Oil Tax Credits: What are they, and why are they a problem?
Last modified: 12th August 2019
- Executive Summary
- We Make Large Cash Payments to Oil Companies
- These Credits are NOT an Investment in the Future
- Our Production Tax is no longer a Tax - It’s a system for redistributing money between Oil Companies and the state.
- The State Pays 35% of Oil Company Expenses, through the Carried-Forward Annual Loss Credit
- What is Alaska’s Share?
Executive Summary
Historically, one of the primary ways the state gets revenue from oil production has been the Oil Production Tax (the other is royalties). The current version of the production tax involves large cash payments to oil companies. These payments make the tax rate negative when prices are low, and cripple the state’s ability to balance the budget. They are promoted as an investment in future oil revenue, but doing the math, it is very unlikely for the state to recoup that investment, even if the credits do lead to more oil production. The government does not make more money by subsidizing development that would be uneconomic for the private sector to do alone. Cash payments, credits against tax liability, and taxing net profits rather than gross value have combined to make our production tax lower than at any time in state history.
Abolishing the credits would reduce risk to the state and eliminate the possibility of spending more on credits than we take in in taxes. Oil development would be determined by market forces, which the state could then tax at a reasonable rate. Replacing the current tax scheme with a flat tax on wellhead value would bring in significantly more revenue than the current system, and be simpler to administer. Making a wellhead tax progressive with price (instead of flat) would further increase revenue to the state.
We Make Large Cash Payments to Oil Companies
In 2007, the state began a system of reimbursable tax credits for smaller (less than 50,000 barrels/year) oil companies
We have paid out $3.4 billion over the past 10 years from the state general fund.
In fiscal year 2016 payments to oil companies were third largest line item in the unrestricted general fund budget ($500 million), after K-12 education ($1.2 billion) and Health and human services ($1.1 billion).
The state has been paying approximately 85% of exploration costs and 55-65% of development costs for new projects.
The state tax director estimates we’re “into these projects for about $24 a barrel.”
State production tax at current oil prices is about $1.24 a barrel.
In recent years, over half of these credits have gone to Cook Inlet, where oil paid no production tax at all. (set at $0/bbl until January 2017, now a flat $1/bbl)
For fiscal year 2017, there are $775 million in outstanding credits to be paid by the state, but payment above the $30 million minimum was vetoed.
These credits are still outstanding and never expire, resulting in estimates of nearly $1 billion owed in 2018.
Summary : These tax credits are a huge and ever-growing liability to the state, crippling our ability to balance the budget.
These Credits are NOT an Investment in the Future
- Proponents claim that credits will lead to new oil development, and increased tax revenue for the state.
- Even if credits do spur new development, the state may not make any money.
- Current credit structure means the state pays 35% of costs for new developments. (past credit structure was more generous)
- New developments cost many billions of dollars. It takes a huge amount of oil, or very high prices, for the state to make that money back in taxes.
- An example: Let’s take the biggest new discovery of recent years - Caelus Energy’s Smith Bay discovery in 2016. According to the oil company, this will cost $8-10 billion to develop, and could produce up to 200,000 barrels per day. At a $65 per barrel oil price, it would take 8 years of that high level of production for the state to break even on its $3 billion (35% of the cost) investment. It would take much more than that for the state to actually make money for the general fund.
- If the state has $3 billion to invest, it would be far better to put that in the stock market.
- Reality may well turn out to be less rosy than oil company press releases. The state has sought to promote new oil development for decades, while production has steadily declined.
Summary : The state is making large cash payments to oil companies. History and evidence suggest that these payments will NOT yield large future revenues for the state (even if they lead to new production and yield large revenues for the companies involved). The most likely outcome is large current expenditures (which the state has no budget for) in exchange for marginal future production which does not offset present costs.
Our Production Tax is no longer a Tax - It’s a system for redistributing money between Oil Companies and the state.
- The state may lose or gain money with this “tax,” due to factors outside government control.
- Production Tax was negative in 2016. In 2016, the state received $186 million in Oil Production Tax, and paid out $500 million in Production Tax Credits, for a total of -$314 million.
- Production Tax is predicted to be marginally positive in 2017 ($100 million) only because Governor Walker vetoed the payment of oil tax credits for this year.
- Production Tax is expected to be -$900 million in 2018.
- State predictions show production tax at historically low levels, as far into the future as they predict.
- This is not explained by low prices. The state predicts steadily rising prices (though oil price predictions are notoriously bad).
- This is not explained by low production. Production tax as a percentage of wellhead value is lower than ever before.
- Summary : The current production tax is a mixed tax and subsidy system which is unpredictable and has recently been costly. Under this system, the state garners a lower percentage of oil value than with any previous tax scheme.
The State Pays 35% of Oil Company Expenses, through the Carried-Forward Annual Loss Credit
- This credit is responsible for the vast majority of credits paid in recent years, and almost all of the ones still being accrued.
- Some expenses are “deductible” - these are subtracted before production tax is calculated.
- The credit is based on all the rest: “adjusted lease expenditures that are not deductible in calculating production tax value.”
- Why aren’t expenses deductible? Either:
- Because the company making them doesn’t owe taxes (because it doesn’t produce oil yet).
- Or the company operated at a loss (expenses higher than wellhead value).
- The credit is currently equal to 35% of expenses for North Slope operators.
- We pay this to small oil companies in cash, and to large oil companies by reducing production tax in the years after the loss.
- Small oil companies can sell these credits to larger oil companies, who can use them to reduce production tax - even to zero.
- They don’t expire. Even if we don’t appropriate funds to buy the credits, we are eventually on the hook for the full amount due to lower production taxes.
- This makes the state an automatic investor in all oil company projects and expenditures - economic or not - with no choice, and no way to back out.
- When prices fluctuate, the state takes the risk, and the oil companies take the profit. In a series of low price years, the oil companies may lose money. When prices rise, the oil companies subtract these “carried forward losses” from the taxes they owe the state, reaping profits beyond the profits they would normally receive. This way, the company can use the earnings from the good years to offset the bad years. The state cannot.
Summary : The carried-forward annual loss credit makes the state an automatic 1/3 investor in all oil company projects, and shifts risk from the oil companies onto the state. It can reduce production taxes to zero, even for large oil companies, and cripples the state’s ability to use oil taxes from good years to offset bad years.
What is Alaska’s Share?
- Historically, production taxes have averaged around 13% of wellhead value.
- Adding this to royalties, corporate income tax, and property tax, the state’s total share of oil value hovered around 1/3.
- With the beginning of MAPA/SB21 in 2014, production taxes fell to historic lows, and are not expected to recover. Official state predictions show future production tax topping out at around 2.7% of wellhead value, far less than the historic 13%.
- 2.7% is a good year. In bad years, this “tax” costs the state money , due to high credit payments.
Summary : The state still makes money from oil due to royalty payments, but our current production tax scheme makes large cash payments to oil companies that we cannot afford, shifts risks from the oil companies to the state, and is ineffective at raising money under any reasonable set of assumptions. Even when we take into account the potential for royalty payments, this “investment” in the oil industry costs the state more money than it is likely to recoup.
A Gross Wellhead Tax Would be Simpler and Serve us Better ** **
- ACES was the tax scheme operating from 2007-2013.
- It had a very high progressivity. Tax rates increased with price, and at the high oil prices of the time, tax rates and revenues were very high.
- But that price spike masked several problems with ACES–large credits, cash payments to oil companies, and a tax based on net profits instead of gross value. At current oil prices, tax revenue under ACES would be similar or lower than today.
- MAPA retained most of these problems (credits, cash payments, and net profits tax structure), while reducing tax rates at higher prices, and reducing tax rates even farther for “new oil.”
- If the state had instituted a flat production tax of 12.9% wellhead value (instead of either tax scheme), we would have come out ahead.
- We would have missed out on several billion dollars during the combination of oil price spikes and progressive tax rates under ACES.
- But with a flat tax on wellhead value, we would make around a billion dollars more each year than we make under the current MAPA scheme.
- If the state wished to maximize revenue and minimize risk, it could combine the progressivity of ACES with the reliability of a gross value tax. It would abolish the tax credits, tax on gross wellhead value, and make that tax rate progressive with price.
Created: Jan. 19, 2018