Tax credit changes show unpredictability, consultant says
A consultant to the Legislature reviewed the oil and gas tax credit changes proposed by Gov. Bill Walker and concluded the State of Alaska needs one thing above all else: fiscal stability.
Janak Mayer, chairman of the petroleum industry consultant firm Enalytica, said in a marathon session of presentations before the House Resources Committee Feb. 25-27 that the administration’s proposals to reduce state expenses and increase revenue are not individually drastic. However, they collectively make significant changes to the industry-favored tax structure known as Senate Bill 21 that was implemented less than three years ago.
“It is said over and over again, but stability is the most important element in any fiscal system,” Mayer said.
House Bill 247, the administration’s bill to change Alaska’s oil and gas credits, is not a tax policy overhaul, but incremental changes to the credits with the goal of more revenue could give industry the impression the state is headed down a “slippery slope” of tax tweaks, he said.
Collectively, Mayer said the small tax changes would likely have a significant adverse impact on producers, particularly at the low oil prices of today’s market.
Soldotna Republican Kurt Olson commented that the Legislature changes oil tax policy virtually every two years.
“That’s not (HB) 247’s fault, it’s just the newest one,” Olson said.
The Alaska Oil and Gas Association contends the bill amounts to drastic changes in the state’s oil tax system that will directly impact production and investment if enacted.
Walker’s suite of oil tax revisions was introduced along with tax increases on other prominent industries as part of an overarching fiscal plan to pull the state out of annual budget deficits that have grown to more than $3.5 billion as fast as the price of oil fell to the current $30 per barrel range. The tax changes include raising the minimum production tax rate from 4 percent to 5 percent, as well as “hardening” the tax floor to prevent companies from claiming losses against tax liabilities in order to pay less than the minimum tax.
Among closing other loopholes, HB 247, and its companion legislation Senate Bill 130, would limit the amount of money the state pays out to explorers and producers each year by setting a refundable credit limit of $25 million per company per year.
Refundable credits can be applied to tax liability, sold to another company with a liability or cashed in to the state, resulting in a direct expense for the state.
Walker deferred — through a partial veto — $200 million of a $700 million line item in the 2016 budget for the state’s projected refundable credit obligation this fiscal year. That action was meant to start a conversion about the expensive subsidy program, Walker said, and it did. At the same time, the veto is alleged by those in industry to have scared potential private investors and killed some deals in the state that were dependent on the credits as collateral for additional financing.
The state’s payout of refundable credits peaked in fiscal year 2015, with more than $400 million paid to companies working in Cook Inlet and another $224 million going to North Slope operators, according to the Department of Revenue.
If passed as proposed, HB 247 would cut the annual credit outlay to about $200 million and generate about $100 million per year in additional tax revenue, the administration has said.
Of the eight tax credits that would continue beyond 2016 under current law, five are refundable; the remaining three are non-transferrable credits that can only be used by North Slope producers.
HB 247 would eliminate two of the refundable capital expenditure credits available for companies working in Cook Inlet.
The loopholes the governor’s bill attempts to close are mostly related to what have been described by legislators as unintended consequences of SB 21’s credit provisions, which were not modeled for fiscal impacts at oil price regimes below about $60 per barrel when it was being debated.
One of Walker’s changes would prevent the state from covering more than 100 percent of a North Slope operator’s losses for producing new oil during times of low prices, which could occur if the Gross Value Reduction for new oil and the Net Operating Loss credits are combined.
Mayer, who helped the Legislature scrutinize SB 21, said he was surprised to learn of the possibility for the state to pay more than a company’s loss through the combined credits, but the bigger issue is again how many statutory cracks lawmakers try to fill at once.
“There are a number of things in (HB 247) that are really important questions to be thinking about,” Mayer said. “It’s some of the specific solutions and the incremental nature of what’s being proposed that I have the biggest worry about.”
He testified Feb. 25 that on top of Alaska being an innately high-cost place of business for oil companies, the state’s near total dependence on the industry for revenue makes it a more risky business environment. When in need of cash, Alaska is more likely to turn to the industry for concessions than other state’s or countries that have an oil and gas sector as part of a more diversified economy, he reasoned.
Additionally, Alaska’s overall industry tax structure combines tax systems kept separate in other jurisdictions. The state’s mineral royalty acts as a steady, regressive gross tax often used by resource-dependent governments to provide income during low price cycles, Mayer said, while the more volatile and net production tax — on its own — gives producers a break at low prices but captures more revenue during profitable periods through progressivity.
Another issue of concern is the July 1, 2016 effective date for most of the provisions in the bill, according to Mayer. He said immediately changing the credit system could significantly impact exploration and development plans that have already been drafted.
The Oil and Gas Tax Credit Working Group led by Sen. Cathy Giessel, R-Anchorage, recommended to harden the minimum tax floor, as the administration wants to do, but also noted that any changes to the system be made gradually.
Cutting Cook Inlet tax credits wouldn’t generate new revenue, as no production tax is collected on the basin’s oil and its natural gas production tax would not be impacted.
Eliminating the capital and drilling credits would save the state money, but what effects that would have on an out-of-step gas market needs to be considered, Mayer and Enalytica President Nikos Tsafos said.
The 2010 Cook Inlet Recovery Act, passed by the Legislature to encourage natural gas development, among other things, instituted a 40 percent drilling and exploration credit that HB 247 would cut.
The reliability of Southcentral’s natural gas supply has improved since the passage of the act when fears of gas shortages abound, but the act contributed to distorting the isolated market, according to Mayer and Tsafos.
Further complicating matters is the Consent Decree that Hilcorp Energy and the state agreed to in 2012, which allowed Hilcorp to purchase a vast majority of the producing assets in the Inlet, but also set gas prices on most utility contracts through early 2018. The prices laid out by the Consent Decree are in the $6-$8 per thousand cubic feet, or mcf, of gas.
Recent contracts for gas supply beyond 2018 have been at slightly lower prices than the Consent Decree, evidence that some natural market forces may at play.
A simple lack of demand for Cook Inlet natural gas has put nearly everyone involved in a bind. As Henry Hub-based natural gas prices have fallen in the Lower 48 to about $2 per mcf in recent years and worldwide LNG prices have fallen as well, Cook Inlet has become one of the most expensive natural gas markets in the world.
High gas prices and tax credits have undoubtedly incentivized new investments and helped turn Inlet production around — and secured Southcentral’s primary energy source — but the whole situation has led to unsustainable state expenses that won’t be recovered under the current system, according to Mayer.
The credits, combined with the lack of a significant production tax, has led to Cook Inlet being one of the most generous fiscal regimes for oil and gas in the world, he said, with about 40 percent total government take.
Still, companies are only able to manage about a 10 percent to 15 percent return on investment because the volume of gas they can sell is basically capped with limited exports and no major industrial anchor customer.
“The basic impact of the credits is to make what is a very marginal investment maybe just possible,” Mayer said.
While it’s time for the state to have a “serious conversation about what the state’s policy aims are” through the Cook Inlet credits, he added that eliminating the capital credits July 1 “seems like a rash decision.”
Tsafos suggested — now that the Inlet can supply Southcentral for at least 10 years based on Department of Natural Resources reserve estimates — allowing market forces to return as much as possible in the coming years as the Consent Decree expires.
“The broad instinct should be rather than try to artificially prop up a market that isn’t working, it’s to try to think more generally about how do we make this market work better,” Tsafos said.
Rep. Mike Hawker, R-Anchorage, a sharp critic of many provisions in HB 247, said the state should be careful to not disrupt the Cook Inlet gas market further through credit changes because it will change the Consent Decree’s current March 2018 expiration.