Alaska’s top oil/natural gas producers told state lawmakers Thursday afternoon that the proposal on the table to pipe, liquefy and export North Slope natural gas is uneconomic and they won’t move forward as partners. However, they said they would sell their natural gas to a state-developed project if it comes to fruition, which is more in doubt than ever.
Consultant Wood Mackenzie, hired by BP plc, ExxonMobil Corp. and Alaska Gasline Development Corp. (AGDC) to study the project also told a state House and Senate Resources Committee the project won’t work as configured.
“Currently the competitiveness of the Alaska LNG project ranks poorly when compared to competing LNG projects that could supply North Asia, specifically Japan, South Korea, China and Taiwan,” Wood Mackenzie said in its presentation. “…[N]ot only will the project not make sufficient returns for investors at current LNG [liquefied natural gas] market prices, but it may struggle to make acceptable returns even under a US$70/bbl [oil] price.”
Gov. Bill Walker — a proponent of greater state control of the project since taking office — acknowledged the Wood Mackenzie findings but held out hope for a differently configured project.
“…I was very pleased to see that there remains a strong potential for an economically viable Alaska LNG project, even at $45/bbl oil prices, by exploring some of the alternate project structures currently being investigated by AGDC,” Walker said in a statement late Thursday. “Alternate ideas such as third party investors, project financing and other advantages resulting from a state led project could make the difference.
“If the AK LNG project can prove to be competitive on the world market, we would see untold advantages of what it would do to propel Alaska’s economy, well beyond the bounds of this project alone.”
The AK LNG project as currently configured could cost $45 billion to $65 billion, according to estimates. Besides BP and ExxonMobil, ConocoPhillips has been partnering with the state in the project. Pipeline partner TransCanada Corp. had its stake bought out by the state last year (see Daily GPI, Nov. 5, 2015). The producer partners have now declined to participate in the project’s front-end engineering and design phase. This had been scheduled to begin next year and cost as much as $2 billion.
If a project is to move forward, it will not be financed by the state’s permanent fund, Walker said. “Let me be clear, a project that is not economically viable will not be built,” he said. “If economically viable, it will be financed by long-term purchase contracts secured before the first piece of pipe is laid, not by the permanent fund. This is how projects around the world are financed and Alaska’s will be no exception.”
Nikos Tsafos, president of energy analytics firm enalytica, has been a consultant to the state legislature on its options for an LNG project. In a Wednesday presentation to lawmakers he outlined three options.
One option is for AK LNG to become a state-owned tolling project. The second option would be the same but include cost-reduction measures intended to improve economics for producers. The third option outlined by Tsafos is for AK LNG to become a state-owned merchant facility.
In the first two scenarios, AGDC would own the hardware, gas treatment plant, pipeline, liquefaction and marine facilities. Producers and possibly others would sign long-term contracts and pay AGDC a tariff to use the facilities. The state could also be a shipper if it were to take its royalties from producers in-kind, or as gas, as opposed to monetary payment. AGDC would use the commitments to attract investors and/or secure third-party financing.
Tsafos said this configuration would free up producer capital that the companies could spend to further develop Prudhoe Bay and Point Thomson. The structure would be simpler and remove some risk from the producer perspective, he said. However, if the project is uneconomic now, this structure is unlikely to make a difference, he said. Key is whether the project would be exempt from federal income taxes, which is currently unknown.
However, an Aug. 22 memo to the Alaska Legislative Budget and Audit Committee from Eric Wohlforth, an attorney with Jermain Dunnagan & Owens PC, does not sound promising. With producers taking up to 75% of the project capacity “…there is no possibility that interest on…bonds to finance the project would be exempt from federal income taxation…” Wohlforth wrote. However, there is a possibility that bonds issued by the Alaska Railroad Corp. for the pipeline and LNG project might be tax exempt under a provision of the Federal Railroad Transfer Act, he said.
The second option offered by Tsafos adds measures for cost reduction, such as the state reducing the desired rate of return used to calculate tariffs, lowering costs for shippers and allowing the sale of producers’ LNG at a lower, more competitive price in the global market. One of the risks here is that the state overextends itself on concessions in order to move a project forward.
“This problem is particularly acute if the state sees AK LNG as a ‘must have’ and is thus willing to take on too much risk or offer too much risk or offer too many concessions to advance a project that is uneconomic,” Tsafos said in his presentation. “In this scenario, it is imperative to screen every concession and understand why it is being offered; it is similarly important to extract concessions from other parties so that the state is not, alone, trying to reduce the cost of supply.”
In the third option, the state would also own the pipeline, liquefaction and other facilities, but it would buy gas at the wellhead from the producers, liquefy and resell it. The price paid for the gas and the price received for the LNG would dictate project economics. And this would be driven by whether the two prices are linked, via an index to Henry Hub, for instance.
In a linked transaction, the value that would be provided by the state and its facilities is not clear, Tsafos said. “…[I]f the transaction makes sense, the buyer and seller would deal directly with each other, and one of them would pay the state a tariff for using the infrastructure (as in Options 1 and 2). The only value would come from adjusting the margin — but the state can do this without owning the gas (i.e., Option 2).
In a non-linked transaction, the state could buy gas at a price linked to Henry Hub and sell LNG at an oil-indexed price, for instance. “In this case, the risks for the state rise exponentially — as do the theoretical returns if prices move in a way that favors the state,” Tsafos said. “Such a deal, however, would not only require extensive due diligence, it would also require a very high risk tolerance.”
Risk and the appetite for it are key considerations if the state is to take ultimate control of the project.
“The state cannot expect to take on a leading role, and full control, without assuming more risk — or, more precisely, while assuming that most of the risks will be borne by others (suppliers, contractors, banks, etc.),” Tsafos said. “Nor should the state expect a large number of third-party investors to flock to the project in order to earn sub-par returns.”
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