipeline companies that can bring this kind of experience to the project.”
The company also has had a long interest, and experience with, an Alaska pipeline, the most recent being the company as the only bidder for an Alaska Gasline Inducement Act, or AGIA, license with the state a few years ago.
Being in the pipeline business, TransCanada brings with it incentives to expand the project to generate more revenues. The producers’ interest are more focused on maximizing their own returns, Poduval said.
Having TransCanada in the deal also retains the momentum, the committee was told.
“The company has been deeply involved since it received the AGIA license and has a substantial body of work that has been done,” she said.
Relationships have also been established between TransCanada and the producer companies. It would take time for another pipeline company to duplicate these, she said.
Poduval also said the financing terms offered by TransCanada — a cap of 5 percent on debt and a 12 percent cap on return on equity — “are pretty good numbers in the pipeline world.”
So is the guarantee of a 75 percent debt and 25 percent equity ratio in financing, Poduval said. The lower equity helps the state because it lowers the tariff, or transportation cost.
However, whatever improvement the state can gain with a potential new partner offering better terms is swamped by the erosion in the state’s long-run return by a delay while a new partner is solicited and brought in.
“If a new partner offers to reduce the return on equity to 10 percent instead of 12 percent, there could be a $100 million gain in state’s Net Present Value on the project. If the new partner offered an 80-20 debt/equity ratio instead of 75-25, there could be an additional $100 million in NPV,” Poduval told the Senate Finance committee.
“But what if there is a year’s delay while you solicit for and find a new partner? A year delay will cost you $800 million in lost NPV, so any gains from improved commercial terms are just washed away.”
She also said TransCanada runs some big risks by offering to lock in financial terms before the project begins construction and the actual financing is done.
There is no guarantee, she said, the company will actually get financing at 5 percent, or that it will be able to really raise enough debt to fund 75 percent of its construction costs.
“If the debt cost gets to 7 percent (instead of 5 percent) TransCanada’s NPV on the project could actually go negative,” she said.
TransCanada’s balance sheet and ability to finance may be strong now, Poduval said, but if the company’s circumstances are different several years from now when money has to be raised for the project the pipeline company may not be able to raise as much as is needed.
The same risk applies to the state, Poduval said. Despite the state’s current AAA credit rating, changes in financial circumstances or in capital markets could make it more expensive for the state to finance its share or limit the amount that can be borrowed, she said.
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