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April 2008

Vol. 13, No. 17 Week of April 27, 2008

Formal transmission not until June 3

If AGIA license recommended, 60-day review would begin with special session; admin says AGIA doesn’t affect sovereign rights

Kristen Nelson

Petroleum News

The administration of Gov. Sarah Palin and the Alaska Legislature are continuing to work out details of how review of an AGIA license — if one is granted to TransCanada — would be scheduled.

The governor said April 18 that it is still the goal of the commissioners of the departments of Revenue and Natural Resources to complete the findings and determination for the TransCanada Alaska Gasline Inducement Act application the week of May 19. But based on feedback from legislators — if the commissioners decide to pursue an AGIA license — formal transmission of any findings materials to the Legislature won’t occur until June 3 when the special session convenes.

“This action will allow the special session to begin on the same day that the 60-day review period begins for the Legislature under AGIA,” the governor said.

The administration will proceed with the previously announced three-day presentation of information May 28-30 in Anchorage. The governor said these sessions are intended as “a public presentation to the members of the Senate and House in preparation for deliberation in Juneau, and provide an enhanced opportunity for interaction between legislators and AGIA team members and our consultants.” The presentation will be at the Sheraton Hotel.

What would state be committed to do?

As the Legislature prepares to review a possible administration award of an AGIA license to TransCanada, legislators are looking at questions arising from the company’s application.

Among the issues raised during legislative hearings and in public comments on the application is what would a license commit the state to do?

“Would the State of Alaska have a right to represent what it considers to be in its best interests” in hearings for certificates for the project before the Federal Energy Regulatory Commission and the National Energy Board of Canada, Rep. Ralph Samuels, R-Anchorage, chair of the Legislative Budget and Audit Committee, asked Gov. Sarah Palin in a March 26 letter.

How many of the “terms and conditions” in TransCanada’s proposal would the state be committed to support, he asked, listing the company’s return on equity, debt-equity ratios and cost overrun financing proposals. These are “critical questions” raised in the Legislature and in public comments on TransCanada’s AGIA application, Samuels said.

State would protect its interests

The response came April 18, in a letter from Deputy Commissioner of Natural Resources Marty Rutherford, who heads the administration gas line team.

Rutherford said that if the administration recommends a license and the Legislature approves that license it is reasonable to assume that the state and TransCanada “would be allied in pursuit of a project on mutually beneficial terms.”

But that does not mean, she said, that the state would be required to support the license before any agency if it was not in the state’s best interest to do so.

The state didn’t limit its sovereignty in AGIA or in the request for applications. The licensee and the state are likely to have similar interests in many cases, but “the state would not be required to advocate for the same terms and conditions proposed by the licensee before FERC, NEB or any other agency with regard to an ANS natural gas pipeline project.”

What TransCanada would get in a license would be the terms enacted by the Legislature under AGIA, Rutherford said: “primarily the project construction inducement under AS 43.90.110 and expedited review and action by state agencies under AS 43.90.260.”

TransCanada would also, she said, “be subject to all other requirements, terms and conditions that AGIA has set forth for the licensee.”

Not MidAmerican

Samuels has requested information for legislators from TransCanada, LB&A’s consultants and from companies formerly involved in efforts to build the Alaska portion of a North Slope to market gas pipeline.

At the end of February he asked the withdrawn partners of the Alaska Northwest Natural Gas Transportation Co. or ANNGTC (the partnership formed to build the Alaska portion of the original 1970s-early 1980s project to move Alaska North Slope natural gas to market) whether they would be willing to waive their rights under the ANNGTC partnership agreement. He also asked whether they believe the corporate structure used by TransCanada in its AGIA application violates any obligation to their companies under ANNGTC.

The withdrawn partners issue has been much discussed because it is the source of a potential $9 billion liability.

There were 11 original partners in ANNGTC; all withdrew except two, both of which are currently TransCanada subsidiaries. The original partnership agreement provided that partners who withdrew forfeited all of their rights as partners but, because it was expected that the line would be built soon, they had the right to receive their original contribution, about $24 million per partner, with interest, if ANNGTC built the Alaska segment of the line. With interest those cumulative obligations are some $9 billion.

TransCanada has said it does not intend to build the Alaska segment of the gas pipeline under ANNGTC, nor will it use anything belonging to ANNGTC: The Alaska portion of its AGIA application proposal starts from scratch.

But there has been concern that the current owners of the withdrawn partners could sue, so Samuels wrote to the six current non-TransCanada owners. Two have responded.

Sempra Energy said that to the extent it has “certain continuing rights under the ANNGTC agreements … (it) is not willing to waive any of its rights as a withdrawn partner.”

But it also said that based on the corporate structure used by TransCanada in its AGIA application, “we are not aware of any obligation under the ANNGTC General Partnership Agreement that is being violated by TransCanada.”

The other response came from MidAmerican Energy Holdings Co.

TransCanada told the state it believed MidAmerican was the “current ultimate parent” of Northern Arctic Gas Co.

MidAmerican Chairman and CEO David Sokol said that was not the case — that Northern Arctic Gas Co. “is not, and never has been, a subsidiary or affiliate” of MidAmerican.

Sokol said when MidAmerican Energy Holdings Co. purchased all of the capital stock of Northern Natural Gas Co. in 2002, Northern Natural Gas had no subsidiaries. He told Samuels that it is MidAmerican’s understanding that Northern Arctic Gas Co. was a subsidiary of InterNorth Inc., which merged with Houston Natural Gas Co. around 1986.

The company name was changed to Enron Corp.

S

Econ One looked at TransCanada’s values to stakeholders

amuels has also requested work from consultants, asking Econ One for a review of project economics figures provided by TransCanada, as well as figures presented by ExxonMobil in its comments on the TransCanada AGIA application.

Econ One used the same destination prices for natural gas and natural gas liquids as TransCanada — Energy Information Administration forecast prices and TransCanada’s estimates of a basis differential between Henry Hub and Alberta for natural gas and TransCanada estimates of NGL prices at Alberta — Barry Pulliam of Econ One said in an April 10 memo.

Pulliam said Econ One calculated “virtually the same” tariffs and per-million British thermal unit netback values as TransCanada, but “revenue flows to stakeholders differ” from those presented by TransCanada “in several areas.”

The Econ One analysis shows revenues to TransCanada as almost exactly the same as TransCanada’s numbers: total 25-year revenues of $16 billion; first year revenues of $1.3 billion (TransCanada) and $1.2 billion (Econ One); and annual average revenues over 25 years of $700 million.

But there are differences in what the State of Alaska, the federal government and the producers receive.

Pulliam attributed those differences to key assumption differences including: costs of gas production; how royalties are calculated; and the level and application of production taxes.

The stakeholder values are based on no expansions, so the volume would be 4.5 billion cubic feet per day for 25 years.

Costs a factor in royalties, taxes

The value to producers is calculated after royalties and taxes but before upstream costs, which TransCanada estimated at $1.50 per million Btu, in 2007 dollars, for all gas production. Econ One, by comparison, estimated “production costs based on the incremental (or additional) costs that would be incurred to produce gas,” Pulliam said.

Since Prudhoe Bay is already in production, “those additional costs are minimal,” he said. Costs would be higher for fields not yet developed. “For gas-only fields, incremental costs will be equal to the total costs to develop and operate the field,” he said.

TransCanada estimated producer revenue over 25 years would total $183 billion, less $109 billion in upstream costs, for a total of $74 billion — $1.3 billion in the first year and an average of $3 billion a year over 25 years.

Econ One, using a much smaller upstream cost of $37 billion, estimated total return to producers of $95 billion. Econ One also estimated less revenue to producers before upstream costs (only $132 billion) because it “estimated that production taxes at forecast prices and costs would be higher” than TransCanada estimated.

TransCanada estimated revenues to the State of Alaska of $115 billion over 25 years; $2.5 billion in the first year; and an average of $4.6 billion per year over the life of the project. Econ One estimated the state would earn $152 billion from the project, $3.3 billion in the first year and an average of $6.1 billion over 25 years.

TransCanada projected the U.S. government would garner a total of $46 billion, $1.2 billion in the first year and an average of $1.9 billion a year. Econ One estimated U.S. government take at $61 billion over 25 years, $1.4 billion in year one and an average of $2.4 billion a year.

Econ One on royalties, taxes

Pulliam said that while TransCanada used a 12.5 percent rate for royalties to the state, it used 12.6 percent to reflect higher royalty rates at Point Thomson. He also said TransCanada’s figures reflect a deduction of $1.50 per million Btu for upstream costs. “Royalties should be calculated based on netback values, less ‘field’ costs, per settlement agreement with the State,” he said, with field costs totaling about 24 cents per million Btu in 2007 dollars. Pulliam said Econ One assumed those field costs would be deductable against royalties on Prudhoe Bay production.

The total is $17 billion more to the state over 25 years than estimated by TransCanada.

Pulliam said TransCanada used a production tax rate of 25 percent, but did not deduct royalty payments from production tax obligations. Production taxes, he said, are based on net proceeds — “after deduction of royalties and upstream costs.”

TransCanada also did not calculate the progressivity rate in Alaska’s tax that increases the rate above 25 percent when prices are higher.

Pulliam said Econ One’s “analysis estimates incremental production tax revenues that would flow from gas production,” and estimates production taxes at forecast prices and costs would be higher by some $25 billion than those used by TransCanada in its analysis.

The state gets more money under the Econ One analysis, $37 billion, Pulliam said, “largely due to higher estimates of royalties ($17 billion) and production taxes ($25 billion) but offset by lower estimates of income taxes (minus $5 billion).”

The federal government gets more in revenue under the Econ One analysis. Some $3 billion is in royalties — TransCanada does not include royalties on federal lands — “and $11 billion in additional income tax generation associated with lower production costs,” Pulliam said.

ExxonMobil figures closer

Econ One said its results, under the same scenarios as presented by ExxonMobil, “are largely (and directionally) consistent with the figures it presents, though there are some minor differences.”

In figuring the total equity return for TransCanada under its base case, Econ One said it used the $16.4 billion TransCanada used in its Jan. 15, 2008, submission, while ExxonMobil started with the $17.1 billion TransCanada used in its original application. TransCanada later corrected the inflation factors in the application, Pulliam said in an April 9 memo to Legislative Budget and Audit.

He said Econ One also found “a somewhat higher impact” on TransCanada’s equity return for cost penalty scenarios under two of ExxonMobil’s scenarios. (TransCanada proposed penalties for cost overruns in its AGIA application.)

Econ One estimated that in a 40 percent cost overrun scenario TransCanada’s equity return would increase by $5.4 billion under its proposed equity penalty formula and by $3.3 billion under an alternative in which the equity penalty would apply for 25 years rather than five years. ExxonMobil’s numbers in the same cases were increased returns to TransCanada of $3.8 billion and $2.2 billion, respectively.






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