Legislators met in Fairbanks June 12 and 13 as the special session continued to consider a state license to TransCanada Corp. to work on a North Slope natural gas pipeline.

The license would entitle TransCanada to a $500 million state subsidy and other incentives. In their final day of hearings in Juneau, on June 10, legislators delved further into questions related to a liquefied natural gas project, financing for TransCanada's project, net present value estimates and likelihood of success of the project.

Analyses of three possible LNG projects from the North Slope to Valdez indicate all could be profitable but none would be more so than TransCanada's overland project, the administration and its consultants argued, primarily because of the added capital costs of the liquefaction plant. Vessel construction and marine shipping costs were viewed as an operating expense that would add $1 to $1.20 to tariff rates, they said.

Three scenarios reviewed by consultants from Energy Project Consultants LLC (EPC) and Westney Consulting Group Inc. included a 2.7 billion to 4.5 billion cubic feet per day pipeline to Valdez; TransCanada's “Y-line” option (a pipeline to Alberta with a spur line to Valdez) for a 6.5 bcf a day line to Delta Junction 4.5 bcf a day being shipped to Alberta and 2 bcf a day to Valdez.

The scenarios include a one-year delay on the start of an LNG project, compared to TransCanada's AGIA proposal, because there is no LNG project sponsor at the same stage of readiness as the Canadian company.

Lawmakers who support an LNG project over an all-land pipeline criticized the 12-month delay as too long, which the consultants acknowledged was an assumption on their part.

The Valdez LNG plant got a boost in the analysis for its cold water, which would reduce evaporation costs of a super-chilled product, but Bill Sparger of EPC said the higher demand for operating fuel for the liquefaction plant would increase costs 7 percent over the pipeline to Alberta.

Other negatives on an LNG proposal included limited economy of scale benefits because U.S.-flagged vessels that would be required to carry the product would likely be smaller than foreign ships in the LNG trade and have less market flexibility.

Also, LNG imported by the U.S. is dry, meaning gas liquids have been removed. The Asian market demands gas with a higher Btu content that is usually provided by the retention of liquids in the delivered LNG.

The consultants said expansion of the LNG project would be more difficult than an overland pipeline because LNG projects are expanded in full train increments involving substantial volumes. Because of this it would be more difficult for smaller volume discoveries of gas to get space in an LNG project as easily as through compression expansion of an overland pipeline.

Potential tariffs on an LNG export project ranged from $9.68 for a 2.7 bcf a day line to $10.33 for the TransCanada Y-line combination. Vessel construction and marine shipping costs, viewed as an operating expense rather than a capital cost, added $1 to $1.20 to the tariff.

The absence of an actual contract between the state and TransCanada that spells out expectations on both sides remains a point of concern for lawmakers that the administration has been unable to eliminate. This would be useful in preventing disputes.

One focus of the worry has been a list of expectations that TransCanada Vice President Tony Palmer included in his presentations. These included an expectation that the state would use its influence and sovereign powers (i.e. taxes) to convince North Slope producers to commit gas to the project. In his presentation Palmer agreed with Galvin the items are not legal commitments.

Galvin argues a contract is unnecessary and that the AGIA statute, the state's request for applications and TransCanada's application together constitute a contract sufficient to cover any disagreements. He also noted that the license pending before the Legislature states that any perceived conflicts are decided in favor of the state.

“It is the state's statement of what the relationship that is legal,” Galvin said.

State legislators concluded three days of hearings in Fairbanks on Gov. Sarah Palin's proposal to grant TransCanada Corp. a license that contractually binds the state and TransCanada together to develop a natural gas pipeline.

This was the first of the so-called road hearings. The hearings continued June 16 in Anchorage, with Federal Energy Regulatory Authority officials scheduled to testify. Legislators also scheduled hearings in Palmer, Soldotna, Barrow and Ketchikan.

Given the long-standing role of Fairbanks supporting an “All Alaska” gas pipeline terminating at a Valdez/LNG facility, the community testimony was more subdued than expected. The pipeline licensure issue shared the stage with strongly voiced local concerns that the increasingly high cost of oil has pushed Fairbanks families into an energy crisis.

Community testimony seemed to be that Fairbanks would ride along with a TransCanada line, but the underlying assumption seemed that under current conditions an all-land pipeline best facilitates the possibility of a subsequent future Valdez/LNG link.

The overriding issue in Fairbanks seemed to be local energy costs now, not wait for AGIA or the All-Alaska pipeline.

The issue of family energy costs in Fairbanks brought strong local interest in Enstar Natural Gas Co.'s proposal for their independent line 20-inch bullet pipeline. The hope was this could bring gas - and energy relief - to Fairbanks several years earlier than the big pipe. The Enstar direct line would follow the Parks Highway south to Mat-Su, Anchorage, the Kenai Peninsula, and possibly allow expanded LNG exports by the existing Conoco/PhillipsMarathon LNG plant at Nikiski on the Kenai Peninsula.

Enstar officials testified at the hearings, presenting their proposal for an independent line. Enstar is currently the state's only operating gas transporter and distributor, serving the Kenai Peninsula, Anchorage and portions of the Mat-Su Valley. However, regional gas supply is expected to experience sharp shortfalls in gas availability after 2011.

Frank Richards, deputy commissioner of the Alaska Department of Transportation, testified that the state needs to embark on an immediate program to prepare and reinforce roads and bridges to handle the heavy loads required for pipe sections and larger modules.

Richards talked about the front-end costs and the need for an expedited construction program, but the assessment is that all roads and bridges will need significant repairs after heavy use during construction. Richards estimated the cost at $2 billion, probably in state funds between now and the beginning of construction.

He told the committee the requirement is for about $350 million a year, roughly equal to the current state outlay for transportation construction. Infrastructure needs will focus on access points, including Anchorage, Prudhoe Bay, Seward, Port MacKenzie, Valdez, Haines, Skagway and the Yukon River crossing.

Richards added that one difficulty might be in the Canadian section of the Alaska Highway, between Whitehorse and the Alaska border, where construction and maintenance has been 60 percent supported by U.S. funds appropriated by Congress.

Given the pending reauthorization of the transportation program by Congress next year, availability of these funds could be deleted.

The Yukon Territory government would likely have difficulty absorbing this 60 percent even at the current levels, much less a significantly increased outlay to handle higher levels of durability required for pipe loads.