Alaska’s petroleum basin, with billions of barrels in place, is one of the most promising energy regions in the world. Alaska competes globally for a limited pool of resource development capital. The state has always worked hard to strike a balance between its need for revenues and providing incentives that attract companies with expertise and the latest technology to explore and invest here.
Alaska’s oil and gas production tax, which remained essentially unchanged since 1989, was replaced last year with the Petroleum Profits Tax. The legislation has incentives for exploration, development and investment in Alaska. Changes include:
• Taxing the net value of production rather than gross value of production;
• Small producer tax credits of up to $12 million;
• Cash flow timing benefits to explorers and investors;
• Risk sharing by the state through exploration credits and deductions;
• Incentives for oil with high production costs, such as heavy or viscous oil;
• Minimal production taxes when energy prices are low;
• Protecting Cook Inlet taxpayers with a tax ceiling;
• Offering $6 million per taxpayer in new area development credits;
• Extending sunset dates of existing oil and gas exploration tax credits; and
• Options for tradable or reimbursable tax credits.
The reasons for changeGovernment fiscal systems for oil and gas production in the United States tend to have static tax and royalty mechanisms with government share taken from gross revenues before costs are deducted. Petroleum provinces outside the U.S. have been gradually moving away from such systems and implementing more progressive revenue raising mechanisms that recognize important project timing and cost considerations.
Prior to reform, Alaska’s fiscal system was considered highly regressive. Three of the four major components — royalty, production tax, and property tax — were all straight percentages based on the value of the production or property, without considering the costs of production.
The production tax calculation included an adjustment for a field’s economic limit factor or ELF. This served to lower production tax liabilities for fields that were at their “economic limit.” Together, these three components would generate a greater percentage for the government when prices were low than when prices were high.
Illustration 1 shows the state, federal, and company shares of the value of Alaska oil production prior to reform. The graph shows that as the price of oil increases, the percentage of the value of production that goes to the state government decreases.
Under the ELF system, half the fields on the North Slope were paying no production tax. The Kuparuk oil field with its satellites was collectively producing more than 150,000 barrels per day and was, by ELF calculations, reaching its economic limit and would owe no production tax in the next year. Other key fields such as Alpine had rapidly declining ELF tax rates. Many people felt Alaska’s production tax system was no longer functioning as intended and was allowing oil to be produced with very little or no production tax.
At the same time, the state and oil companies had begun negotiating a contract to build a natural gas pipeline from Alaska to Lower 48 markets. Among the concerns noted by oil company executives was the future of oil production taxes. They argued that fiscal certainty for oil production was needed for a natural gas pipeline.
The need to encourage more investment in Alaska, record high oil prices at a time when the state had no means to capture the windfall, the perceived shortcomings of the ELF, and the preparation for a large natural gas pipeline all played a role in prompting policymakers to reform the production tax system.
Components of the Petroleum Profits Tax or PPTThe PPT differs from the previous ELF-based tax system in a number of ways. The primary difference is that the PPT taxes net profits rather than gross profits. Because of this distinction, the tax has become company-specific, whereas the previous tax was property-specific. Other differences are outlined in Illustration 2.
Tax based on net profits
The PPT taxes companies on their net profits from oil and gas production in Alaska. Under PPT upstream costs (costs incurred in the production of oil and gas, called “lease expenditures”) are deductible from the wellhead value of the oil or gas. The law defines lease expenditures as “ordinary and necessary costs ... that are direct costs of exploring for, developing, or producing oil or gas deposits.” Direct costs include operating and capital costs relating to the production of oil or gas, an allowance for overhead, and payments in lieu of property taxes, sales and use, motor fuel, and excise taxes.
The law specifically disallows certain costs as lease expenditures, such as depreciation, depletion, and amortization; interest or financing charges; lease acquisition costs; costs of arbitration or litigation; costs arising from gross negligence; and facility abandonment, removal, or restoration costs. The Legislature may make additional changes in the future to further clarify the deductibility of certain maintenance and other costs.
Credits for capital expendituresThe PPT allows a credit for capital expenditures at a rate of 20 percent. Thus, combined with the tax deduction of 22.5 percent of the capital lease expenditures, a total of 42.5 percent of companies’ taxable capital expenditures are exempted from taxation (22.5 percent deduction; 20 percent credit). Unlike basic accounting rules, which require companies to expense capital assets through depreciation over time, the PPT allows companies to expense all the cost of a capital expenditure in the year the cost is incurred.
The drafters of the tax plan favored capital expenditures because they frequently precede an increase in petroleum production. Under the state’s previous tax system, unless companies met the requirement of the exploration credit, they were not able to recoup any of their drilling expenditures. The PPT would reimburse these companies up to 42.5 percent of the allowable capital costs for drilling, whether or not the wells proved successful.
By allowing companies to deduct exploration costs, expenses for unsuccessful wells can be written off against the profits from successful finds. Exploration costs can also be reduced by selling credits to profitable producers or by applying for cash refunds. The state is in effect sharing the risk and expense of drilling dry holes.
The PPT allows for more operating cost deductions when costs are high. This may encourage development of substantial deposits of heavy and viscous oil known to exist on the North Slope, that typically have a higher cost of production.
Transferable or refundable creditsUnder the PPT, companies with capital expenditure credits, but no tax liability, can apply to the state for a certificate to transfer the credit to another taxpayer. These certificates do not expire and if transferred, can be used to reduce another taxpayer’s PPT liability by up to 20 percent.
Alternatively, a qualifying company that has a credit certificate can redeem it for cash by selling it to the state. The law authorizes up to $25 million per taxpayer annually for purchasing credits, subject to legislative appropriation.
Timing for tax paymentsThe PPT back-end loads the production tax. Tax payments will be lower when large initial capital outlays are made and higher as production responds to that investment and net cash flow becomes positive. The PPT allows tax breaks early in the development cycle. Because of the time value of money, the net present value, or NPV, of a project improves. There are also cash flow benefits from monetizing credits early on in the project timeline.
Tax floorThe PPT includes a tax floor, which applies only to production on the North Slope. It is levied on the gross value at the point of production (the production value prior to subtracting costs). The percentage of tax levied is graduated, based on oil prices as follows:
With the tax floor, a North Slope taxpayer must first determine whether the PPT liability (prior to applying credits) exceeds the tax floor. Unless prices are lower than $30 per barrel, or costs are extremely high, the PPT liability will generally be higher than the amount calculated under the floor. Assuming the PPT liability is higher, the taxpayer can then apply credits to determine the final tax liability. This system allows the final PPT tax liability to be lower than the tax floor, but is consistent with the Legislature’s intent to reward companies for making capital investments.
Progressive surchargeThe progressive surcharge is a mechanism for collecting additional tax revenues when the profits of oil production are very high. The calculation of this surcharge uses a value called the “price index”. The Legislature settled on a progressive surcharge at a rate of 0.25 percent for every dollar that a company’s net profits from petroleum production exceeds $40 per barrel, up to a progressive surcharge ceiling of 25 percent of net profits. Combined with the PPT tax rate of 22.5 percent, the maximum total tax a company will pay is under this method is 47.5 percent of net profits. This rate would only apply in times of extremely high oil prices and must be considered in light of the considerable tax credits and deductions that can lower the liability.
Illustration 3 shows the progressive surcharge as passed by the Alaska Legislature. The ceiling is activated when net profits reach $140 per barrel (0.0025 * ($140-$40)).
Base allowance creditThe legislation includes up to $12 million tax credit per year for each company with operations having production volumes of less than 50,000 barrels per day. Companies with production of more than 50,000, but less than 100,000 barrels per day, receive a smaller credit based on a sliding scale. For example, a company that produces 75,000 barrels per day would receive a base allowance credit of $6 million ($12 million * (1- ((2 * 75,000 – 50,000)/100,000)).
The base allowance credit was added to the PPT system primarily to benefit small producers. One of key features of the PPT is that it benefits small companies willing to explore and develop fields that are considered too small for the major oil companies. The base allowance credit is not transferable, nor can it be carried forward. The allowance is scheduled to sunset in 2016.
A separate base allowance credit of $6 million per year per company was authorized for operations outside of the North Slope and Cook Inlet producing areas. This credit, which has no upper limit on the level of production, is intended to encourage exploration and development of petroleum deposits in other areas of the state, including the Alaska Peninsula, Nenana and Susitna basins.
Special provisions relating to Cook InletCook Inlet has been a known oil and gas producing region for decades. Its discovery played an integral role in Alaska becoming a state. The availability of this inexpensive energy source has been of great value to the development of Alaska’s economy.
Under the ELF system, all Cook Inlet oil was produced without taxation because the economic limit factors on the fields reduced the tax to zero. An ELF of 0.5 on natural gas in Cook Inlet lowered the production tax on gas from a rate of 10 percent to 5 percent. The low taxes, combined with long-term contracts for Cook Inlet gas, provided for a very inexpensive supply to the most populated region of the state.
Recognizing that taxes on Cook Inlet production could increase under the PPT, legislators created special provisions for this area of the state. Under the new production tax system, companies operating in Cook Inlet will pay the lesser of the PPT tax and the ELF tax, as determined prior to the enactment of the PPT. With the application of available credits, many Cook Inlet companies will likely pay less production tax than they did prior to the enactment of the PPT. Cook Inlet special provisions will sunset in 2022.
ConclusionAlaska is a mature oil province with billions of barrels of oil that are classified as proven reserves and billions more yet to be discovered. The state recently overhauled its production tax system, replacing it with the Petroleum Profits Tax, a tax based on net profits rather than on gross profits from oil production. The new tax system is designed to encourage additional production through its deductions and credits, and generate more tax revenue for the state at high prices.
The Alaska Department of Revenue is preparing for phase two of the regulations process, which will clarify several issues including which costs qualify as lease expenditures, and how operating agreements will be used under the PPT. The department expects to have the regulations completed sometime in the fall of 2007.
For more information on the PPT legislation, updates on the implementing regulations, or staff contact information please visit the Alaska Department of Revenue, Tax Division website at www.tax.state.ak.us