Special session called on oil taxes, in-state line; bill based on Senate’s new field tax
By Kristen Nelson
It looked like Senate Finance had an oil tax compromise senators could live with when, after weeks of work on the measure, it moved Senate Bill 192 out of committee April 11.
But SB 192 never reached the Senate floor.
The bill, a fundamental change of Alaska’s oil and gas production tax system with different tax rates for existing production from legacy fields, incremental production from legacy fields and new oil, couldn’t garner enough support from members of the Senate Bipartisan Working Group.
On April 14 another plan surfaced, a tax change affecting only production from new fields. Senate Finance added that measure to House Bill 276, credits for exploration and seismic work in frontier basins (see story in this issue).
The Senate passed HB 276 by a vote of 17 to 3, but it got no traction in the House, with portions of HB 276 moved to other legislation and HB 276 withdrawn by its sponsor.
The tax change proposed by Gov. Sean Parnell last year, an across-the-board production tax cut, passed the House last year but stalled out in the Senate, with senators saying they needed more information before making tax changes.
So the session ended with no major changes in the state’s oil tax system.
Within the hour of legislators gaveling out the governor had called a special session to begin April 18, with the oil tax issue, House Bill 9 (the in-state gas pipeline bill) and HB 359, sex trafficking, on the agenda.
‘A new dynamic’
At an April 16 press conference the governor said he was interested in the approach the Senate took in HB 276, and said with the “Senate’s action there’s a new dynamic now at work that I think might lead to a compromise that could produce new production, both now and in the future.”
Parnell said the Senate proposal wasn’t the whole answer because any new oil discovered as a result of the credits wouldn’t be going into the pipeline for a number of years, and he was concerned “that vast resources in our legacy fields will remain untapped.”
The governor also said the Senate’s approach, focusing only on new fields, “will cost the state billions of dollars across 10 years while we have declining production and no new revenues from new production.”
He cited the example of a company proposing to spend $9 billion in the state over the next 10 years on new fields. Under the state’s existing tax structure that company would get credits of between 45 and 65 percent, “so the state will pay half of the cost of that exploration across the next 10 years,” meaning the state would have to come up with $4 billion to $6 billion in that timeframe, while production from existing fields is declining.
The governor said he wants to see a proposal which would incentivize new production from existing fields, along with new field production, and believes that with “a significant tax change in existing fields” the state could see as much as 100,000 new barrels a day “within a year and a half or two years.”
“I want to see whether we can take what the Senate has already agreed is meaningful in the new field context and make it material enough to do the same in existing fields,” Parnell said.
If the Legislature reaches an impasse, Parnell said he would understand.
“But I think it’s worth a try to create a competitive environment where more production can be produced,” he said.
On House Bill 9, a bill moving along work on a small-diameter in-state gas pipeline, Parnell said that if the key provisions in HB 9 don’t pass, “Alaska’s gas line efforts, in my view, will be set back for one to two years.”
The governor said he was asking the House and Senate to waive the uniform rules and take up HB 9 where it was when the session ended; both bodies did that April 18.
Parnell said he disagrees with House Speaker Mike Chenault on whether the Alaska Gasline Development Corp. needs to come back to the Legislature before a pipeline gets built, and said he’s “not trying to empower AGDC at this moment to go and contract and have an open season and sanction a pipeline; I think we have to have some gates they have to go through where they are held accountable by the Legislature and by the executive.”
On the other hand, the governor said he doesn’t agree with legislators who believe AGDC’s “efforts should be killed off.”
“I’m not in that camp,” he said, explaining that the state needs alternatives — the large line from the North Slope to markets and the smaller in-state line — because without an option, the process would slow down, as it did under the Stranded Gas Act negotiations “when one party’s negotiations were swept off to the side and ... the process slowed down and the state had no other alternative.”
The new bill
The governor submitted a new oil tax bill to the House and the Senate April 18, describing it as “a piece of legislation that blends the positions of the House and Senate into a comprehensive approach that will bring economic opportunity to Alaskans for generations to come.”
New North Slope oil and gas production is incentivized with a 30 percent exclusion, based on gross value at the point of production or GVPP, from the production tax value used to calculate the base rate and progressivity for the first 10 years of sustained production. This applies to fields not in production or in a unit on Jan. 1, 2008 — which would exclude Point Thomson but include Oooguruk and Nikaitchuq.
For currently producing North Slope fields, there is an exclusion, but only from the value used to calculate progressivity: 40 percent of the GVPP would be excluded from the monthly production tax value used to calculate progressivity; progressivity would be capped at 60 percent.
The bill also extends tax incentives for well lease expenditures available elsewhere in the state to North Slope activities and allow producers to apply tax credits in one year.
The new-oil provision
So what would the 30 percent exclusion in calculating base rate and progressivity for the first 10 years of sustained production look like?
Senate Finance had PFC Energy model the lifecycle effects for a new small development — a 70 million barrel field with peak production of 10,000 barrels per day at $100 oil.
Finance co-Chair Bert Stedman, R-Sitka, said at the April 14 hearing when the proposal was first aired publicly that the “concept of the 30 percent gross revenue allowance was derived out of our previous work on trying to enhance new oil production” with a gross progressivity calculation, and is an approach to incentivizing oil outside of existing developments within the current ACES structure.
Gerald Kepes, a partner in PFC Energy and head of the consultancy’s upstream and gas practice, showed models run at the 30 percent gross revenue allowance for new developments at three different development costs: $17 per barrel; $25 per barrel; and $34 a barrel.
Kepes said with a $17 per barrel capital cost under the current tax, Alaska’s Clear and Equitable Share or ACES, a lifecycle analysis showed a net present value or NPV of $112 million and an internal rate of return or IRR of 16 percent, with total government take ranging from 67 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil.
With the gross revenue allowance of 30 percent applied to ACES, NPV rose to $201 million and IRR to 20 percent; government take ranged from 56 percent at $60 oil to 64 percent at $100 oil and 66 percent at $150 oil.
“So it’s a substantial difference for these lower-cost new developments,” Kepes said.
Capex of $25 a barrel
At development costs of $25 a barrel for the same new development, which Kepes said “is more in line with the costs that we see with these new developments ... away from existing infrastructure,” NPR under ACES would be $24 million and IRR 11 percent, with government take ranging from 68 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil.
At the $25 a barrel capital cost with the 30 percent gross revenue allowance, NPV is $121 million and IRR 14 percent, with government take ranging from 51 percent at $60 oil to 62 percent at $100 oil and 67 percent at $150.
At a capital cost of $34 a barrel, which Kepes characterized as “among the higher or highest cost rates that we’re looking at,” under ACES NPV is a negative $90 million and IRR 7 percent, with government take ranging from 80 percent at $60 oil, to 77 percent at $100 oil and 79 percent at $150 oil.
With the 30 percent gross revenue allowance, NPV on this type of project is a positive $3 million and IRR 10 percent, with government take ranging from 49 percent at $60 oil to 62 percent at $100 oil and 66 percent at $150 oil.
Legislators received a letter from 70 & 148 LLC, a partner with Repsol in new developments which have been cited at capital costs of $9 billion over 10 years, expressing “strong support” for passage of the new oil provisions Senate Finance added to HB 276, calling the new field tax changes “exactly what is needed in order to have the oil industry focus on Alaska over other oil producing regions,” but also noting that the company hopes modifications can be made in the tax code “that will make operations within the legacy fields more competitive as well.”
How many of the 10 largest oil and natural gas companies are owned and operated by foreign governments? If you answered all ten, you’re correct.
API and Harris Interactive have released the findings of the 2008 Energy IQ. The annual survey of U.S. energy knowledge illustrated that Americans are more informed about key energy issues than they were one year ago. For instance, more than half the respondents correctly answered that we will need between 16 and 20% more energy between now and 2030. However, some misperceptions remain; respondents underestimated the amount of energy produced in North America.
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