Will the State of Alaska’s present production tax system, Alaska’s Clear and Equitable Share, or ACES, be effective when natural gas sales begin from the North Slope?
Legislators have heard both yes and no to that question.
In December Dan Dickinson told the Legislative Budget and Audit Committee that ACES would produce lower revenues if natural gas sales were occurring.
If natural gas sales were occurring right now in addition to crude oil sales, revenues to the state would actually drop, he said.
Dickinson, a former director of the Alaska Department of Revenue’s Tax Division and now a consultant to the Legislature, told LB&A at a December hearing that numbers he ran in September, when Alaska North Slope crude oil was selling for around $80 a barrel and the Henry Hub spot price for natural gas was just above $6 per thousand cubic feet, showed that adding 4.2 billion cubic feet of natural gas sales to current volumes of ANS crude oil sales would reduce production tax revenues from $4.176 billion, the production tax on the crude oil, to $4.105 billion from combined oil and gas revenues.
Dickinson attributed the drop in revenues to the progressivity feature in ACES. The wellhead value of natural gas, he said, is too low to trigger the progressivity feature. If oil and gas were combined, the combination of the lower natural gas progressivity would reduce the oil progressivity, resulting in less revenue to the state from combined oil and gas sales than the state would have received from oil sales alone. Progressivity adds a surcharge to the base production tax rate as prices rise.
Begging to differRich Ruggiero of Gaffney, Cline & Associates, a consulting firm which helped the state design ACES, told the Senate Resources Committee Feb. 2 that Dickinson’s calculations were correct, but that the numbers Dickinson chose to do the calculation were not representative of the typical price difference between oil and gas. And using current crude oil production figures does not reflect what oil production is expected to be when gas sales occur in the future, Ruggiero said.
The numbers in Dickinson’s example would produce a temporary drop in revenues, but the relationship between oil and gas prices in the example has only occurred some 4 percent of the time in recent years. It’s an anomaly, Ruggiero said, and just one of tens of thousands of scenarios which could be run.
Dickinson looked at how ACES would work with a natural gas development of the type anticipated under the Alaska Gasline Inducement Act, Ruggiero said in a report he prepared for the committee, and Dickinson used equivalent oil and gas production rates on a barrel-of-oil-equivalent basis, producing an oil production rate close to current levels, with a gas production rate close to the AGIA base case, although adjusted down to create a 50-50 blend of oil and gas.
But gas transportation and operating costs “will almost always be greater than oil on a per BOE basis,” Ruggiero said, producing a lower profit per barrel for a natural gas field than for an oil field. Because costs are different, analysis is sensitive to the ratio of oil-to-gas production, he said.
The work done for AGIA estimated first gas in 2018 and at present rates for North Slope oil production decline oil volume at the start of gas flow is likely to be about half of current rates, or some 350,000 barrels per day. That rate, Ruggiero said, produces a blended tax rate $250 million greater for oil and gas than for a standalone oil tax.
Lower progressivity expectedRuggiero told the committee that a reduced progressivity level was expected from ACES — and discussed while the bill was in the Legislature.
With a base of existing oil production, if heavy oil or natural gas enters the mix — both less profitable than conventional production — “we did know and we did predict that that would bring the overall combined progressivity down.” ACES was designed that way, he said, to “encourage what appeared to be, at the time, uneconomic developments in heavy oil and natural gas.”
The benefit ACES provided in lowering the tax rate when new fields were added “that were less profitable or more expensive to bring on” is that the new production keeps existing assets, such as the trans-Alaska oil pipeline, in operation.
“And as long as you feed more crude into TAPS, then it allows Prudhoe, Kuparuk and the other existing fields to continue to produce at ever lower and lower levels because when combined with these new developments you then have a minimum level necessary to keep that pipeline in operation,” Ruggiero said.
The parity issueRuggiero also took issue with the oil-gas parity in Dickinson’s analysis.
The relationship between oil and gas can be looked at in two ways, Ruggiero said: The thermal or heat value between oil and gas is 6-to-1. Price parity would occur when the price of a barrel of oil is six times the price of a million British thermal units of gas (roughly equivalent to a thousand cubic feet), i.e. $60 oil and $10 gas.
In his report Ruggiero graphed a range of oil-gas price parities starting at 5-to-1 and continuing to 15-to-1. A ratio of 13-to-1 or greater was required “before the blended tax rate and resultant taxes paid are less than the taxes that would have been paid if the company produced only oil,” he said.
During hearings for the Alaska Gasline Inducement Act consultants from Black and Veatch presented historical oil-to-gas price ratios from January 1995 to January 2008, and said they expected the parity over the life of the project to fall between 7-to-1 and 8-to-1.
Out of that 14-year period, there were six months when the parity was 13-to-1 (the parity between the prices Dickinson used in his calculations), with the peak at 14-to-1, and Ruggiero said Black and Veatch and others testified at the AGIA hearings that in the long run parity between 7-to-1 and 8-to-1 was what they expected to see.
The public concernSen. Bert Stedman, R-Sitka, asked Ruggiero how legislators were going to be able to explain to constituents parities at the high end and the “giving our gas away for free, or next to nothing?”
Ruggiero said large gas export projects, such as the proposed Alaska gas pipeline project, generally involve a lot of commercial dealing, with producers looking for things in the package that protect them on the downside.
Looking at the parity range between 1995 and 2008, if the gas project had been in operation, “the State of Alaska 4 percent of the time would have provided a bit of a subsidy to the oil companies” by uplifting the net value of the gas during six months out of 14 years, Ruggiero said.
But when the parity is below the expected 7- or 8-to-1, “that’s when the state’s receiving extra value. As the price of gas increases relative to oil then we go back up the progressivity curve and the State of Alaska is getting it back in return.”
Ruggiero also said that the market will correct itself when gas gets to be unusually inexpensive relative to oil, because “there are quite a few industries that can switch literally on a penny or two difference in the price and that will switch between liquid fuels and gas, such as a large number of the power generation plants in the Lower 48.”
RecommendationSen. Charlie Huggins, R-Wasilla, asked Ruggiero what tax scheme — combined or separate for oil and gas — he would recommend if the state had only oil production and was suddenly faced with a major gas find.
“I hate to say this, but it depends,” Ruggiero said. Variables would include the size of the project and its relative location.
But separate oil and gas taxes, such as David Wood suggested to LB&A in December, open Pandora’s Box, he said.
Would you tax the oil and gas revenue streams separately or would you do separate taxes by field or unit? If it’s by field or unit, you’d have to define what is a gas field and what is an oil field.
If the tax is by stream — oil or gas — “you then have to come through and you have to label each piece of equipment” as gas equipment or oil equipment “because you’re going to put these into two different tax regimes.”
Whether Gaffney, Cline would recommend a blended tax or separate taxes “depends on where the asset is located, how large it is, what type of market it’s going into, how many other existing facilities it would have to use and the list would go on and on,” Ruggiero said. He told Huggins that in the past Gaffney, Cline has recommended both combined systems and separate systems.
But, Ruggiero said “There’s a lot more analysis that needs to be done, digging down into some of the specifics before you can even start as a state to think about the need to change your fiscal system for gas.”
Stedman said he did not expect to see the Legislature “go into a debate on the gas tax,” and said he expects the gas tax to be dealt with at a later date.
Huggins noted that he wanted to “get out in front” of the gas tax issue and said he didn’t want to see a special session in 2010 before the open season to deal with gas tax issues.
Sen. Hollis French, D-Anchorage, said Huggins had expressed half of what he was going to say, and reminded those listening that the reason Huggins brought up the year 2010 is that the Legislature promised, in AGIA, “to keep gas taxes the same for 10 years” when gas starts flowing for those committing to ship gas in the first binding open season of an AGIA project, based on the rates in place at the time of that open season.