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Vol. 15, No. 12 Week of March 21, 2010
Providing coverage of Alaska and northern Canada's oil and gas industry

ACES: more bad than good

House panel hears mostly nays, a few yeas, on results of ACES production tax

Kristen Nelson

Petroleum News

When House Resources heard comments from industry March 10 on its proposed changes to Alaska’s current production tax it heard a litany of woes about what is wrong with ACES, Alaska’s Clear and Equitable Share, enacted in 2007.

While independents generally spoke in favor of the credits ACES provides, they also told legislators that there is no ready market for the credits, so companies without production and taxes were disadvantaged against producers.

Marilyn Crockett, executive director of the Alaska Oil and Gas Association, called the Resources bill, House Bill 308, an important first step in an overview AOGA believes should be undertaken on the issue of whether ACES is garnering the investment that was expected when it was enacted.

HB 308 would reduce the interest rate on underpaid or overpaid taxes, allow interest to be waived when it is due to retroactive regulations, reduce progressivity in ACES from 0.4 percent to 0.2 percent, offer a tax rebate for resident hire, provide a 30 percent credit for well work and restore the three-year statute of limitations on auditing of tax returns.

She addressed three problems AOGA sees with ACES: the tax rate, the “impossible plight” of non-operating companies and the inability of taxpayers to determine with certainty what taxes will be based on the regulations.

On the excessive tax rate issue, Crockett said there has been a lot of discussion of investment, but AOGA thinks the number of new in-field wells drilled is more telling, dropping from 166 in 2007 to 155 in 2008 and 147 last year.

She noted that BP has said that its in-field drilling this year will be less than half of what it was in 2007. And while 450 million barrels of oil equivalent of reserves have been added on the North Slope in the last five years, only 35 million have been added since ACES was passed.

On the non-operator issue, Crockett said non-operators receive only monthly billings from the field or unit operator with a description of the cost items, but without timesheets or other documentation and without copies of billings from third parties that the operator has received and paid.

She said there is virtually no way a non-operator, for example, can know which of 336 cost codes or categories in Revenue’s regulations relate to the 20,000-plus cost codes used to allocate costs at Prudhoe Bay.

Small independents

Greg Vigil, senior vice president of Savant Alaska LLC, told the committee that Savant has earned or redeemed $19 million in ACES tax credits since the inception of the program. The secondary market for these credits it thin at best and he said Savant generally supports the governor’s proposed amendments to ACES.

As Commissioner of Revenue Pat Galvin explained the credit aspects of the governor’s bill, HB 337, a 30 percent credit would be added for all well-related work; credits could be used in the first year, while the current law requires them to be spread out over two years; and the bill eliminates the existing requirement that to get state reimbursement companies without current production have to make additional investments in the state. The governor’s bill also allows interest to be waived when it is the result of retroactive regulation.

Vigil said that in Savant’s view the exploration incentives and qualified capital incentives in ACES are meaningful. He said the company has remained silent on progressivity because it didn’t have any production, but now that Savant expects to have production from Badami it sees progressivity as a disincentive.

He said ACES’ progressivity is an incentive to Savant to be mediocre because it results in a diminishing return per incremental barrel produced as indicated by the company’s economic modeling at Badami.

Mark Landt, executive vice president of land and administration for Renaissance Alaska told the committee that there isn’t a liquid market for the credits. One producer, he said, would only acquire them at 50 cents on the dollar and others said they weren’t acquiring them at all because of lack of certainty around the regulations.

Landt said the state needs to level the playing field between new and existing players. He told Seaton he would be supportive of anything that would expand the market for tax credits and said a proposal to let the Alaska Retirement Management Board purchase the credits at an 8 percent discount would be better terms than what Renaissance has seen for the producers.

But, Landt said, since the state pays 100 percent in the end he doesn’t see why non-producers have to go through a secondary market.

Large independent: Anadarko

Mark Hanley, public affairs manager for Anadarko Petroleum in Alaska, said Anadarko, a large independent, has production from Alpine, where it has a 22 percent interest, and is looking for gas on some 4 million acres in the Foothills.

Hanley, a former legislator, told the committee that what he sees as the problem that policy makers should consider is the North Slope’s declining production.

To make up for that decline, the state needs to see an Oooguruk or a Nikaitchuq come online every year or every other year.

The real issue, he said, is investment adequate to do that?

People used to say you needed to drill at least 15 exploration wells a year because not all wells are successful, Hanley noted. “Is there enough investment for new discoveries? I don’t think there is,” Hanley said.

And if there isn’t enough investment, he said, “I’d suggest something needs to be done to increase the investment.”

Anadarko will go where it can make money, he said. In Alaska the cost of pipeline and tanker transportation add to the cost of projects and the state’s royalty if fixed. But one thing the state can control is taxes, he told the committee.

Anadarko testified early on that the company thought the net system was a good one because it takes into account higher costs for some fields and newer production. But just because it’s a net system, if the tax is too high it doesn’t work, he said.

Credits help, he said, but Alaska is still challenged on net present value from projects because of the short exploration season.

Referring to a Department of Revenue comparison between taxes under ELF, PPT and ACES, Hanley said there wasn’t enough investment under ELF and the state is now taking roughly $2 billion a year more in taxes.

“If it sounds too good to be true, it probably is,” he said, telling the committee that it’s hard to argue that taking $2 billion out of industry improves industry’s economics or encourages more investment.

PPT (the predecessor to ACES) improved Anadarko’s exploration numbers, he said, but existing fields got hit hard.

And ACES is even worse than PPT, he said.

Hanley said ACES is complicated and he wouldn’t go into all of the details, but “overall it’s too high; it’s not getting the investment” and it’s hard for Anadarko’s Alaska projects to compete with projects the company can do elsewhere.

The majors: ExxonMobil

Dale Pittman, Alaska production manager for ExxonMobil, told the committee ExxonMobil supports AOGA’s presentation and said he would not repeat the technical comments from that testimony.

He said that, consistent with ExxonMobil’s testimony during hearings on PPT and ACES, the company “believes Alaska’s current production taxes are too high to result in the additional investment needed to maximize the development of Alaska’s resources.” Pittman said ExxonMobil believes that even the 20 percent tax originally proposed under PPT “would not encourage the full development of Alaska’s resources.”

He said that while spending on the North Slope has been relatively flat since ACES was enacted, “the majority of that investment has been for maintenance or production enhancement efforts for existing operations, not for new exploration and development opportunities.”

It takes about $1 billion a year just to maintain North Slope production at the current 6 percent decline rate, Pittman said, and without that investment the decline would be closer to 12-15 percent annually.

Pittman brought a very long-term perspective to the discussion, telling the committee that time in the oil industry is measured in decades and generations. “Today’s production rates are the product of government policies, technical work and investment decisions that in many cases were made decades ago,” he said.

He said legislators need to decide whether Alaska’s high production tax is right for Alaska or, “given the current high costs and steadily declining oil production rates we face — if another course is necessary to harness the remaining resource potential.”

The majors: ConocoPhillips

Brian Wenzel, ConocoPhillips Alaska’s vice president of finance, said ConocoPhillips supports HB308 not because it addresses all of the company’s concerns but because it’s a step in the right direction toward a more attractive business climate.

Wenzel noted that core fields on the North Slope — Kuparuk, Prudhoe and the Alpine area — provided 90 percent of North Slope production in 2009. He showed a slide illustrating that those core fields also contain the majority of the remaining barrels on the North Slope, dwarfing accumulations at Point Thomson, Nikaitchuq, Liberty and Oooguruk.

With 90 percent of the remaining barrels in core fields, “you should be structuring your fiscal system to encourage investment there,” he said.

He also compared the Department of Revenue’s 2008 forecast of remaining barrels in the North Slope’s core fields (Prudhoe, Kuparuk and Alpine) with the department’s 2009 forecast, which showed about a 20 percent reduction due to higher decline rages. Wenzel said ConocoPhillips believes this is related to less investment in those core fields and he noted that industry well completions were down 14 percent from 2007 through 2009.

He also compared the Department of Revenue’s oil price, the Baker Hughes U.S. oil rig count and ConocoPhillips figures for the rig count in Alaska’s core fields. The U.S. rig count, he said, tracks the oil price while the rig count in Alaska’s core fields has been flat or declining beginning in the third quarter of 2007, and fell when the U.S. rig count rose steeply in the second half of 2009.

In addition to rigs, overall spending is a leading indicator that creates concern, Wenzel said, and while the administration has cited increases in spending, when adjusted for inflation spending has been flat from fiscal year 2007 through fiscal year 2010. And while core field investments increased from 2005 through 2008, declining in 2009, most of the increase was for maintenance, replacement and repair, Wenzel said, with development projects and drilling remaining relatively flat.

In recent project activity, he noted that Oooguruk began prior to ACES and has royalty relief; Nikaitchuq has royalty relief; and Liberty is not subject to ACES (the field is on federal outer continental shelf acreage).

More than $2 billion in projects have been deferred since ACES was passed, he said, including Prudhoe and West Sak work.



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