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The complex story of state tax credits A system to incentivize oil and gas exploration has evolved over the years, along with different tax regimes and changing priorities ALAN BAILEY Petroleum News
Characterized as oil industry subsidies by some and as state resource investments by others, the various tax credits the state of Alaska offers for oil and gas exploration and development have become a major headache in balancing the state’s fiscal books in an era of low oil prices. The tax credit system, which began more than 10 years ago, has evolved into a complex arrangement of interrelated laws and regulations.
The array of current tax credits needs to be viewed against the backdrop of the state’s evolving oil and gas production tax regime; against the state’s priorities for encouraging new oil and gas development; and against the impact of recent low oil prices.
Changing tax regime From the perspective of the tax regime, the first major change came in 2006, with the implementation of the Petroleum Profits Tax, or PPT, in which the state moved from taxing production based on the wellhead value of oil to a tax based on production profits. In 2007 the state Legislature passed the Alaska’s Clear and Equitable Share, or ACES tax. ACES, like PPT, was a profits based tax, but with a higher basic tax rate than PPT, and with tax progressivity to heightened rates at higher oil prices. The Senate Bill 21, or SB 21, tax law passed in 2013 eliminated the high oil price progressivity in ACES while increasing the basic tax rate. SB 21 also strengthened a tax floor, introduced in ACES, to prevent the state’s tax take falling to zero in low oil profitability situations.
Under SB 21 the tax floor was set at 4 percent of the wellhead value of oil produced.
Against this scenario of changing tax laws came a growing concern about declining Alaska oil production and the need to encourage new oil development. In addition, major concerns in 2010 about potential utility gas shortages from the Cook Inlet basin led to legislative tax action to encourage new exploration and development in that region. Then, in 2012, came a drive to encourage exploration and development in the so-called “Middle Earth” basins, potential petroleum basins in Interior Alaska.
But with the collapse in oil prices and state revenues in 2014, a focus on state cost cutting led to the passage of House Bill 247, or HB 247, this year, a bill that trimmed back some tax credit provisions.
Ken Alper, director of the Alaska Department of Revenue’s Tax Division, has explained to Petroleum News the system of state tax credits that has evolved against this background of changing taxes and state priorities.
Exploration credit The earliest of the credits introduced by Gov. Frank Murkowski in 2003 prior to the enactment of PPT addressed concerns about declining oil production by encouraging the drilling of new exploration wells. Essentially, a company drilling an exploration well more than specified distances from an existing unit or well could claim a credit against taxes of 20 percent of the cost of the new well. Although originally used as a credit against current or future taxes, this credit could later be taken as a tradable and cashable tax credit certificate. The credit changed over the years, eventually becoming a 30 to 40 percent credit, depending on the distance from the existing unit or well, Alper explained.
In general, this exploration credit only applied to drilling conducted prior to July 1, although the state is still processing claims relating to drilling prior to that date. However, under the SB 21 legislation, state lawmakers extended the credit until 2022 for basins in Middle Earth, Alper explained. HB 247 made no changes to this credit, Alper said.
Alper also commented that the sunsetting of this credit this year probably accelerated the start of some exploration projects such as the project at Smith Bay, off the northwestern North Slope.
Qualified capital expenditure A separate set of credits addressed the encouragement of new investment in oilfield development. For example, the so-called qualified capital expenditure credit, introduced as part of PPT and sometimes called the 20/20 plan, provided a tax credit of 20 percent of the cost of specified types of exploration and development capital expenditure in a tax system that used a base tax rate of 20 percent of production profits. Major oil producers could discount this credit against their tax liabilities, while companies in the process of field development, with no taxable oil production, could obtain a tax credit certificate that could be traded, applied against a future tax liability, or redeemed for cash from the state.
Under SB 21 the qualified capital expenditure credit ceased to apply to the North Slope after Dec. 31, 2013, but continued to operate elsewhere in the state. In Cook Inlet, where the ACES legislation had capped production taxes at levels similar to those prior to PPT, producers ended up paying zero or near zero taxes but remained eligible for substantial qualified capital expenditure credits, Alper commented.
HB 247 reduces the credit in Cook Inlet to 10 percent in 2017, and phases the credit out completely at the end of that year. However, the credit will remain at 10 percent in Middle Earth.
Per-barrel credit The SB 21 legislation, in part to replace the capital expenditure credit that it eliminated, brought in a new per-barrel credit for oil produced on the North Slope. The tax credit allows a $5-per-barrel credit for the production of new oil. For oil from legacy oil pools, the credit works on a sliding scale ranging from $1 to $8 per barrel at oil prices below $150 per barrel. The credit has to be taken against actual taxes, and cannot be cashed or carried forward to a subsequent year.
The per barrel credit sought to eliminate the regressive tax effect of stacking a fixed royalty rate on top of a fixed tax rate at low oil prices - the credit slightly reduces the effective tax rate at low oil prices while increasing the effective rate at oil prices above $100, Alper explained.
HB 247 includes a provision causing new oil to be reclassified as legacy oil after three to seven years, depending on the oil price.
Net operating loss credit Another credit, called the carried-forward annual loss credit, also referred to as the net operating loss, or NOL, credit, was introduced in conjunction with the move to a profit based tax regime in PPT and ACES. Essentially, under the ACES tax system, with its 25 percent base tax rate, a company could take a tax credit of 25 percent of an operating loss, the idea being to create a level playing field, in which a company with development expenditure but little or no oil production could obtain a similar development tax benefit to a producing company that could offset its costs against its North Slope production revenues.
Thus, the credit percentage was adjusted in synchronization with changes in the tax laws, ending up as 35 percent, a figure that matches the 35 percent tax rate under SB 21.
The production tax and the associated NOL credits for a single company are aggregated for the entire North Slope, rather than being calculated separately for each field that a company is involved in, Alper said. Thus, through the credit, the state can end up, in effect, underwriting some percentage of a field development cost, even for a new field. This phenomenon became particularly heightened during the ACES era, when the tax credit could lower a company’s tax rate under the ACES progressive tax formula, Alper commented.
Losses carry forward A company producing fewer than 50,000 barrels of oil can take the NOL credit as cash from the state, while a major producer can only take the credit against its own tax liabilities. However, if a company operating at a loss earns a tax credit in excess of its tax liability for a year, the company can continue carrying forward the resulting credit year upon year until the entire credit is consumed. Moreover, under the profit-based tax system, if the company’s total qualifying expenditures across the North Slope exceed its oil revenues over the course of a year, the excess expenditures carry forward against revenues in subsequent years.
These credit and expenditure carry-forward arrangements are causing a major problem for the state, given the sharp fall in companies’ oil revenues as a result of recent low oil prices and the fact that the tax fence is Slope-wide rather than field-wide. Essentially, a company, especially if it is incurring major capital expenditure, can generate carry-forward credits that reduce its tax liability to zero, thus undermining the supposed tax floor set under SB 21, potentially over several years.
Despite a lengthy debate about making changes to the NOL credits to harden the tax floor, HB 247 did not make any changes to the NOL credit rules for the North Slope. However, the bill is phasing out the credit in Cook Inlet by the end of 2017, with the credit in Middle Earth dropping to 15 percent of losses, starting in 2017.
Small producer credit
PPT also brought in a small producer credit that allowed companies with oil production below a certain level to obtain a credit prorated up to $12 million per year, depending on the production level. The credit, once invoked, applied for up to nine years of continuous production. The expiry of this credit on May 1 probably encouraged BlueCrest to start production from the Cook Inlet Cosmopolitan field in April and caused Chugach Electric Association to push for completion of its purchase of a share of the Beluga River gas field before the beginning of May, Alper commented. The credits could only be applied against tax and were not transferrable.
Another credit, called the traditional investment expenditure credit that came in conjunction with PPT, created some level of tax certainty during the dramatic changes to the tax regime at that time but was later repealed in conjunction with the ACES legislation.
Cook Inlet incentives
Concerns about declining gas production in the Cook Inlet basin triggered tax legislation in 2010, with a tax credit designed to encourage the development of a new gas storage facility on the Kenai Peninsula, to help utilities warehouse gas supplies for winter use. However, the legislation incorporated a number of incentives for gas exploration and development in Cook Inlet and resulted in what is referred to as the well lease expenditure credit. Working in parallel with the qualified capital expenditures credit, the credit, which applies to the Cook inlet and Middle Earth, consists of 40 percent of certain specified expenditures associated with exploration operations and drilling wells. The well lease expenditure and qualified capital expenditures credits are mutually exclusive, with a company typically splitting its credit claims between the two credits, using the higher rate of the well lease expenditure credit as much as possible.
But a company operating in Cook Inlet can also take an NOL credit, a factor that can result in the state picking up more than 50 percent of a company’s costs. And all of these credits can be taken as tax credit certificates.
HB 247 is phasing out the well lease expenditure credit, cutting it in half in 2017 and eliminating it in 2018.
A bill introducing a jack-up rig credit for the Cook Inlet was also passed in 2010, to encourage offshore Cook Inlet exploration drilling. This credit expired on July 1 - it may have encouraged companies to bring jack-up rigs to the inlet but was never used, probably because it proved easier to claim the other regular credits.
Middle Earth In 2012 the Legislature passed bills somewhat paralleling in Middle Earth basins the approach that had been taken to encourage exploration in Cook Inlet. There was a tax credit for the support of LNG storage facilities and a new tax credit of 80 percent of the cost of the first two wells drilled and 75 percent of the cost the first seismic program in each of six defined Interior basin regions. The credit expired on July 1. However, Ahtna Inc., the Native regional corporation planning to drill for gas near Glennallen this year, has obtained a one-year extension to the credit.
Another tax credit, the education tax credit, has been on the books for many years and enables companies to take credits for contributions to qualified educational and vocational programs. This credit does not specifically relate to oil production taxes and can be claimed by wide variety of businesses, not just in the oil industry, Alper said.
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