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Port authority analysis released PFC estimates $3.17 per million Btu North Slope netback for port authority, $4.69 for highway gas pipeline; says unlikely any LNG terminals AGPA has agreements with will be built in short term Kristen Nelson Petroleum News
The Alaska Gasline Port Authority’s proposed liquefied natural gas project “does not provide a superior netback value for monetizing Alaska’s North Slope gas when compared to a natural gas pipeline to the Chicago area,” according to a study of the project done by PFC Energy for the Alaska Department of Revenue.
The report also concludes there is little likelihood that any of the LNG receiving terminals with which the port authority has agreements will be built in the short term.
PFC Energy said it was asked to look at the likelihood of the construction within the next 10 years of five planned LNG receiving sites on the West Coast with which the port authority has executed nonbinding agreements: Kitimat, British Columbia; Northern Star, Oregon; Clearwater Port, offshore California; Port Penguin, offshore California; and SES, Port of Long Beach. It was also asked to assess West Coast gas marketing issues, the cost of moving propane and butane from Valdez to Asia, the cost of project facilities, the need for Jones Act-compliant tankers for shipments to Kitimat, B.C., and the effect of port authority LNG sales on North American natural gas prices.
PFC said netback comparisons to the North Slope of the port authority’s LNG project and a Chicago pipeline project were $4.69 per million British thermal units for the pipeline project and $3.17 per million Btu for the port authority project using publicly available information from the port authority and LNG receiving terminal sponsors. PFC Energy said when it used internally generated asset cost estimates for the port authority project, however, the port authority netback dropped to $3.05 per million Btu. PFC used estimates provided by the Alaska Department of Revenue for the North Slope pipeline to Chicago project.
PFC said the port authority’s average price for gas sold into the West Coast market would be 61 cents per million Btu lower than the price received by the Chicago pipeline project due to “regional gas price differentials” and a greater average distance from major consuming centers of gas sales by the port authority compared to the pipeline.
Terminal evaluation In evaluating the proposed West Coast receiving terminals PFC looked at four factors: likelihood of federal approval; likelihood of state and local permits; likelihood of being first project in area ready for financing; and likelihood of financing and construction.
Kitimat in British Columbia illustrates the general conclusions of the report about the likelihood of these particular LNG terminals being constructed in the next 10 years: projects in Canada or the U.S. Pacific Northwest have good chances of project approval but are too far from markets for gas to be economically competitive whereas proposed projects offshore California or in that state are close to major markets but are opposed by both local communities and the state.
The proposed Kitimat LNG facility is close to the private port of Kitimat in British Columbia and close to other industrial facilities. It enjoys considerable local support, with aboriginal issues with the Haisla First Nation apparently resolved in December with a change in location from Emsley Cove to Bish Cove, PFC said. Kitimat LNG and Haisla said April 26 that they have finalized a partnership agreement for the proposed $500 million LNG import and regasification terminal.
But PFC said Kitimat’s “location works to the detriment of the project’s economics.” The local market already has natural gas and Kitimat is 1,400 miles from Los Angeles.
The location disadvantage is so great that PFC concluded that even if Kitimat were the only Canadian-U.S. West Coast project permitted it is unlikely the terminal would be built because Rockies gas supplies are closer to premium markets in southern California.
Northern Star has issues with needed dredging as well as its U.S. Northwest location.
The projects off California and in Long Beach face local and state opposition and PFC rates their chances of being built in the next 10 years from negligible (Port Penguin) to poor (Clearwater Port and SES at the Port of Long Beach).
PFC said “the comparatively modest size of the West Coast market” and its relative closeness to Western Canadian and Rockies production “mean that its need for LNG import capacity is modest.” As for the 3.3 billion cubic feet a day the port authority has proposed to export as LNG, PFC said it would be difficult for the West Coast, even including Mexico, to absorb 3.3 bcf a day given the amount of U.S. and Canadian production that would have to be displaced to markets east of the Rockies. “On the Gulf Coast, terminals can replace declining production volumes and use existing infrastructure, while East Coast terminals can more directly access high value markets that are well removed from major gas production areas.” PFC said that it would be difficult for the West Coast to support any four large import terminals, “and it is highly unlikely” that the specific terminals discussed will be built.
Cost estimate PFC Energy said its estimates of the port authority project costs were 5 percent to 8 percent higher than estimates generated by Bechtel, but said it used Bechtel costs to evaluate the project’s economics.
PFC said it estimated a 54 percent premium for shipping LNG on Jones Act-compliant tankers compared to non-compliant tankers, due primarily to higher construction costs and U.S. taxes. It said it believes deliveries to Kitimat would be subject to Jones Act requirements because British Columbia is already an exporter of natural gas so some portion of gas delivered to Kitimat as LNG would ultimately end up in the U.S. and because the natural gas “will not be substantially processed or transformed in Canada.”
On the port authority project’s costs, PFC said the complexity of the project and the number of pieces required produce “a great deal of uncertainty regarding the financial viability of the project.” It said the large scale of construction required results in “significant risk related to the costs of the facilities being built and the timing of project start-up.”
PFC noted that Bechtel updated its cost estimates in 2005, but said that study may not capture some recent LNG facility development trends. Several factors have driven up costs in recent months: increases in raw material costs including steel, cement and nickel; a limited number of contractors that can build such facilities, which pushes prices up; and the fact that with high oil prices there is a “demand for similar services and materials for a wide variety of energy projects throughout the world” including drilling rigs, platforms and pipeline construction.
PFC said several projects with final investment decisions in 2005 “have announced costs per ton far exceeding what had become the industry norm of around or below $250/ton of capacity,” with the Yemen LNG project announced in September having a cost of about $300 per ton of liquefaction capacity. “This trend is likely to continue in the near term as the boom in LNG construction continues, led by Qatari, Nigerian and other project developments.”
Pipeline vs. LNG cost differential In arriving at a wellhead netback of $3.17 per million Btu for LNG and $4.69 for the pipeline project, PFC said in the LPG sales estimates — 56 percent higher for the pipeline than for the LNG project — there was a major difference in how ethane was handled. “Typically, ethane stripping from gas volumes is only logical if there is adequate chemical plant and other industrial facility offtake capacities in proximity to the LPG extraction plant in order to utilize the extracted ethane,” PFC said, noting that characteristics of ethane make if “fairly difficult to ship via tanker to markets where chemical production capacity is available.”
Since Valdez lacks petrochemical facilities, PFC said it assumed ethane would be left in the natural gas stream, increasing Btu value from 1,000 Btu per cubic foot to 1,030 Btu.
By contrast, there are facilities in the Chicago area which could use the ethane.
PFC said the breakeven cost for the Chicago pipeline project to transport natural gas (net of LPG revenue) is $1.85 per million Btu. It said the port authority project would need a levelized tariff of $2.76 based on project costs in the public domain, and $2.88 based on PFC Energy’s asset cost estimates.
“Either way, the Chicago pipeline project has a decisive cost advantage,” PFC said.
PFC Energy’s Web site says the company, a strategic advisory firm in global energy, is headquartered in Washington, D.C., and has offices in Houston, Paris and London.
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