Dear Petroleum News editor,
Although dated Nov. 16, 2007, the day the final ACES bill was passed by both the House and the Senate, Kristen Nelson’s article “Alaska gets poor marks” devotes but a single line to testimony by Gaffney, Cline and Associates, GCA, where it quotes us as saying “... increasing oil taxes will make investments in the state more attractive to oil and gas companies,” while it devotes 50 more lines to discussing reports and testimony by others from which you draw your headline “poor marks”.
The article is unbalanced, and deserves a clearer explanation of what GCA actually said (all of which is on record), and what the ACES bill and Alaska’s production tax actually does.
In summary, what GCA explained in testimony was that, based on the company’s own numbers, not only are existing infill drilling operations in the legacy fields exceedingly profitable, and will continue to remain so, but that the structure of Alaska’s production tax:
• Can differentiate between fields of differing production costs, taxing each according to its own profitability;
• Similarly, taxes (at current levels of profitability) existing production and new investments differentially;
• Contains levels of tax benefits and credits for investment that are found in few countries in the world; and
• Continues to make Alaska an attractive and profitable place to do business.
While testimony from the oil companies argued that tax increases could only hurt profitability and investment, they declined in testimony either to produce numeric examples to support their assertions, or demonstrate where GCA’s analysis is flawed.
Alaska’s production tax is a tax on a company’s net cash flow in any taxable period. As such, it taxes a base that represents a company’s profits after deduction not only of royalty, property tax and operating expenses arising from existing production, but also after deduction of the capital expenditure that a company chooses to make in respect of future production and exploration.
Further, development capital attracts an investment credit (not just an uplift of the spending in calculating taxable income, but a direct reduction in the tax itself) of 20 percent of the expenditure made, and exploration capital a credit of either 30 percent or 40 percent of the expenditure.
Such a structure is of itself attractive to both incumbents and new entrants, with the latter being able to monetize in the following year both the investment credits and the negative cash flows either by selling them to another taxpayer or to the State.
The tax rate is a function of the net cash flow in each taxable period divided by the production in that period. Until that net cash flow per barrel exceeds US$30, the tax rate is 25 percent. Thereafter it increases by 0.4 percent per dollar per barrel until that margin reaches US$92.50 (representing an oil price of about $115 based on current production costs) and then by 0.1 percent per dollar until the rate reaches 50 percent — a feature known as “progressivity” or “the slope.”
It is important to note that higher rates are only payable when a company’s Alaska operations are returning to the corporate treasury, after deducting operating expenses, future development capital and exploration expenditure, more than US$30 per barrel.
Such a situation can only occur when a company has extremely profitable operations.
At current oil prices (in the US$90s per barrel) profitability before taking into account capital expenditure is around US$70 per barrel.
Different profitability taxed differently
There is a further aspect to the progressivity component of the production tax. As noted above, the tax rate is a function of the net cash flow per barrel of production in the tax period. During testimony, GCA showed a series of slides illustrating how this structure can allow fields of different profitability to co-exist within a single tax system and effectively be taxed at different rates according to their own profitability. In the example (the full presentation with associated assumptions is available on the Alaska Legislature Web site) the four pairs of bars labeled Existing Reservoirs, X Y and Z represent a company’s existing production and further investments each of decreasing operating profitability. The leftmost bar in each pair represents the tax rate that would be applicable to that component of production if it were the only asset in a company’s portfolio, and the rightmost bar the effective tax rate when combined in a single company portfolio.
As each component is added to the company’s portfolio it reduces the average operating profitability (cash flow contribution) per barrel, thus reducing the tax rate not only on the new investment itself, but also on all other production. The effect of this is the same as continuing to tax production on existing reservoirs according to their prevailing profitability, while lowering the effective tax rate on the lower profitability components of the portfolio.
In the example used, the tax rate applicable to the example company’s entire portfolio would be 36.9 percent. However, this would be the same as taxing the existing higher-profitability production at 39.8 percent, investment X at 38.1 percent, investment Y at 31.3 percent and investment Z at 21.3 percent. Note also that the rate applicable to investment Z is actually less than the “floor” rate of 25 percent.
The exact rates applicable will of course vary from company to company, and the mix of assets/profitability in their portfolio. This effect only occurs while progressivity applies.
Capital expenditures lowers rate
The impact of capital expenditure further lowers the tax rate. As noted, the tax rate is based on cash flow per barrel, not profit per barrel. A company producing 5 million barrels in a taxable period at an operating profit (operating cash flow) margin of US$70 per barrel would be subject to a production tax rate of 41 percent (25 percent on the first US$30 per barrel, and a progressivity increment of 0.4 percent on each of the next US$40 per barrel of profit). If that same company then invested $50 million in development and/or exploration expenditures in that period, it would lower the cash flow margin, which is also the taxable income, to US$ 60 per barrel. This would reduce the tax rate from 41 percent to 37 percent on the entire 5 million barrels, saving $32.5 million in tax, or 65 percent of the capital to be invested. In addition, a tax credit of 20 percent would apply (more if any of the expenditure is exploratory), saving the company 85 percent of its capital investments, before any State and Federal income tax benefits.
Even a new entrant, with no existing production, will benefit from 55 percent to 65 percent production tax and investment credit tax breaks on exploration, and 45 percent on development capital.
Taking all these points together, GCA continues to believe that the petroleum tax structure is not only conducive to continuing investments, but provides significant incentives to undertake that activity.
Sincerely,
Robert George and Rich Ruggiero
Senior consultants
and group management executives
Gaffney, Cline and Associates
worldwide group
