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Cook Inlet oil tax credits separate issue Concerns in Southcentral were over natural gas production; producing companies facing changes in credit system for projects underway KRISTEN NELSON Petroleum News
In addition to changes impacting the North Slope, House Bill 247, Gov. Bill Walker’s proposed changes to the state’s oil and gas tax credit system, would repeal capital and well lease expenditure credits in Cook Inlet.
In presentations to the House Resources Committee in early February, Ken Alper, director of the Department of Revenue’s Tax Division, said HB 247 would repeal the 20 percent qualified capital expenditure credit and the 40 percent well lease expenditure credit for areas outside of the North Slope. Cook Inlet is the only area outside of the North Slope with production.
A new field developer in Cook Inlet, he said, receives a 25 percent net operating loss credit - which would remain under HB 247 - which is stacked with either a 20 percent capital or a 40 percent well credit, which means the state typically refunds 50-60 percent of the costs of new field development.
A total of $500 million to $800 million in these credits have been earned, more than 85 percent since fiscal year 2013 with a “substantial portion” spent on oil drilling and well workovers.
Cook Inlet tax caps, which sunset Jan. 1, 2022, are zero for oil and an average of 17 cents per thousand cubic feet for natural gas, which means state income from oil and gas production in Cook Inlet comes from royalties, property taxes and corporate income tax. The majority of refundable oil and gas tax credits go to Cook Inlet companies, while Cook Inlet production generates limited revenue to the state.
Janak Mayer, chairman of enalytica, the Legislature’s consultants, said the Cook Inlet credits were one thing when the state was bringing in billions of dollars and there was a shortage in the Cook Inlet gas supply.
But with much less revenue from the North Slope, anyone who looks at the numbers for Cook Inlet credits would wonder how long that can go on, creating uncertainty over the fiscal regime.
Setting a stable, sustainable system is paramount, Mayer said, speaking in presentations at the end of February.
The gas supply concern Prior to the 2010 passage of the Cook Inlet Recovery Act there was a shortage of natural gas, used for heat and electricity in Southcentral, and residents were asked to practice cutting back on power and heat usage.
Rep. Mike Hawker, R-Anchorage, said he was concerned that HB 247 would put Cook Inlet back where it was when there were blackout drills.
Commissioner of Revenue Randall Hoffbeck said the dynamics of Cook Inlet are different than they were five to six years ago. Then, he said, the situation was a market looking for gas with incentives needed. There is now gas behind pipe, he said, and there are fields that lack a market.
Hoffbeck said there is additional gas that could be brought on line and asked if the state can declare victory and move on.
Hawker said long lead time investments were required and described getting more gas as comparable to turning an aircraft carrier.
The price issue Rep. Paul Seaton, R-Homer, said he wanted to see the price of natural gas in Cook Inlet worked into the equation. Previously, he said, if you produced gas in Cook Inlet you lost money, but now that gas is the most expensive in the U.S. He asked to see how the timing of the rise in gas price factored in, and not just the credits, and said Cook Inlet credits needed to be investigated as a subsidy.
The 2010 bill, among other things, changed the criteria the Regulatory Commission of Alaska could consider in approving or disapproving gas supply contracts for utilities and after 2010 RCA approved higher-priced natural gas contracts.
Mayer told the committee that historically Cook Inlet gas prices were equal to or below Henry Hub, but the price has risen steadily since 2004 and since 2010, prices have been between $5 and $6 per mcf.
The prices are a result of the Cook Inlet Recovery Act and the consent decree the state imposed when Hilcorp acquired Marathon’s gas interests in Cook Inlet, making Hilcorp the dominant gas producer in the area.
Mayer said that other jurisdictions have found that prices in the range of $5 to $7 per thousand cubic feet have been sufficient to produce the most expensive gas - shale and deepwater.
The market issue Mayer characterized the Cook Inlet market as constrained and cited statements by Furie Operating Alaska, operator of the Kitchen Lights unit, that the constrained market made their development difficult because of the expensive upfront costs for the platform, pipelines and onshore facilities. He said Furie has one well on production at some 18 million cubic feet per day, what they are able to sell into the market, making the project very difficult economically.
Mayer said that while the Cook Inlet fiscal system is one of the most generous in the world, with the net operating loss credit and the capital credit resulting in some 45 percent of the cost being borne by the state, and up to 65 percent state support for drilling, economics are still very challenged.
If Cook Inlet was an unconstrained market, allowing a company to drill a prospect up quickly, credits would be much less necessary, Mayer said.
Asked by Hawker how the market could be unconstrained, Mayer said that was a bit of a chicken and egg situation, with an export anchor tenant needing certainty of supply and a company developing a project need to know the demand would be there.
There has been discussion of the possibility of Agrium re-opening the nitrogen fertilizer plant at Nikiski, but Rep. Kurt Olson, R-Soldotna, said while Agrium came to the area in the summers of 2013 and 2014 they didn’t come back last summer. He said the plant is pretty well deteriorated and without state support he didn’t think it would reopen.
Nikos Tsafos, president of enalytica, said if Cook Inlet had demand the resource could be developed, but then the area would run out much sooner - and perhaps that wouldn’t be enough supply security for Agrium.
The question, he said, is whether the Department of Natural Resources’ estimate of 1.6 trillion cubic feet of natural gas is correct, or whether it’s some other number.
Hypothetical Mayer said the models they were presenting were hypothetical, were not based on knowledge of any project, but were intended to give legislators a directional idea.
The basic directional conclusion, he said, is that market-constrained development is very difficult; un-constrained develop looks possible without support; and drilling in existing fields appears to be generally economic.
The models, he said treat facilities and acquisition investments at existing fields as sunk costs and when you do that, Mayer said, it’s hard to see circumstances in which drilling additional wells in existing fields isn’t profitable.
Rep. Bob Herron, D-Bethel, asked Mayer to outline good and bad aspects of HB 247, and “ugly” aspects - things that need more work.
Mayer said on the good side it’s time for the state to have a serious discussion about Cook Inlet credits, what the state’s policy aims are for the credits and whether there aren’t more efficient ways to achieve those aims.
In the “ugly” category Mayer put simply leaving everything as it is, sunsetting and taking away capital credits and leaving NOL in place.
Fundamentally, he said, the question is: What is the optimal fiscal regime in Cook Inlet long term and if subsidies are necessary, what is the optimal means of doing that. Simply getting rid of credits is a crude answer to a question that possibly requires more analysis - not just what can we cut now, but what is necessary for subsidy and how can we provide that and have a sustainable system for the inlet.
As for bad, Mayer said removing capital credits effective July 1 seems rash since companies have commitments to drilling programs for this year and rely on the credit system as it exists.
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