Our state oil tax system is simple in concept, but the "tweaks" we attach to it complicate things.
At its core, we have a net-profits tax. Costs are deducted from revenues, and the net value is what gets taxed. Revenues are determined mainly by oil prices, which are unpredictable. Recently, they are trending down.
Costs are what it takes to extract the oil and move it to market, including production, pipeline and tanker costs.
Before 2006, we had a tax on gross revenues, meaning production costs were not allowed as deductions. The tax rate, whatever it was, applied to revenues after deductions only for transportation costs.
Simple enough, but then we began adding special incentives for special purposes. These were all well meant but over time they have mostly not worked out as intended. Many have had to be undone, which was always messy.
This all started in 1977, just as North Slope oil production started, when we added a special provision, called the Economic Limit Factor, or ELF, to lower the tax on small, high-cost fields.
This was really meant to protect the smaller Cook Inlet oil fields from the higher tax rates applied to the large, prolific North Slope fields. As time went by, the ELF began to lower the tax rate on large fields too.
This was very controversial. Many argued that lowering the tax on large fields would encourage producers to squeeze more oil out of those fields, which were then just beginning their decline (in the late 1980s). Others felt the top tax rates should continue to apply to the very large fields.
More time passed and the ELF became obsolete, to the point that the second-largest field in North America, the Kuparuk River field, paid little or no state production tax.
Finally, in 2006, then-Gov. Frank Murkowksi, had had enough. He called for a major overhaul of the oil tax that not only got rid of ELF but replaced the gross revenue with a net revenue tax.
The switch to net revenues was actually an increase in taxes on the industry, but Murkowski persuaded the companies to accept it, which they did reluctantly. This was at a time when Murkowski was also engaged in gas pipeline negotiations with the companies and he made the tax change part of the deal.
The gas pipeline plan never progressed that year, but the tax change passed the Legislature.
As an incentive, ELF was gone, but something else took its place. Murkowski had long been interested in finding a way to encourage oil producers to reinvest their profits in Alaska, and he hit on the idea of a capital investment tax credit. If the companies reinvested, they lowered their tax bill, the thinking went.
Exploration tax credits had long been in the law to allow companies to credit certain exploration expenses against their tax bills. Murkowski's idea was to apply it broadly, to 20 percent of all capital investments. If $10 was invested, $2 could be credited, dollar-for-dollar, against the production tax liability.
Meanwhile, tweaks were added to the exploration tax credits, mostly by legislators who wanted exploration in certain areas, like Cook Inlet. A special "jack-up rig" tax credit was enacted that paid 80 percent to 100 percent of the cost of Cook Inlet wells. Exploring companies also learned to "stack" the capital and exploration tax credits atop of each other to the point that, typically, 65 percent of a company's exploration costs were paid by the state.
Another tweak was the state buying tax credits themselves from an explorer, paying cash. This was a real boon to small independent companies with thin wallets.
Whether the proliferation of exploration credits is good policy is debatable. We did get new gas discoveries in Cook Inlet because of it, but meanwhile a real problem was developing with the 20 percent capital investment tax credit.
The credit was getting very expensive. For the current budget year, FY 2014, the cost to the treasury is estimated at a billion dollars for the capital investment tax credit. About half of that will be paid out in cash to the exploring companies (when they cash in their credits) and half is foregone tax revenue from producing companies who apply the tax credits to their tax bills.
There was one other problem that was more fundamental: The credit wasn't resulting in much new oil being found. Small independents are hustling to explore, but their discoveries (and prospective discoveries) are too small to slow the production decline.
The big undiscovered oil, it seems, are untapped resources within the big producing fields. For the producing companies, the tax credits aren't enough to spur a lot of new investment. The high tax rates offset any benefits of the tax credits, the companies say.
In retrospect, the 20 percent capital investment tax credit wasn't aimed at the right thing. It wasn't aimed at finding new oil.
It was indeed encouraging investment, including in maintenance-related capital projects. The major producers have said that 70 percent of their capital investment in recent years was targeted to major maintenance.
What to do? In 2011, Gov. Sean Parnell decided a major revamp of the tax credit was needed. He finally got this in Senate Bill 21, passed last year. The exploration incentives were left intact but the 20 percent capital investment tax credit was junked, replaced by a new per-barrel tax credit targeted at new production.
Parnell's idea was no new oil, no tax credits. A production tax credit of $5 a barrel is now allowed (the per-barrel credit varies for producing fields). One significant difference is that new production, and revenues, have to come before the tax credits are paid, so there's no big drain on the treasury.
There were other changes in Senate Bill 21, but this was a big one.
All of this raises other questions, however. Would the companies have developed this new oil anyway, without the tax credits? And how do we define "new" oil from existing fields?
More about that in my next column.
Tim Bradner is an Anchorage-based business writer. He was a member of BP's external affairs staff in the 1970s and early 1980s.