TransCanada Corp. is offering significant incentives for North Slope producers to commit gas to its planned natural gas pipeline when an open season for shipping contracts is held this summer.
But company officials say they expect any bids for capacity in the pipeline to be heavily conditioned over several issues, including the need for North Slope gas producers to conclude a long-term agreement on fiscal terms with the state.
There's wide agreement the fiscal deal is needed, but Gov. Sean Parnell says any deal on gas production terms, mostly on taxes, should come next year when the results of open seasons held this year by TransCanada and a competing project, Denali, are known.
An open season is a period of several months when a pipeline developer solicits firm contracts to ship gas. With contracts in hand, the developer designs the pipeline to fit the volume for which it contracted and then takes those signed agreements to financial markets.
TransCanada filed its application with the Federal Energy Regulatory Commission Jan. 29 to conduct its open season from May through July for Alaska portions of a North Slope natural gas pipeline.
An application will be filed separately with the Canadian government for portions of the pipeline built in Canada, TransCanada Vice President Tony Palmer told legislators in briefings in Juneau.
The pipeline company is working with ExxonMobil Corp. on engineering and cost studies related to the open season, which are being reimbursed 50 percent by the state, but ExxonMobil company is not yet a partner with TransCanada on the pipeline and will not be until "commercial issues" between ExxonMobil and the state are settled, both TransCanada and ExxonMobil have said.
The issues involve litigation over Point Thomson leases and the fiscal terms for gas production to a pipeline. TransCanada is making the application to FERC on its own, Palmer said.
If FERC approves the plan submitted, the open season would begin May 1 and conclude July 31, he said.
The plan is to have permits and approvals for the project by 2014 and to have the first flow of gas in 2020.
Incentives added to the proposal for shippers willing to make commitments early would be worth about $500 million a year in lower transportation costs for the gas, Palmer said. Lower transportation costs will boost profits from gas production and sales.
Lower costs will result in higher revenues to the state because they translate to higher values of the gas on the North Slope. State production taxes and royalties are tied to the value of extracted resources calculated on the Slope.
Palmer and Paul Pike, ExxonMobil's senior manager on the project in partnership with TransCanada, said two options will be presented to potential shippers in the open season. One is a 48-inch, 1,700-mile North Slope-to-Alberta pipeline with estimated construction costs of $32 billion to $41 billion in 2009 dollars.
The other alternative is an 800-mile pipeline from the North Slope to Valdez to a possible liquefied natural gas project. A Valdez pipeline would also be 48 inches in diameter and its construction costs are estimated at $20 billion to $26 billion, also in 2009 dollars, Palmer said. TransCanada would build a pipeline to Valdez but a separate party would build the LNG plant, which would cost several billion dollars to construct.
The Alberta pipeline option would be designed to ship 4.5 billion cubic feet of natural gas per day and the Valdez option would be designed for 3 billion cubic feet per day, he said.
Palmer said only one of the two pipelines, either the Alberta or the Valdez option, would be built, depending on shippers' preferences. Not enough gas reserves have been established on the North Slope to supply the 7.5 billion cubic feet of gas needed for both projects.
"We believe both the Alberta and Valdez projects are commercially and technically feasible," as separate projects, but there is not enough gas to do both, Palmer said.
The project would also include a 32-inch, 58-mile pipeline from the Point Thomson gas field to Prudhoe Bay and a large gas treatment plant in Prudhoe Bay. This would be built no matter which pipeline to market is built, the Alberta or Valdez pipelines.
Costs for the 1,700-mile Alberta option are higher than the $26 billion TransCanada initially estimated when it submitted its proposal to the state of Alaska several years ago, Palmer said.
Price for steel and equipment used in pipeline construction have sharply escalated over the last few years accounts for part of the escalation, as does recent declines in the value of the U.S. dollar against other currencies, including the Canadian dollar.
Most of the pipeline will be built in Canada and paid for in Canadian dollars, but the cost is expressed in U.S. dollars, Palmer said.
Another substantial factor is that the gas treatment plant cost is substantially higher than TransCanada initially estimated. Palmer acknowledged that TransCanada has less expertise in development of large process plants that it does in pipelines, and the entry of ExxonMobil last year into planning for the project brought about a more realistic estimate of the gas treatment plant costs. ExxonMobil has substantial experience in the design of such plants, Palmer said.
One major change is that the treatment plant would be built over three years, with three sealifts of large modules and materials brought to the North Slope, rather than two sealifts as TransCanada had previously thought possible.
The gas treatment plant would be capable of processing 5.3 billion cubic feet of raw gas and delivering as much as 4.5 billion cubic feet of processed gas to the pipeline.
Gas in the Prudhoe Bay field contains substantial amounts of carbon dioxide, which must be removed from the gas in the treatment plant before it is delivered to a pipeline. North Slope producers hope to use the carbon dioxide in enhanced oil recovery projects to produce more oil.
Palmer said tariffs have been estimated at $2.80 per million btus (mmbtus) to $3.50 per mmbtus for the pipeline to Alberta and $2.45 per mmbtus to $3.15 per mmbtus for the North Slope to Valdez option.
Either pipeline would generate strong revenues for producers and the state of Alaska, he said.
"Assuming the U.S. Department of Energy's latest forecast of an Alberta gas price of $6.25 to $7.65 per mmbtus from 2020 to 2030, which is the first decade this project would be in operation, we believe our tariffs would result in a wellhead value for gas on the North Slope of approximately $3 to $4 per mmbtus," Palmer said.
The state of Alaska would receive about one-eighth of those revenues through its royalty share of gas production.
It is more difficult to assess possible gas production revenues from the Valdez option, Palmer said, because sales of LNG might occur in either North America or Asia.
If sales were made to North America, and assuming the LNG is shipped from Valdez to an existing regasification plant in Baja California, there could be an additional 75 cents to $1 per mmbtus in transportation costs, Palmer said. LNG sold in Asia would be priced in parity with crude oil prices, which is the basis for most international LNG sales.
Palmer said he hopes the incentives TransCanada has added to the open season offering will encourage the North Slope producers to sign shipping contracts. Even though ExxonMobil is participating in the pipeline engineering and cost studies as a potential pipeline partner, it is the production group within ExxonMobil that will make the decision on any commitment of gas to the project, Pike said.
Palmer said he hopes BP and ConocoPhillips will commit gas during the open season, and that offers have been made to the two companies to join TransCanada's project as investors in the pipeline. However, so far there have been no serious discussions with BP and ConocoPhillips, he said.
The estimated $500 million a year in savings of transportation costs come about through two changes in the project plan, Palmer said. The first is that TransCanada has reduced its expected rate of return on equity for the project from 14 percent, which was in TransCanada's original proposal to the state, to 12 percent in the application filed with FERC, Pike said.
This lower rate of profit would only apply in tariffs for gas committed early to the project, he said, although the lower rate would also be available under renewals of gas contracts originally made early.
The pipeline company would also assume part of the capital risks of the project, which could amount to several billion dollars in risk shifted from shippers to the pipeline company, he said. This will be done by allowing shippers to contract for only 20 years rather than the 25 years TransCanada had originally stipulated as the minimum contract term.
In its FERC tariff, however, TransCanada will stick with a 25-year depreciation schedule for the debt, which could leave the pipeline company paying debt service on bonds for the last five years if there is no new gas committed to the project and assuming the financing is on a 25-year term.
The combination of these incentives, the lower rate of return and the reduced minimum term for shipping contracts, amount to about $500 million in lower transportation costs for gas.
Palmer acknowledged that conditioned bids are anticipated during the upcoming open season but that the pipeline company hopes to have these resolved by the end of 2010.
"However, we understand that there are factors outside our control and the control of shippers and that these could influence the bids," Palmer said.
One of these is the unresolved question for producers, who are likely to be shippers, of a long-term fiscal agreement with the state of Alaska.
Meanwhile, the president of the Denali pipeline group led by BP and ConocoPhillips, which is competing with a separate pipeline plan, said the FERC filing by TransCanada doesn't affect Denali's plan to file for its own open season in April.
"I am confident that we will have an attractive commercial offer for our potential customers. Today's open season announcement by TransCanada and Exxon doesn't change anything for us," Denali president Bud Fackrell said in a statement.
Denali's project is for a North Slope-to-Alberta pipeline similar to that proposed by TransCanada and ExxonMobil. However, Denali will offer no alternative of a pipeline to Valdez.
Tim Bradner can be reached at email@example.com.
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