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Report on AKLNG project review released Administration critical of limits of state’s role in liquefied natural gas project, wants TransCanada’s place at negotiating table KRISTEN NELSON Petroleum News
The administration of Gov. Bill Walker has released a report summarizing results of a due diligence review on the state’s role in the AKLNG project as established by the administration of Gov. Sean Parnell.
Walker said earlier in the year that it would be a “45-day due diligence” review by a state gas line team of all material related to AKLNG.
The summary, dated Sept. 24, said the majority of the challenges facing AKLNG “are structural and commercial in nature rather than technical.”
AKLNG began when the chief executives of ExxonMobil, ConocoPhillips and BP informed Parnell in March 2012 that their companies had begun working with TransCanada to assess whether an LNG project made more sense than a pipeline to North America.
A pipeline to North America was deemed no longer economically viable and concept selection led to adoption of a Nikiski LNG site in 2013. The report says favorable oil and gas tax production legislation was passed in 2013 and the parties entered a heads of agreement in January 2014 to jointly advance AKLNG.
Senate Bill 138 was passed in 2014, followed by a preliminary front-end engineering and design joint venture agreement.
Technical work is being progressed for the project concurrently with negotiation of a fiscal deal.
“Thus, although Pre-FEED work is occurring, each party reserves and expects to exercise its right to not do additional technical work - including entering into FEED - unless the fiscal and commercial contracts are satisfactory and the Project otherwise meets internal corporate priorities to move forward,” the report says.
Commercial challenges: no alignment on timeline “There is no alignment on when the AKLNG Project should begin FEED or construction, and time delays kill many projects,” the report says, noting that AKLNG and SB 138 “were based on an assumption that all three Producers were as motivated as the State was to bring an LNG project to fruition as soon as reasonably possible.”
Because each producer has its own economic and strategic concerns, “individual participants within the AKLNG process are not incentivized to agree to finish the commercial agreements necessary to advance AKLNG,” leading to a result where “the AKLNG Project will only proceed on a pace set by the schedule of the Producer who is most reluctant to proceed.”
The report says that because the state has the strongest interest in advancing the project, it “is the party with the strongest incentive to make concessions to progress the Project.”
The report proposed that the state “must have the ability to prevent any AKLNG partner from causing unreasonable delay” and the state must have the ability to acquire the interest of any party which withdraws and get a reasonable commitment from withdrawing parties that they will commit their gas to the project or sell that gas to the state.
The state is negotiating a withdrawal agreement and milestones, but it is unclear if the state will be successful in those negotiations, the report says.
Report argues for larger pipeline The report argues for a 48-inch line rather than a 42-inch line, saying the producers focused on the smaller line because each was focused on the lowest-cost transportation of its Prudhoe Bay and Point Thomson resources. But a 42-inch line doesn’t easily accommodate new natural gas, the report says, and the state “is more broadly focused on encouraging opening up the North Slope’s gas resources to development and exploration beyond PBU.”
The report said the state’s “modeling indicates that the additional cost to build the 48 inch pipe will be repaid due to the lower operating costs resulting from the first 14 years of operating.”
Different ownership interests The report notes that there are significantly different ownership interests in Prudhoe Bay and Point Thomson natural gas. The fields are also different in that Prudhoe “is a mature field with a great deal of knowledge about the gas resource and length of plateau” whereas Point Thomson “is a less mature field with much less knowledge of its gas resources and length of plateau.”
ExxonMobil and BP, with larger shares of the smaller Point Thomson resource, “have tremendous economic incentive to be able to overlift their gas from PBU to provide security for LNG sales contracts on PTU gas that may stretch the bounds of current knowledge of PTU resources,” the report says.
ConocoPhillips, with some 40 times the gas at Prudhoe that it has at Point Thomson, “has no interest in taking any risk with respect to potential effects from overlifting at PBU to support PTU.”
A gas balancing agreement could alleviate the problems associated with disparate ownership, but because the state is not an upstream owner there is little the state can do except to encourage an agreement.
“It may be that this issue will not get resolved until there is alignment by all parties to proceed as soon as reasonably possible,” the report says.
TransCanada’s role TransCanada holds 25 percent of the gas treatment plant and 25 percent of the pipeline. The Alaska Gasline Development Corp. holds 25 percent of the LNG facilities.
But if the state terminates its relationship with TransCanada, AGDC will own 25 percent of the entire project, the report says.
The Department of Natural Resources retained Black & Veatch to do a study of the pros and cons of terminating TransCanada, and the analysis indicates that TransCanada’s participation is expensive for the state and reduces state-producer alignment. The report says revenues to the state could be increased by an average of $400 million a year over the first 20 years of the project if the state buys TransCanada out, and with TransCanada out of the project, the state would be a full partner with the producers.
An appropriation would be required this fall to buy out TransCanada, the report says, along with an appropriation for AGDC to cover future expenditures related to the 25 percent interest in the GTP and pipeline.
RIK/RIV determination The report also says the DNR commissioner cannot make the required statutory finding that taking royalty gas in kind or in value is in the state’s best interest without execution of project-enabling agreements including arrangements for disposition of the state’s LNG share.
The report says that means the commissioner cannot make a RIK election “until the parties have agreed to project-enabling contracts that include satisfactory arrangements for disposition” of the state’s share of LNG. The report says DNR Commissioner Mark Myers has begun the determination, but because the producers are unwilling to finalize project-enabling agreements, he cannot complete the analysis.
The report also says the parties are not aligned on payment of field cost allowances. The state maintains that it should not pay field cost allowances because the producers can deduct field costs as leasehold expenses against their oil production tax, and also because the state is investing 25 percent in the AKLNG project.
The report says there is not alignment on this issue.
Fiscal certainty The report notes that producers are unwilling to move forward on AKLNG without fiscal certainty, and says requests have included certainty on AKLNG property taxes and gas production taxes for 25 years. The producers also wanted assurance from the state that it would not impose a gas reserves tax during project construction.
Certain producers, unidentified in the report, “have indicated an expectation for greater fiscal certainty on unrelated taxes,” the report says, and the state has a concern that some producers will not proceed without fiscal certainty on oil.
The report says the state has consistently told producers it is unwilling to provide fiscal certainty on oil for AKLNG.
The report also says there is disagreement on dispute resolution, with the state wanting dispute resolution to be under Alaska law.
LNG marketing The report says the current ownership model, with each partner intending to separately sell its LNG, means that the AKLNG Project LLC “will not have any independent revenue stream,” and thus the LLC “will not have any capacity to raise financing under a common project financing of the sort that has been the feature of most, if not all, precedent LNG project financings.”
The report says the state believes the present structure must be changed for the project to be successful and concludes that “the project process” adopted under SB 138 “poses serious challenges that make AKLNG very difficult to progress in a manner, and on a timeline, that can maximize benefits to Alaskans.”
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