Former official recommends scrutiny for TransCanada role
JUNEAU — A former state revenue economist has recommended state legislators take more time with a proposal to partner with TransCanada Corp. as part of a deal for state financial participation in a large natural gas project.
However, Roger Marks, now an independent consultant, endorsed the basic terms of state participation with North Slope producers on the gas project. Marks retired from the Department of Revenue in 2008. He spoke to the House Resources Committee March 27.
Senate Bill 138, which has passed the Senate and is now before the House Resources Committee, would have the state own 25 percent of the project and also ship state-owned gas through its share of the gas pipeline and liquefied natural gas plant.
“The administration has put forth a thoughtful proposal. My observations are just to offer some options, as suggestions,” he said.
Most of Marks’ remarks were directed at a proposal for the state to partner with TransCanada on its 25 percent share of the pipeline and large gas treatment plant on the North Slope to lessen the financial burden for Alaska, although the state would finance, and own, all of its 25 percent share of the large LNG plant proposed to be built at Nikiski, near Kenai.
Marks suggested the Legislature explore ways to go ahead with the deal with the producers, to keep the project on schedule, but take more time to review the relationship with TransCanada and possibly improve it.
Some of the advantages to the state of the TransCanada partnership are being overblown, Marks told the House Resources Committee.
For example, a motivation for the state to have TransCanada as a partner is the company’s experience, but Marks said he cannot find evidence that TransCanada has experience with large gas treatment plants, a major part of this project.
In TransCanada’s original application to the state for its Alaska Gasline Inducement Act license in 2009, Marks said TransCanada did not want to take on the gas treatment plant part of that project.
“They eventually agreed to do it, but hired a contractor to provide assistance,” he said.
Marks said the TransCanada deal overall appears to have been engineered to get the state out from under a disadvantaged 2010 contract with the pipeline company under the Alaska Gasline Inducement Act, or AGIA, which could subject the state to a treble-damages claim from TransCanada if that contract was violated. “Treble damages” is a legal term that allows a court to triple a defendant’s liability.
The Legislature should initiate an independent legal review of its liability under the treble-damages clause in the AIGA agreement, Marks said. Key terms of the treble-damages provision are unclear.
So far TransCanada has spent $550 million on its work under AGIA with the state providing $350 million of that under an agreement to provide a subsidy and TransCanada itself investing $200 million, Marks said. What is not clear is whether the treble damages are for the gross amount expended, or three times the $550 million, or for TransCanada’s net investment, or three times $200 million, he said.
Marks also believes the state doesn’t really need TransCanada’s help in financing and that it could be capable of financing all of its 25 percent share of in other ways, including all of it in debt financing.
That opinion is based on consultations the state had with large financial firms on previous gas project proposals in which Marks was involved, and even a study by Citigroup, the nation’s third-largest commercial bank, in 2011 for the state-owned Alaska Gasline Development Corp., or AGDC, that concluded that 100 percent debt-financing for an $8 billion state-built “bullet line” might be feasible, and without a partner.
The plan now before legislators contemplates the state financing its share of the large gas project with a combination of cash equity investment and debt, which would put pressure on the state budget between 2019 and 2023, years in which the state would have to make large cash contributions as equity.
Taking on partners such as TransCanada would lessen that burden, administration officials have said.
Marks said there should be more research on alternative financing packages that would lessen the needs for up-front cash payments by the state.
Most important, any financing alternative that reduces the cost of capital for the state’s 25 percent share of the project would pay off handsomely in reduced costs for transporting state-owned gas, to the benefit of consumers who would receive gas through the system.
“A 2 percent reduction of the state’s cost of capital can easily translate into several hundred dollars a year in savings in energy for consumers,” Marks told the House committee.
One of the key arguments being presented for the TransCanada partnership is that the pipeline company would finance the 25 percent share of the Slope gas treatment plant and pipeline itself, so that this would not be a state obligation that would load up debt on the state and impede its finances.
Marks said this is illusory too, because under the partnership arrangement the state would have to sign a long-term “take or pay” contact with TransCanada to ship the state’s gas through TransCanada’s part of the treatment plant and pipeline.
The contract would represent a long-term multi-billion dollar commitment by the state that would itself be considered a form of debt by the rating agencies, Marks said. Moody’s Investor Services had advised the state that this would be the case in 2006, when the state proposed a similar pipeline ownership plan.
“Debt is debt. You can’t avoid it,” by working through TransCanada, Marks said.
Marks’ criticism of the partnership was countered by state Natural Resources Commissioner Joe Balash and Revenue Commissioner Angela Rodell in comments to the House committee March 31.
“The value of having TransCanada is far more than financial. The state would be hard-pressed to have the human capital and the resources,” that TransCanada could provide during a time when critical negotiations with the producers will be underway, Rodell said.
Balash agreed with that.
“TransCanada is not just a bank,” he said.
If the state went out to look for other offers, “how many pipeline companies are there in North America who can match TransCanada? Maybe three or four. Would any of them be interested?” Balash asked.
The fact that TransCanada was the only qualifying bidder interested if the state’s solicitation under AGIA would seem to speak for itself.
“We believe the opportunity to improve on the terms TransCanada has offered are very limited,” Balash said.
TransCanada’s commitment to a financing structure of 75 percent debt and 25 percent equity is a huge benefit to the state, Balash said, because pipeline companies make their guaranteed profit on the equity portion and most pipelines have higher percentages of equity.
A survey of new Federal Energy Regulatory Commission-regulated gas pipelines built or planned showed the lowest equity percentage at 60 percent. It is to the state’s advantage to have lower equity and more debt because that translates to a lower tariff for transporting gas and higher state revenues.
In his remarks March 27 Marks did endorse the state administration’s basic approach. The concept of the state taking its royalty and production tax in kind, or in the form of gas, and taking an ownership stake in the project equal to the state’s share of gas, about 25 percent, is sound, Marks said.
Having the state share in ownership is important to the producers because it lessesn the amount of the project they have to finance and better aligns the overall risks and rewards of the project, he said.
“This helps the economics of the project considerably,” for the producers, Marks said. “It is possible that the proposal, as it is, is fine. But if it is possible to modify some of the terms (on the TransCanada partnership) you might want to take a little more time.”
There are also uncertainties in how the would regulate the project and these should be fleshed out, Marks said.
FERC normally regulates interstate pipelines and an LNG project that exports gas that is served by a pipeline all within one state is something new.
“The proposal in the Heads-of-Agreement (with the producers) is for FERC to regulate under Section 3 of the Natural Gas Act,” Marks said.
“Section 3 is mainly designed for licensing the siting, construction, expansion and operation of LNG import or export terminals. Terminals include facilities to transport or process gas. However, this section is rarely used to include a large pipeline with local consumption,” of gas, he said.
This needs consultation with the FERC, Marks said. It also would seem to leave regulation of an expansion of the project, to accommodate new gas or expansions related to in-state needs in limbo with no apparent regulation of tariffs or other protections for the public.
Marks laid out a scenario where Enstar Natural Gas Co., supplied now with Cook Inlet gas, might need North Slope gas in the future. However, if all of the gas moving down the pipe, including the state’s gas, is committed under long-term LNG export contracts that must be served, the only way to accommodate Enstar would be with new gas delivered through an expansion, Marks said, most likely added compression. But who, he asked, will review terms of the expansion to protect consumers?
It would be prudent to include a provision in the deal for the state to expand its capacity to serve local needs and for it to be clear that the state regulatory commission would have jurisdiction over this.