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Vol. 13, No. 51 Week of December 21, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Alaska gas tax quandary

Gas rolled in with oil under present Alaska production tax would drop revenues

Kristen Nelson

Petroleum News

If North Slope natural gas production was rolled into Alaska’s present production tax system on a barrel-of-oil-equivalent basis, state production tax revenues would drop.

Dan Dickinson, a former Tax Division director, told the Alaska Legislature’s Budget and Audit Committee 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 slightly more than $6 per thousand cubic feet (using current volumes of oil and estimates of gas sales) showed that adding in an estimated 4.2 billion cubic feet of gas sales a day would have reduced production tax revenues from $4.176 billion — if the state were getting production taxes only on oil — to $4.105 billion with combined revenues from oil and gas.

Dickinson said the issue is progressivity under the present system.

At the September price for ANS crude a 9.59 percent progressivity rate would have been added to the oil base rate of 25 percent, for a tax rate of 34.59 percent.

The value of natural gas at the wellhead, however, is too low to trigger the progressivity factor. When 75 cents is subtracted from the Henry Hub spot price to adjust for the gas going to Alberta, the transportation cost to market, estimated at $2.88 per mcf, is more than half the price the gas brings at market, dropping the value at the point of production so low that there is no progressivity factor.

Combining oil and gas under the same production tax system — with no progressivity for natural gas — drops the progressivity rate from 9.59 percent to 1.74 percent, reducing the overall tax rate from 34.59 percent on oil alone to 26.74 percent on the oil and gas combined. Combined, the production tax is figured on a larger base, but at a smaller rate.

Dickinson said state revenues from royalties and property tax would increase with natural gas sales, but corporate income taxes would drop.

Wood concurs

Dickinson provided an overview for the committee of Alaska’s production tax system and recent changes, including progressivity, a presentation which was an introduction to a preliminary report on a study commissioned by LB&A in April on a fiscal design for Alaska North Slope natural gas.

Large gas volumes contribute low value to high-value oil production and can dilute production tax value on a boe basis and reduce the progressivity factor for the combined stream, David Wood of David Wood & Associates told the committee.

Wood said the trigger point at which the progressivity tax is payable is set too high for natural gas.

Looking at fiscal design internationally, Wood said three focuses are possible: optimizing government take; encouraging inward investment; and developing indigenous industry. Alaska’s focus, he said, is on the first two — optimizing its take and encouraging producers to invest earnings in the state. Many developed countries focus on inward investment, he said, while Norway and North Africa focus on developing local industry and maintaining control. Big developing countries, many of them Organization of Petroleum Exporting Countries like Venezuela, maximize sovereign take.

Stability important

Wood said important parts of a fiscal design include providing stability and consistency, aligning with all stakeholders and having flexibility to adapt to changing circumstances.

Fiscal mechanisms which dominate international fiscal designs are mineral-interest systems, like that in the United States, where rights to production are transferred to a lessee or licensee in exchange for development of the resource and payment of a royalty and usually other taxes, and production-sharing mechanisms which are contractually driven. There is about a 50-50 split between production sharing agreement systems and mineral-interest systems and while there is a range of other fiscal mechanisms, these are the main two under which big gas projects are developed, he said.

The focus of fiscal designs, Wood said, is on the division of economic rent between government and industry and investment is promoted by designs which are progressive and flexible.

Regressive vs. progressive

Regressive elements and fears of instability can limit investment. Regressive elements in Alaska’s fiscal design include royalty, property taxes and the production tax floor.

Wood said those regressive elements are partially offset by investment credits for exploration and development; production taxes which are levied after deduction of allowable costs; and the progressivity tax which is only levied on high-value streams.

He said the state should consider other allowances or credits to offset impacts of the regressive elements coupled with tougher progressivity terms under the most recent production tax revisions.

The government sees income later in a progressive system, sooner in a regressive system, Wood said. It is unrealistic to have all government income from progressive elements, but it is a problem for producers to have all government income from the regressive end of the spectrum. There is less flexibility with regressive systems and more flexibility with progressive systems, he said.

The minimum reserve size is negatively impacted by regressive systems: While highly progressive systems act to bring down the minimum economic field size and help keep those fields in production, highly regressive systems move the minimum economic field size up, Wood said.

He said the new Alaska fiscal design is more regressive because of the increase from 22.5 percent to 25 percent in the base production tax rate.

Treatment, transport, tariff

The costs are higher in natural gas, he said, so the economic rent is smaller and there is perhaps less room for adjustments.

Under Alaska’s fiscal system the government take is about 30 percent of total revenues for natural gas (state 22 percent, federal government 9 percent). For oil, however, government take is closer to 60 percent (Alaska 46 percent, federal government 11 percent) because costs are lower.

Starting with destination value, 42 percent of the value of natural gas from a large field is consumed by treatment, transport and tariff costs, with about 1 percent TT&T for liquids from the field. This compares, for a large oil field, with 5 percent TT&T for the liquids and 6 percent TT&T for any gas from the field.

While the producer take is 16 percent in Wood’s example for a large gas field, it is 20 percent for a large oil field.

Stability important

Wood said fiscal stability and credibility are important to international oil companies making investment decisions, but are not the only factors that influence investment decisions.

International oil companies often seek fiscal certainty in exchange for committing to large investments, he said, but warned that issuing guarantees or being drawn into long-term contracts is risky for governments. He said a flexible and progressive fiscal design is a better approach and said “clear, pro-commercial fiscal strategy statements” improve industry confidence. Any guarantees offered should have limited time periods, involve reciprocal commitments from the companies for ceilings on costs and involve more regressive fiscal elements than if no guarantees are given.

He said that retaining the right to adjust fiscal terms allows governments to “periodically change the fiscal design to respond to market conditions.”

Wood said international oil companies have “demonstrated more enthusiasm around the world for downstream infrastructure project investments that are integrated with development of upstream resources.” Companies have signed on, worldwide, to progressive systems with high marginal government takes — and significant government equity shares — when gas values are high and there is limited access to reserves, he said, but have been more likely to do so with incentives during low gas prices, with exclusive rights to resources in integrated upstream and downstream projects and when terms are controlled by contracts.

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