A guide to understanding Cook Inlet tax incentives

Two branches of Cook Inlet tax credits exist — those credits a company can apply against its tax liability with the state, and those credits a company can covert to cash.


Lennie Dees, audit master for the tax division of the Alaska Department of Revenue, said what credit a company applies for depends on the individual company, the activity that company is performing, the size and scope of the work and what the company’s long term plans are.

All oil and gas companies working in Cook Inlet that are incurring expenditures, whether they are producing or not, can qualify for various tax credits, Dees said. Usually a company that does not have a tax liability can get cash from the state under certain credits. However, if a company is producing and has a tax liability with the state, they must use the credits to offset their tax liability, Dees said.

If a company has a tax liability, it would likely first use up non-transferable, non-cashable credits to reduce its production tax liability to zero. Normally companies in Cook Inlet can eliminate that liability, Dees said, and then apply for other credits based on expenditures, like exploration, drilling and seismic data gathering that can be converted to cash.

If a company is not producing — such as an explorer new to the area — it has no production tax liability and, in that case, receives credits based on expenditures only, Dees said.

There are several tax credits on the state’s books, but there are five main credits available to Cook Inlet explorers. Those credits are the qualified capital expenditure and well lease expenditure credit, carried-forward annual loss credit, small producer credit, alternative credit for exploration, and the jack-up rig credit.

In fiscal year 2011, companies claimed $41.3 million in total Cook Inlet tax credits related to oil and gas encompassing production and exploration, according information provided by Dees. That number is up significantly from 2010’s $10.1 million, and 2009’s $8.9 million. Figures for 2012 were not available.

The qualified capital expenditure and well lease expenditure credit is the most widely-used credit available to explorers and producers, Dees said.

The credit has special provisions for work done outside the North Slope. In Cook Inlet it is good for 40 percent of qualified capital expenditures. Those expenditures include things like constructing facilities, laying pipeline, and buying equipment and capital.

“It is a myriad of items,” Dees said. “It includes everything from drilling to constructing or building facilities.”

The well lease expenditure portion of the credit includes the intangible costs related to drilling a well, such as fees for using the rig, costs of the labor and other items. Usually these costs are about 75 to 85 percent of what a company spends to drill a well, Dees said.

“It is kind of the activities associated with drilling the well that don’t have a physical, tangible property,” he said.

The QCE went into effect in 2006, and the WLEC went into effect in 2010, as part of the Cook Inlet Recovery Act.

In the early stages of exploration and production of an oil field, before revenues are generated, companies incur costs, but have no revenues to offset them, Dees said. When companies operate at a loss, the carried-forward annual loss credit allows them to claim 25 percent of the amount of the loss on both capital and operating expenditures.

“If a company goes out, has zero revenues, has $100 of expenditures, they can get a tax credit for 25 percent of that amount, so they’d get a $25 tax credit on that $100,” Dees said.

The credit can be used along with QCE and WLEC, for a max credit of 65 percent together in Cook Inlet.

Both the annual loss credit and the QCE and WLEC credits can be cashed out if the company doesn’t have a tax liability to offset. If a company is operating in multiple areas of the state, the credit may be transferred from Cook Inlet to another area, like the North Slope, to further offset a tax liability. If a company wishes to cash out, they have to meet certain requirements, Dees said. The carried-forward annual loss credit went into effect in 2006.

The small producer credit is available statewide if a company has started commercial production, but is producing less than 100,000 barrels or BTU equivalent per day. The credit allows the company to eliminate its tax liability up to $12 million. Most of the producers in Cook Inlet qualify for the credit and Dees said it is likely that no inlet producer pays production tax.

“Most of the companies take advantage of this because in Cook Inlet it pretty much wipes out most of production tax liabilities down there,” Dees said. “This is a non-transferable credit and a non-cashable credit. If they otherwise have a tax liability, they’ll use this credit to wipe out the tax liability and then they can turn around and, with all the other credits, like transferable credits or the monitizeable credits, they’ll turn those into the state for cash.”

The credit, which went into effect in 2006, is available until the later of either 2016 or nine years after a company first starts commercial production on the property to which the credit applies.

The alternative credit for exploration, which began in 2003, is designed to incentivize companies to explore in areas where they had not previously.

In Cook Inlet, companies get a 40 percent discount on seismic exploration costs outside an existing unit, 30 percent for drilling costs greater than 10 miles from an existing unit, 30 percent for pre-approved targets and 40 percent for drilling costs that are greater than 10 miles from an existing unit and pre-approved new targets.

The credit can be converted to cash and can be coupled with the carried-forward annual loss credit, Dees said.

“One way to look at it is that the state is sharing in the risk of exploration,” Dees said. “Exploration is one of these activities that doesn’t have a high success rate. The rule of thumb is that on an exploration well, out of every seven, you may find one that has a measureable quantity of oil and gas deposits that might be commercially produced.”

In exchange for sharing some of the risk, the state requires the producers to share certain information with them after a defined period of time. After 10 years, companies must release the data from their seismic explorations and after two years they must release information such as well log data from their drilling campaigns, Dees said.

The Cook Inlet jack-up rig credit is designed to incentivize companies to use a jack-up rig to drill wells offshore, which, before a few summers ago, had not happened in the area in several decades.

The credit, which began in 2010, incentivizes the first three wells drilled by the first jack-up rig to arrive in the area regardless of the company using that rig. It requires the well to be drilled down into a certain geologic layer in the inlet.

The credit is for 100 percent of the cost of the first well up to $25 million, 90 percent of the cost of the second well up to $22.5 million and 80 percent of the cost of the third well up to $20 million.

It stipulates that if the well drilled is brought into production, the operator will repay 50 percent of the credit over a 10-year period following production start up.


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