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Alaska oil tax: PPT with numbers Pedro Van Meurs and Roger Marks give Alaska legislators numeric examples for proposed production profit tax Kristen Nelson Petroleum News
There isn’t a bill yet — and legislators aren’t sure when they’ll see one.
But they did get a walkthrough Feb. 1 of what revenues from the administration’s proposed profit sharing production tax on oil would look like compared to the present system.
Consultant Pedro van Meurs and Department of Revenue petroleum economist Roger Marks presented scenarios based on tax and credit rate numbers requested by legislators to a joint meeting of House and Senate Finance committees. A number of legislators attended, leading Senate Finance Chair Lyda Green, R-Matanuska-Susitna, to quip to House Finances Co-Chair Kevin Meyer, R-Anchorage, that she thought the House had a quorum.
Van Meurs had briefed House and Senate Resources committees on the proposal Jan. 18 (see story in Jan. 22 issue of Petroleum News), and legislators asked for examples of what the change in tax would mean at specific rates.
The production profit tax, or PPT, would replace the state’s current production severance tax with its economic limit factor.
Alaska Commissioner of Revenue Bill Corbus, introducing the Feb. 1 presentation, said the state’s oil tax system must be reformed. “The current production tax system with its ELF exclusions is no longer working for Alaska, particularly in an era of high oil prices.”
The proposed profit sharing tax system, Corbus said, is based on the state getting a fair share of profits on oil “based on what the producers are already paying in similarly situated oil regimes around the world”; on incentives needed to “induce exploration, investment and reinvestment in Alaska”; and on “what is needed to protect explorers and independents and small operators.”
Van Meurs told legislators that the state’s current severance and ELF worked well to encourage development of smaller fields in the economic conditions of the late 1980s, when the system was developed, but said the benchmarks for the system “are now completely outdated and therefore an overhaul of the production tax is in the interests of the state.”
Van Meurs listed four “serious deficiencies with the production tax,” all related to the ELF, a formula which produces a number from zero to one which is then multiplied by the severance tax to determine the tax rate for each field. He said the ELF is no longer “rational in relationship to well productivity and field production”; it isn’t responding to field production decline; it “does not provide for a reasonable balance under a range of oil prices”; and it “does not provide for sufficient incentive to re-invest.” PPT a consolidated tax The profit sharing production tax, or PPT as the administration has dubbed it, would be “a consolidated tax at the corporate level,” van Meurs said, unlike the present production tax which is on a field-by-field basis. The PPT would be based on cash flow: gross revenues, net of royalty, based on wellhead prices (which exclude transportation costs), less lease expenditures.
There will be tax credits to encourage investment, van Meurs said, and a loss in any year multiplied by the tax base can be claimed as a credit. “Tax credits can be transferred and traded,” he said, making this an important incentive for new investors, allowing them to monetize their investments immediately.
Sen. Ben Stevens, R-Anchorage, said the numbers used to run scenarios for the presentation were numbers legislators requested the administration to use: Tax rates of 25 percent, 20 percent and 17.5 percent; and tax credit rates of 15 percent and 20 percent.
Van Meurs said he believes the rates are “a reasonable range.” Benefits to small producers Van Meurs had told legislators in January that the administration was considering tax breaks for small producers because the administration wants to “encourage them to invest in Alaska.”
Alternatives suggested in the Feb. 1 presentation included: a zero tax rate on the first 5,000 barrels of oil equivalent per day; or a tax-free allowance in the range of $50 million to $100 million a year on “actual profits per company.”
Van Meurs said the administration was also looking at ways to provide a tax credit on heavy oil, perhaps with a higher tax credit on capital investments in heavy oil. Van Meurs said the administration is still working on a precise definition of heavy oil and how a company would qualify capital expenditures for heavy oil.
He said the administration wants to create incentives for investment in Alaska, and believes the new tax system, along with the gas pipeline, will make Alaska “a whole new core area for investment by a wide variety of companies.” What the numbers look like Marks said the PPT starts with the wellhead value of gas, the market price less transportation costs.
The basis of the current tax is also the wellhead value, sometimes called the netback, he said: the market price less the royalty, the marine transportation cost and the trans-Alaska oil pipeline tariff.
The goal of the PPT, he said, “is to actually bring in the upstream costs as well and recognize the full economics of production.”
From the current wellhead value the operating cost, property tax and capital costs would be deducted, and that amount would be subject to whatever the tax rate is, and to a credit for the capital costs.
The volume of oil in the future was an important issue in modeling the scenarios, Marks said, and the department looked at two significant parameters. The first addresses future oil exploration and success: an enhanced volume scenario, he said, includes “a series of eight analogues to the Alpine field coming on spaced five years apart over the next 45 years.”
The other parameter is whether or not there is a gas pipeline.
Marks said the gas pipeline affects oil volumes in three ways: initially a gas line would reduce Prudhoe Bay oil production because of the decline in pressure, but in the long run it would increase the life of the field and increase the total volume of oil recovered.
The assumption in the modeling, he said, “is without a gas line Prudhoe Bay shuts down in 2030.”
With a gas line Point Thomson is developed.
“And also with a gas line we believe there’ll be a lot of additional exploration for gas and with new gas fields there will be associated oil.”
Depending on whether or not there are enhanced volumes of oil and whether or not there is a gas line there are four scenarios.
Marks said the department was presenting the bookends: a low-volume scenario with no gas line and no enhanced volumes of oil and a high-volume scenario with a gas line and enhanced volumes of oil. No gas: North Slope shuts down in 2030 “We believe it’s not unreasonable to think that without the enhanced volumes and without a gas line that the whole North Slope could shut down in 2030,” he said, so the low-volume scenario only runs to 2030, while the high-volume scenario runs to 2050.
Total oil production (from the present to 2030) is 6.5 billion barrels in the low-volume scenario and 10.5 billion barrels (present to 2050) in the high-volume scenario.
The cost and price assumptions used in the scenario are real 2005 dollars escalating at 2 percent a year. Cost estimates include: $100 million a year in exploration; $1 per barrel on-going capital; $4 per barrel developmental capital on two-thirds of the oil in existing fields; $4 a barrel development capital on new fields; and $4 a barrel operating costs.
Marks presented a series of graphs comparing the status quo with five combinations of tax and credit rates.
For the low-volume case (no gas line, no enhanced volumes of oil), the cumulative PPT taxes (2006-2030) compared to the status quo ranged between $3 billion less and $61 billion more, depending on the price of oil (the scenario looked at a range from $15 a barrel to $65 a barrel) and the tax and credit rates.
The upper side scenario (with both a gas line and enhanced oil volumes) from 2006-2050, had total revenues ranging from $6 billion less than the status quo to $134 billion more than the status quo. Cross-over point Marks said there has been a lot of interest in the cross-over point: the oil price at which the PPT will bring in less than under the status quo. On the low-volume case Marks said the cross-over looked to be in the low to mid twenties. But, he said, what’s really important is the slope of the line (on the graph) after it crosses the cross-over point.
In a series of graphs of annual revenues at prices of $20, $40 and $60 a barrel, Marks noted that a $20 low-volume case demonstrates that “at low prices we make less money” with the PPT than with the status quo, from $100 million to $180 million less in a year. But at a $40 price, in the low-volume case, average annual revenues are $400 million to $900 million more than with the status quo.
The significance of the cross-over point is evident at $40, Marks said: “The money we would make at $40 in one year is more than the money we would lose at $20 for four years.”
A $60 per barrel low-volume scenario showed average annual revenues of $1.1 million to $2 million more than the status quo. This, Marks said, is the low-volume scenario, without a gas line: “What’s interesting here is that these revenues are equivalent to how much money we would make with a gas line at $5 per million Btu market price in Chicago. So in this scenario you’re getting gas line revenues without a gas line and at prices less than what they are today.”
Van Meurs echoed that thought: in the range of tax rates that the Legislature requested, the proposed PPT “is not a minor thing: this is equal to the whole gas line, the only difference is that it comes in right away rather than having to wait for the gas line coming on stream.”
What prices will be in the future is unknown, Marks said, calling the scenario “interesting.” Gas revenues not included For the high-volume scenario (a gas line and enhanced volumes of oil), Marks said the revenues do not include money from a gas severance tax, but the upstream gas costs are deductible for the PPT, “so this includes the gas line costs, but the gas line revenues are not here, but are received per our in-kind marketing receipts per the stranded gas act.”
Again, at $20 a barrel, the state loses money on the PPT compared to the status quo, an average of $150 million to $200 million a year less. At $40 a barrel annual revenues are $600 million to $1.2 billion more than the status quo, and at $60 oil, average annual revenues are $1.5 billion to $2.6 billion more than the status quo.
Even though the tax rates are flat, “this creates a progressive system ... because your upstream costs are deductible and those costs are a smaller and smaller percentage of the value as prices go up,” Marks said. Under the low-volume scenario the effective tax rate would be between 10 and 16 percent, and under the high-volume scenario the effective tax rate is between 12 and 18 percent.
And what does the PPT do to the corporate take?
If you look at gross volumes over 45 years (the high-volume scenario with a gas line), and use the Department of Energy’s Energy Information Administration’s current projection of $58 per barrel oil, the total is about a trillion dollars, Marks said, compounded at 2 percent over 45 years.
Corporate take goes from 39 percent of gross revenues, under the status quo, to 33 percent of gross revenues under the PPT at a 20 percent tax rate and 15 percent credit rate. The state take increases under the PPT, but the federal take decreases. Marks said the federal government picks up the tab on about a third of the PPT.
How big a hit would the PPT be to the producers over 45 years under this scenario? Of the trillion dollars “they would get 6 percent less and walk away with 33 percent of a trillion dollars, which is $333 billion. And the question you need to ask yourself is, is that painful or not, to walk away with $333 billion?” And, he noted, the status quo, with the ELF, “is a modest standard of comparison.” International comparison Van Meurs told the legislators that high oil prices have had an important impact on international government take. Countries with progressive regimes have deals “for production sharing or contracts or taxes whereby it is already agreed beforehand that taxes will go up very significantly with price or other profitability indicators.” In Russia, he said, deals in place vary from the equivalent of a 10 percent PPT at low prices to as much as 70 percent.
In countries where tax formulas didn’t account for higher prices there have been legislative or contractual changes to increase the take, including the United Kingdom, Trinidad & Tobago, Kazakhstan, Bolivia and Venezuela.
In December the United Kingdom indicated it would increase its take from 40 percent to 50 percent, an increase of 10 percent. The change for Alaska with the PPT would only be a 6 percent increase, he said.
Higher oil prices have created a worldwide trend of higher government take, van Meurs said, “either because the terms were already negotiated or countries decide that it is fair to get a better share because of the higher ... oil prices.” The PPT from an investor’s viewpoint Van Meurs said he analyzed the PPT from the perspective of an investor, looking at a range of field sizes from 50 million barrels with low well productivity to 500 million barrels with high well productivity, and also looking at first investment and re-investment.
For a 50 million barrel field Alaska collects nothing under the current system because the ELF would be zero, he said, so the state collects more production tax at high prices with the PPT. At low prices under the PPT, when a small field would become unprofitable, the tax credit would help the field: “under very uneconomic conditions, there will be some tax credits and they can be traded with another oil company.”
For a big field, 500 million barrels, the state would collect more production tax under the PPT with both average and high oil prices.
Those are cases where a large oil company is re-investing.
He said the most interesting case was what he called the Cook Inlet case: first investment in a 50 million barrel oil field with high costs and low well productivities. A small producer would not pay PPT because they have an allowance (5,000 barrels per day without tax), “but they still get the credits.” At 20 percent tax and 15 percent credit for capital investment a small operator can lower its capital cost by 35 percent.
“Now if you want to give an incentive to look at Cook Inlet, this is the way to do it,” van Meurs said.
He said with this kind of a tax structure, “a few small oil companies would look with new eyes at their smaller targets, maybe smaller targets on the North Slope ... and first investors would see a very attractive system to come into.”
If a large new player, such as Petrobras, came into Alaska looking at large new fields, the new investor allowance doesn’t mean very much because even with that allowance on a large field they pay more in taxes. But, he said, with the capital credit, “we have modified the ... initial investment required,” so even with the new PPT, “the rate of return actually goes up despite the higher taxes.”
With the tax credit for capital investment, the investment costs a company less and the company can trade its tax credits and its rate of return goes up. The tax credits improve the internal rate of return for both new investors and re-investors, van Meurs said, “and that means that companies who are interested in a strong rate of return would find that a very attractive aspect of the PPT.”
Comparison with competition Van Meurs compared the current Alaska system and the proposed PPT with eight areas, selected because large oil companies active in Alaska are also active there: Norway, the United Kingdom, U.S. Gulf Coast, Alberta oil sands, Nigeria, Angola, Russia-Sakhalin and Azerbaijan.
He rated 48 economic criteria, 1 for the best, 48 for the worst.
The U.S. Gulf of Mexico scored 52 for first investment, Russia-Sakhalin 444 (out of a hypothetical 48 best and 480 worst). Alaska’s current system scored 364 and the Alaska PPT 272. Of the 10, the eight countries and the two Alaska tax systems, an Alaska PPT system was No. 5 out of 10, Alaska’s current system No. 8 out of 10.
Van Meurs concluded that “from a competitiveness point of view for a new investor ... on average, Alaska would look far more competitive, far more attractive, with the PPT than with the current system.”
Large investors that are already in Alaska wouldn’t get the 5,000 barrel per day allowance, so Alaska’s PPT doesn’t look as attractive as it does for a new investor, he said. For what van Meurs labeled “next investment,” Alaska with a PPT system had a rating of 322 and was No. 6, compared to Alaska’s current system with a score of 353 and a rank of No. 8.
Alaska’s attractiveness for a large re-investor under the PPT “would depend very much on how they weigh rate of return and other profitability criteria relative to the government take, what kind of sizes they’re actually looking at, what kind of costs they’re looking at. In some cases it would compare, in other cases it may come out somewhat less,” he said.
Van Meurs said he thinks the PPT for a large re-investor in Alaska “is somewhat better” than the current system, “but not dramatically better.”
Any of the cases that were analyzed “look like reasonably competitive cases” from an international perspective, van Meurs said.
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