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In-state gas pipeline bill already filed Proposal stalled in Senate last year, but House leadership prepared to try again, this time proposing AGDC as standalone agency Kristen Nelson Petroleum News
Once crude oil began moving off Alaska’s North Slope in the mid-1970s, natural gas was supposed to follow. But Lower 48 natural gas prices crashed, dooming the 1980s project.
There have been proposals since, but none has been able to surmount the economic hurdle of moving gas off the North Slope — itself a challenge — and then to market either via a pipeline through Canada to the Lower 48 or by liquefying the gas and moving it to Asian markets as liquefied natural gas, LNG.
Most recently the state backed a line to the Lower 48 under AGIA, the Alaska Gas Inducement Act, enacted in 2007 under former Gov. Sarah Palin, but that project foundered when the Lower 48 was flooded with natural gas from shale developments.
In the fall of 2011, Gov. Sean Parnell called for greater alignment among potential shippers of North Slope natural gas — and said that alignment should be for a line going to tidewater, with natural gas going to the Pacific Rim as LNG.
Parnell said at the time that TransCanada and ExxonMobil, partners in the project licensed under AGIA, hadn’t been able to move forward with negotiations with potential shippers for natural gas to the Lower 48, and said the problem might be that the market for natural gas has shifted since AGIA was passed, due to the glut of natural gas in the Lower 48, “the devastating tsunami in Japan and that nation’s subsequent drift away from nuclear power, and other market forces in the Pacific Rim.”
“It all means that a better market for Alaska gas could very well be in Pacific Rim countries,” Parnell said, adding that AGIA does allow for reassessment of market conditions.
He cited what appeared to be an impasse on a line to the Lower 48, and said he had asked TransCanada, ExxonMobil, BP, ConocoPhillips and the Alaska Gasline Development Corp. to move forward on a large-diameter line to tidewater to take natural gas to the Pacific Rim as LNG.
BP, ConocoPhillips and ExxonMobil are the North Slope natural gas owners.
The in-state proposals But it isn’t just marketing North Slope natural gas in the Lower 48 or on the Pacific Rim: There are also efforts under way to get natural gas to Alaskans.
Recent work has been spurred out of the governor’s office and the Legislature.
In 2008, then Gov. Palin tasked the Alaska Natural Gas Development Authority, ANGDA, with a gas pipeline from Southcentral to Fairbanks. This was in addition to work the authority was doing on a spur line to Southcentral from the proposed North Slope mainline.
In early 2009 Palin established an in-state gas pipeline project in the governor’s office, naming Harry Noah as project manager, with a goal of supplying the Railbelt with natural gas within 5 years.
Noah told legislators in late December 2009 that there were too many in-state gas project plans in play
“We are pulling this way and we’re pulling that way,” and while good people are involved on the different project, Noah told a meeting of House Resources, “one side just wants to kill the other side.”
And, he said, the Legislature is funding the competing projects.
Whether spurred solely by getting gas to Alaskans or by the dueling state projects, in 2010 legislators in both the House and Senate worked on legislation to consolidate an in-state gas pipeline under one agency.
That legislation, passed as House Bill 369, sponsored by House Speaker Mike Chenault, R-Nikiski, established the Alaska Gasline Development Corp.
HB 369 was merged with Senate legislation and signed into law by Parnell in late April, creating the Joint In-State Gasline Development Team and putting Alaska Housing Finance Corp. CEO and Executive Director Dan Fauske in charge of the team, which was established as an AHFC subsidiary.
The purpose of the team was to develop and deliver to the Legislature by July 1, 2011, a plan for an in-state natural gas pipeline which would be operational by the end of 2015.
The report delivered to the Legislature in July 2011 found the project economic, but said the 2015 completion date was not realistic given the time required for permitting, holding an open season and securing financing. The report envisaged a completion date near the end of 2018, with first gas in 2019.
Changing legislative requirements As AGDC worked on the project, it identified a number of changes it needed in its statutory authority to proceed, and those were introduced — and some passed by the House — in the 2011 session.
In 2012 the House legislation was merged into House Bill 9, with Chenault and Rep. Mike Hawker, R-Anchorage, as chief sponsors. The bill passed in the House, but languished in the Senate.
Chenault described HB 9 as a bill that would keep momentum going for development of gas for Alaska, “while keeping open all the options for participating in an aligned project,” referring Parnell’s proposal that a large line under AGIA could morph into an LNG project and combine with an in-state gas project.
Hawker said the bill would bring state agencies, including ANGDA, “together into a common mission with a common management,” eliminating the ANGDA board and moving ANGDA under the AHFC board; the AHFC board would also replace the Joint In-State Gasline Development Team, which was the board for AGDC under HB 369.
The bill also established a fund to receive $200 million appropriated in 2011 for work on an open season, limited challenges to right-of-way leasing decisions, allowed AGDC to enter into confidentiality agreements, gave AGDC the ability to determine pipeline ownership and operating structure, issue bonds and manage pipeline and related project assets.
The bill also allowed AGDC to operate a pipeline as a contract carrier and provided the option of Regulatory Commission of Alaska oversight.
ANGDA’s role would focus on marketing under the bill, giving it the ability to pledge royalty gas owned by the state as long as that gas was not already committed by contract.
House Bill 4 House Bill 4, pre-filed for the 2013 Legislature, incorporates the provisions of HB 9 but would establish AGDC as a separate state agency, akin to the Alaska Railroad Corp. or AHFC.
It also addresses the contract carrier issue differently than HB 9, creating a new section of Regulatory Commission of Alaska statutes for in-state pipeline contract carriers, allowing contract carriage and giving RCA oversight.
This has been an issue for an in-state gas pipeline because current statutes for in-state lines allow only common carriage, which would require prorating space on a line to accommodate new shippers. Because an in-state gas pipeline is expected to have contracts with utilities, which require continual gas delivery at specified rates, those shipping on the line need the certainty of contract carriage.
As with HB 9, AGDC’s need for confidentiality is addressed, allowing it to enter into confidentiality agreements — an authority it does not currently enjoy.
The big line project The Alaska Pipeline Project, the TransCanada-ExxonMobil AGIA-licensed mainline project, held an open season in 2010. Multiple bids were received, followed by months of negotiations, but no precedent agreements — binding commitments to “ship or pay” on the line — were ever signed.
In early May 2012, TransCanada notified the Federal Energy Regulatory Commission that it was terminating that first binding open season.
TransCanada received the AGIA license for the project in late 2008 and ExxonMobil joined the Alaska Pipeline Project in mid-2009.
TransCanada told FERC that while “significant interest” was expressed in capacity on a line going to Alberta during the open season in the form of conditioned bids, no precedent agreements were every signed. TransCanada said it was APP’s “assessment that the producers are not prepared to make commercial commitments to the Alberta Project at this time.”
APP is working with the Alaska North Slope producers on the feasibility of a project for a pipeline to an LNG facility at tidewater in Southcentral Alaska and a new open season would be initiated if those evaluations led to a project that appears commercially viable, the company told FERC.
AGIA license amended In his January 2012 State of the State address, Parnell laid out benchmarks for achieving a gas line based on LNG — beginning with resolution of the Point Thomson litigation (a settlement was announced March 29) and alignment of the North Slope producers on commercializing natural gas under the AGIA framework (announced March 30).
On May 2 the state approved an amendment to the AGIA license calling for initial work on an LNG project to be completed by September with an open season by the end of the year.
The governor’s benchmarks included hardened numbers for an LNG project and an associated work schedule by the end of the third quarter.
On Oct. 1 the aligned commercial group — BP, ConocoPhillips, ExxonMobil and TransCanada — told Parnell in a letter that the current cost estimate for an LNG project was $45 billion to $65 billion in 2012 dollars.
The project would include a gas treatment plant either on the North Slope or in Southcentral; a 42-48 inch pipeline; a three-train liquefaction plant; LNG tanks and a terminal.
The companies said they looked at 22 potential sites for the liquefaction plant, including “Cook Inlet, Prince William Sound and other Southcentral sites,” with a footprint of 400 to 500 acres. The gas treatment plant would have a footprint of 150 to 250 acres and be among the largest such facilities in the world.
The pipeline, some 800 miles in length, would have a capacity of 3-3.5 billion cubic feet per day and include five in-state off-take points for 300-350 million cubic feet per day.
In an Oct. 3 letter Parnell said the information provided met his benchmark of hardening numbers and identifying a gas project by the end of the third quarter, and also addressed another benchmark of completing discussions with the AGDC, the in-state gas project, on the potential to consolidate the work of the two projects.
Challenges In a diagram of key decision points accompanying their Oct. 1 letter the companies indicated that for the project to proceed from concept selection to pre-FEED (front-end engineering and design) a competitive oil tax environment, predictable and durable LNG project fiscal terms and resolution of AGIA issues would be required.
In a footnote to the project’s phases the companies listed items which could extend the duration of the phases, including: “protracted resolution of fiscal terms, permitting and regulatory delays, legal challenges, changes in commodity market outlook, time to secure long-term LNG contracts, labor shortages, material and equipment availability, weather, etc.”
The companies said that while concept selection technical work is reaching closure, “additional commercial agreements as well as support from the State of Alaska will be required in order to progress this world-class opportunity.”
Some of the challenges the companies list — “cost, scale, long project lead times” and reliance on production facilities supporting declining fields — aren’t directly things the state can address. Some required permits would come from the state, others from the federal government.
The governor had said in January that if his milestones were met, “the 2013 Legislature can take up gas tax legislation designed to move the project forward.”
But the companies’ letter made it pretty clear that not just gas taxes are at issue.
Existing oil production facilities “need to be available over the long-term for producing the associated gas for an LNG project. For these reasons, a healthy, long-term oil business, underpinned by a competitive fiscal framework and LNG project fiscal terms that also address AGIA issues, is required to monetize North Slope natural gas resources.”
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