State files largest LNG permit application ever
The Alaska Gasline Development Corp. was ahead of schedule April 17 in checking a big “to-do” off its long list of steps to get natural gas off the North Slope.
AGDC filed its formal license application with the Federal Energy Regulatory Commission more than two months before the end of June goal set by corporation President Keith Meyer.
The AGDC board of directors unanimously passed a resolution at its April 13 meeting authorizing management to submit the Natural Gas Act Section 3 permit application.
The license application is FERC’s version of the National Environmental Policy Act environmental impact state process for the energy projects over which it has jurisdiction.
Meyer and other AGDC leaders characterized the filing as a “huge milestone” for the state-led project.
“The FERC filing validates the realness of this project,” AGDC board chair Dave Cruz said April 13.
The sheer volume of information dumped at FERC’s Washington, D.C. door appropriately matches the all but unprecedented scale of the roughly $40 billion Alaska LNG Project.
While FERC oversight — in the natural gas realm — is typically limited to LNG plants, the commission considered the Alaska LNG Project’s linked 800-mile gas pipeline and North Slope gas treatment plant to be part of an integrated LNG system.
That allows the entire project to be permitted in a single environmental impact statement instead of two or three, according to AGDC Vice President Frank Richards.
He said April 13 the corporation had prepared nearly 58,000 pages of environmental, socioeconomic and engineering data to give to FERC. It all adds up to the largest LNG project application the federal agency has ever reviewed, he added.
“We hope that we’ve met every single requirement,” Richards commented.
Meyer said AGDC had answered about 2,000 of the 3,000 questions FERC and other federal energy and environmental regulators raised after reviewing the 30,000-plus pages of Alaska LNG resource reports.
Draft resource reports are sent to FERC prior to submitting a project license application to ensure the project proponents have gathered sufficient information before leaping into the expensive application process.
Many of FERC’s remaining questions are best answered by other state agencies, according to Meyer, and shouldn’t impact the licensing timeline.
“We want to get this FERC process going; it’s on a critical path for the (final investment decision) date,” Meyer said.
Meyer has a plan for AGDC to operate on the funds from previous appropriations for about the next year, but the $100 million-plus licensing process will require additional funding from the Legislature in early 2018, at which point he hopes to have customers lined up to prove the project’s viability.
Richards elaborated that the state-owned corporation is asking FERC to finish the licensing process by the end of 2018 — on the short end of the 18 to 24 months it usually takes the commission to finalize an LNG environmental impact statement.
For one, FERC has the reputation of turning around environmental impact statements much quicker than other federal agencies. Additionally, Meyer said the tremendous amount of baseline data compiled in the resource reports will hopefully help FERC make its determinations quicker.
Cruz emphasized that AGDC couldn’t have done the work it submitted April 17 on its own. Most of the data was gathered, analyzed and organized by the Alaska LNG consortium led by ExxonMobil with support from BP, ConocoPhillips and AGDC.
The producers combined to put up three-quarters of the roughly $600 million that has been spent studying and designing the megaproject since 2013. The state funded the remaining 25 percent.
Even with the State of Alaska now leading the Alaska LNG effort, the producers would see a return on their investments in the project to-date by way of being able to sell their collective 26 trillion cubic feet of North Slope natural gas if the project is built.
LNG Summit, financing
Meyer said AGDC’s closed-door Alaska LNG Summit in early March was a success, with 23 individuals in attendance from 14 LNG buyers, traders and investment firms.
He also noted all but about $8,000 of the $264,000, weeklong event was covered by sponsorships and registration fees. The attendees also paid their own way to Alaska.
Corporation leaders further described the capital structure that they envision will fund the Alaska LNG Project during the April 13 board meeting.
AGDC Commercial Vice President Lieza Wilcox laid out a financing outline with about $10 billion in equity and another $30 billion of non-recourse debt for the $40 billion construction.
The corporation expects to attract equity investors with an 8 percent return, which Wilcox said AGDC has heard from multiple sources is a “very reasonable” expectation. The equity would combine with the majority debt financed at 5 percent for a 5.75 percent blended cost of capital.
Wilcox added that the banks issuing the debt would act as de-facto “auditors in the system” to assure AGDC had not only structured the financing correctly, but also to vet the LNG buyers and related gas sales and tolling contracts that will underwrite the debt.
Meyer has long said take-or-pay type contracts will backstop the debt and keep the project’s massive liability off its equity owners.
The 75-25 debt-equity ratio is indicative of how other large infrastructure projects are often funded, he said in an interview; it’s not specific to AGDC’s particular wants or needs.
Finally, once the project is paid off after about 20 years, it could generate upwards of $5 billion in free cash flow for equity investors each year, according to AGDC. A paid-in-full Alaska LNG Project built for $40 billion has the potential to be monetized for up to $50 billion in today’s dollars if more North Slope gas reserves are found, Meyer estimated, making it more attractive to equity investors.
The U.S. Geological Survey estimates there is at least another 200 trillion cubic feet of natural gas yet to be discovered on the North Slope and “only a small portion of that would have to be developed to supply the project for another 25 years,” Wilcox said.
The 35 trillion cubic feet of available gas reserves at the Prudhoe Bay and Point Thomson fields is expected to supply the project for its first 25 years.
Elwood Brehmer can be reached at [email protected].