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Vol. 11, No. 10 Week of March 05, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

20-20 tax credit unveiled

Alaska lawmakers question decrease from van Meurs’ 25/20 tax, $73M deduction

By Kristen Nelson

Petroleum News

Murkowski administration officials got a lot of questions from legislators Feb. 22-24 as they described the proposed petroleum profits tax to House and Senate Resources committees.

Commissioner of Revenue Bill Corbus told the committees Feb. 22 that this is the first major oil and gas tax legislation pursued by an administration since 1989. The profit-based tax will replace the existing severance tax and economic limit factor, “which is a broken system,” Corbus said. It will encourage badly needed investment in oil and gas exploration and production and provide help for small companies.

And it will, especially during high oil prices, increase revenues to the state.

Corbus said consultant Pedro van Meurs was brought in by the prior administration to look at the tax system. “Immediately after taking office this administration started working on this issue,” he said.

Corbus immediately got a question from House Resources Co-Chair Ralph Samuels, R-Anchorage, on why the administration talked about a 25 percent tax rate and a 20 percent credit, and then rolled out a bill with a 20 percent tax rate and a 20 percent credit.

Corbus said van Meurs recommended the 25-20 rates, but after the administration met with producers they decided on the 20-20 rates as “acceptable to both parties.”

Rep. Mary Kapsner, D-Bethel, asked about the effective date, noting that the governor had said the bill would be retroactive to Jan. 1, but that date isn’t in the bill. Corbus didn’t offer an explanation; he just said the effective date in the bill is July 1.

Commissioner of Natural Resources Mike Menge said the governor’s decision to recommend the 20 percent tax rate took into consideration not just the major North Slope producers, but a whole range of companies. The state hopes to encourage mid-sized and smaller companies to come to the state and explore for 100 million to 150 million barrel fields, he said.

Menge said the Cook Inlet and Aleutian basins need exploration, as do Interior basins, and the state is trying to provide incentives for companies “to roll that dice.” The state would provide incentives for exploration, he said, and if the companies are successful the state would garner benefits.

Into the details

Department of Revenue Tax Division Director Robynn Wilson and Dan Dickinson, her predecessor and now with the governor’s office, talked about the details of the bill.

Oil provides the largest piece of the state’s revenue pie, Dickinson said, $3.4 billion of $8.9 billion for fiscal year 2005.

Royalties are the largest portion of oil revenues: $1.42 billion in royalties and bonuses with $863 million coming from production tax. This year the amount from production taxes could be “north of $1 billion,” he said, because of high oil prices.

The current production tax is based on the economic limit factor or ELF multiplied by the severance rate of 15 percent on production.

There are three issues with the present system, Dickinson said: the impact on revenues; the current system doesn’t have a positive impact on investment; and declining production.

“We’ve been looking at production tax issues for two years,” he said. One result was the aggregation of Prudhoe Bay satellites for severance tax.

Wilson said there is no incentive in the present tax system to reinvest in Alaska; there is a low take for the state compared to international systems at high prices and a high take at low prices; and the maturing of the North Slope, with dropping production, leads to declines in tax revenue.

Rep. Norm Rokeberg, R-Anchorage, said ELF might not be working, but it was designed to create reinvestment by encouraging the development of smaller fields.

Dickinson said that was a fair point: ELF is not an effective incentive, he said, because there is no specific incentive tied to investment.

Either tax or investment under PPT

Under the proposed production profit tax, with its 20 percent provision for tax credits for investment, “we either get the tax or we get the investment,” Dickinson said. He showed an example where the current tax, which would jump from $927.6 million to $1,607.6 million under the proposed production profits tax, would remain the same — with credits — if there were an additional $1.7 billion in investment.

ELF, the economic limit factor, was supposed to be a proxy for cost, he said, but it turned out to be “a very poor proxy for costs” and doesn’t deal with the price range that we see today.

Two main features of the PPT are that it provides a credit for investments that are made and it recognizes that it costs money to get oil out of the ground.

Wilson said the proposed tax represented four ideas: encouraging investment; providing competitive tax rates internationally; encouraging small companies; and streamlining the tax process.

Five components

Wilson said there are five components in the PPT: the net tax base; the tax rate; incentive credits; the base allowance; and the transition provision.

The current system is based on gross; the new system will be based on net. The base rate will be 20 percent and there will be incentive credits. There will be a base allowance of $73 million a year per company, something akin to the standard deduction on personal federal income tax, she said.

Wilson said the deduction cannot be used to reduce taxable income below zero and does not create a loss that can be carried forward.

And the transition provision recognizes recent investments in oil exploration and production, allowing cost recovery of assets placed in service from July 2001 through June 2006, with a deduction of one-sixth of the cost in each of six transition years and the deduction available only when the average price of oil exceeds $40 a barrel.

Samuels said that at $60 a barrel, the investment has probably been recovered.

Lease expenses will be deducted to arrive at a net price, including: operating costs, capital expenditures; and allowance for overhead. Wilson said the department will write regulations covering these deductions, which must be direct costs and ordinary and necessary.

The current statute has 12 words on costs and the department has written hundreds of pages of regulations, Dickinson said. The new tax will have more on costs in the law, although regulations will still be required.

Wilson said the bill also attempts to simplify marine transportation cost issues, which are currently the subject of a lot of audit activity. Under the profit sharing bill, the producer can elect to use royalty value from a settlement agreement or other royalty value accepted by the Department of Natural Resources or the federal government, or a formula that the department would write in regulations.

Credits for capital expenditures and losses

In addition to deducting lease expenditures, the bill provides for a 20 percent credit for qualified capital expenditures, including exploration costs. The taxpayer can take these credits off the tax bill or turn them into credit certificates and sell the certificates. A purchaser of credit certificates can use them for up to 20 percent of its taxes; the company earning the credits can use them for up to 100 percent of its taxes.

Because the tax base is net, the new system recognizes losses (such as a new company exploring and spending money in advance of any production creating income). If a company has a net loss, it pays no production tax. In addition, 20 percent of that loss can be converted into credits, which can be sold.

Rep. Les Gara, R-Anchorage, objected to bigger companies getting deductions “on both ends” — for exploration and development spending.

Dickinson said the notion of bigger or smaller doesn’t enter in. The state has given exploration incentives, he said, but this bill takes a larger view and also favors development of known resources such as heavy oil.

Rokeberg said he was concerned about the potential of a two-tiered system and Dickinson said the administration was trying not to create a multi-tiered system, but wanted to give companies the “same bang” for exploration or development spending.

More on 'clawback' and 25/20

Consultant Pedro van Meurs told House Resources Feb. 23 that the capital expenditure clawback proposal — the transition provision — would allow a 20 percent recovery of capital expenditures over the last five years.

Asked by Rep. Gabrielle LeDoux, R-Kodiak, what the capex clawbacks are, van Meurs said they were developed by Dan Dickinson to allow companies that have been investing over the last five years to take their capital expenditures as a deduction in the future when oil is more than $40 a barrel.

Van Meurs said work by Department of Revenue economist Roger Marks indicated that the 25 percent tax level and 20 percent credit level resulted in higher revenues to the state, and a consultant for Legislative Budget and Audit agreed, so he changed his recommendation to 25/20. The decision to use a 20/20 level in the bill came after his report was completed, van Meurs said. He said he preferred either 25/20 or 20/15 because the tax rate is high enough to balance the credits. The 20/20 combination is riskier, he said: “If you go into large tax credits because of large investments” there will be “less revenue.” In a situation where companies invest heavily, 20/20 is “somewhat riskier for the state” than 20/15 or 25/20, he said.

Van Meurs said he understood the “whole clawback provision” is just a $1 billion item, a relatively minor component which wouldn’t change the economic impacts. It will result in somewhat lower taxes coming in for a few years.

Why not 30/20?

Rokeberg asked that if a balance was the goal, why wasn’t the bill drafted at 30/20?

Van Meurs said he did analyze 30 percent, but recommended against going too high on tax because it would make the system gradually less competitive. As overall government take becomes gradually unattractive compared to other regimes, companies might begin to invest less in Alaska, he said.

The goal, he said, is to have a fiscal system adequate for an ANWR field on one end and ongoing North Slope field developments of 50 million to 150 million barrels on the other end.

The production profits tax, he said, is designed to stimulate heavy oil, exploration in areas like the National Petroleum Reserve-Alaska but also to stimulate exploration in areas like Cook Inlet and Bristol Bay.

The world is very competitive and companies are looking for new opportunities, van Meurs said: the PPT is oriented to investment and reinvestment and “will get immediately the attention of a wider group of companies.”

Rep. Beth Kerttula, D-Juneau, asked about the bill’s provisions to expand credits beyond the traditional exploration tax credits the state has offered.

Van Meurs said the reason for the broader tax credit is that the “problem in Alaska is infrastructure, it’s not just exploration.” The lack of infrastructure is an “enormous obstacle for investors.”

By offering a tax credit for all capital expenditures, it provides “help for smaller companies to build the infrastructure so a wider group of companies will have access to facilities,” forming “a much stronger basis for development.”

Advantages for small companies

Revenue’s Roger Marks highlighted provisions of the bill crafted to help small producers for House Resources Feb. 24.

Small producers, he said, bring advantages to the state because they have a bigger appetite for smaller targets. They also bring diversity — more ideas on how to explore and develop and are less risk adverse than large producers.

The ability to sell losses, the ability to sell credits and the $73 million allowance are the three mechanisms geared to help both small producers and new investors, he said.

A new company which incurs capital costs before it has revenue can convert the loss to a credit at the tax rate of 20 percent and it’s marketable, Marks said. Credits being sold for exploration in the state today are selling at about 90 percent of face value, he said. This allows a company to monetize their loss “at day one rather than having to carry it forward” and on a net present value basis that’s very important, Marks said.

Samuels and Rep. Paul Seaton, R-Homer, had questions about this credit.

Samuels asked wasn’t the state still on the hook for the full amount, whatever the credit sold for? Marks said that was correct. Both Samuels and Seaton wondered if the state wouldn’t be better off just giving the money directly to the new player because the credit sells for less than face value. Marks said he would need to think about that, but, he said, the only thing that gives the credit value on the market is the cut rate.

Rep. Ethan Berkowitz, D-Anchorage, was concerned that the market is so small that the price will be severely discounted.

Marks said that in the existing credit programs credits have sold at about 90 percent of face value.

Rep. Lesil McGuire, R-Anchorage, said if the goal is to provide an incentive for smaller companies to explore, why not just directly give the tax credit to small companies, dollar for dollar, why create a market to do that?

Credits only applicable against production tax

LeDoux asked if the tax loss could be sold to anyone.

Marks said it was only applicable against production tax to protect the state’s revenue base. If the oil price was in the tank, he said, and credits could be used against other taxes, like the state income tax, that would cut further into the state’s revenue base. He said he thought it would take “incredibly low prices, say $10 a barrel,” to make credits of no value to big producers.

Resources Co-Chair Jay Ramras, R-Fairbanks, said he was concerned about oil dropping from $60 to $35 and producers buying every available credit: What, he asked, would the state’s fiscal exposure be?

Marks said credits you buy can be used for no more than 20 percent of your tax liability. Credits a company earns can be used for 100 percent of its own tax liability.

Rep. Harry Crawford, D-Anchorage, said he was concerned about the big producers, as the only market, forcing down the price on credits. In that scenario, he said, they would get the benefit and the state would still be on the hook for 100 percent of the value. He suggested that the state should also be willing to buy at a certain level so major producers didn’t get too much of a windfall. Marks said there may be some interesting things that can be considered as the bill evolves.

Several legislators had concerns about the state taking a bath on credits if prices dropped and there was discussion about the state buying back at a certain level. The tax division’s Wilson said she thought the concept of transferable credits was to keep the state out of the process. If the state steps into the process, she said, maybe a refundable credit would be the simplest way. She said she didn’t see any value to the state in being a middleman.

Tax-free allowance

Marks said small fields pay little or no tax under the present system and the administration believes this should continue as marginal field development will generate economic benefits. The $73 million tax-free allowance is based on a model of $40 per barrel at the wellhead and 5,000 barrels per day paying no tax.

Marks said the department has been asked if thousands of companies wouldn’t come in to take advantage of the $73 million. He said the department believes the companies would come in and take a look at targets like the Nenana basin: “We think this is a good thing.” The department believes companies would look for new targets to take advantage of the allowance.

Given the goal to consider treatment for small fields, 5,000 barrels per day is a judgment call, Marks said. Kerr-McGee and Pioneer came to the North Slope under a system where they wouldn’t pay on 20,000 bpd; now they will pay on the last 15,000 bpd, he said.

Gara said he was concerned that with the tax credit and the $73 million allowance in the bill benefits companies like BP that you shouldn’t be trying to benefit.

Marks said that relatively this will help small companies much more than big companies.

He said it also treated companies the same in terms of the tax code: different benefits to different companies in the tax code is an invitation for “monkey business,” Marks said. He also said that the benefits were factored into the tax rate.

Allowance up to $73 million

At $40 per barrel Marks said the department expects seven companies will take the full deduction of $73 million annually — the first $73 million dollars pays no production tax — which at a 20 percent tax rate costs the state about $100 million a year.

Seaton asked how many full deductions the department expects to see at its current long-term forecast of $29.50 per barrel. Marks said less than seven, maybe five at that rate.

Berkowitz asked what the cost would be if the allowance were applied today, and Marks said $100 million a year.

Berkowitz asked who would get the bulk of the allowance and Marks said the seven biggest companies.

But smaller companies would benefit most, Marks said. Since companies pay no production tax on the first $73 million, the main beneficiaries would be smaller companies, who likely would pay no production tax, Marks said.

LeDoux asked about the possibility of doing something that would benefit only smaller companies.

Marks said you could, but that would lead to stresses between new and old companies. If you’re BP looking at a small field and you don’t get the allowance and someone else does, that puts BP at a competitive disadvantage. A level playing field and uniform treatment is the goal, Marks said.



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