Seaton: SB 21 lacked broad modeling

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Homer Republican says pendulum swung from one side to another when Legislature switched from ACES to SB 21, calls for stability

STEVE QUINN

For Petroleum News

House Rep. Paul Seaton has been on the House Resources Committee for his entire time in office: 14 years. The Homer Republican joined Republican North Pole Rep. Tammie Wilson in crafting the House’s version of HB 247, which is being sorted out with in a conference committee during this special session. Seaton spoke to Petroleum News about what drove the compromise and why he believes SB 21 and chronically low oil prices have put the Legislature in a difficult position.

Petroleum News: You’ve been on Resources for 14 years, so as you see it what are the dynamics driving the HB 247 discussion. Is it the deficit or something more?

Seaton: What’s driving this is the deficit and we recognize that SB 21 did not adequately look at low prices. When you look back at the information we got from the consultants, the range of prices estimated ran from $80 to $140 with $80 being low and $100 getting the most concentration.

People didn’t want to concentrate or think about full range of prices. People found during the ACES debate that people hadn’t concentrated enough on the impacts of high prices. People get stuck in a grind of the price today is what the price is going to be. Without a full analysis of where you are, you end up where we are now: really large problems at low oil prices.

Petroleum News: There’s been quite a disparate view on what, if anything, should be done with the oil tax credits and even the minimum rate. What are you observations on this?

Seaton: There were different philosophical viewpoints. One was the companies are losing money so we have to do everything we can to protect them at low prices and help mitigate their losses. The other view was we have a tax system that isn’t working where we could end up paying more in some cases than we receive in production tax.

It’s hard to have a production tax credit when you have no production tax. The current system has the ability at low prices to generate zero production tax because the large companies can roll forward credits based on the net operating loss from the previous years to offset their tax to zero.

At a time when we are severely fiscally constrained, we could get no production tax, in fact have more liability because of cash credits paid out to the smaller companies, supporting the industry by taking only from savings.

Petroleum News: What about royalty income?

Seaton: Yes, some say can spend your royalty, but the problem is the royalty is the ownership value of the oil, not the tax value of oil. We had created a tax credit system to receive money from oil companies from the tax and remit part of that to incentivize certain kinds of development. Having failed to analyze that fully at low prices, we found that the system did not work for the treasury. Some people say it’s working for the companies or some people say it’s working to keep investment going, but there were some big anomalies in the bill.

The tax credits that were allowed in the transition to roll forward at 45 percent of net operating loss combined with the exploration credit of 40 percent meant that the state on some projects would be paying 85 percent of the entire project, which is extraordinary when we get no additional value from that.

In other words, we would get value from royalty if it’s ever produced and we would gain production tax if it’s ever produced. But since it’s new oil projects, there was a concession in there called gross value reduction, in which if it was new oil, 20 percent of the entire revenue, the gross revenue that they receive was exempt from taxation.

If it was a field that had greater than 12.5 percent royalty, then there was SB 21 language that said oh, we will give you an additional 10 percent of your gross revenue that will not be taxed. When you combine that 30 percent of the gross revenue not being taxable, there was this anomaly built into the law to use the gross value reduction and add it back into their loss so we could actually pay 100 percent or over 100 percent of the costs. That’s if it happened to be a producer that had gross value reduction that would mean we would pay 100 percent of the project. We had that in Smith Bay with two wells drilled there.

I can’t tell you the exact amount whether it was 85 or 100 percent, but depending on how the claims were made, it could be either one of those two situations with us not getting any ownership share of the project while investing 85 percent or more of the entire cost of the exploration, didn’t make much sense to me. To some people it does.

That has gone away. The exploration credits expire this year, so we won’t have that. And the 45 percent has been reduced to 35 percent because the 45 percent was transition from ACES to what we have today.

So in broad generalities there are a number of things in the tax code. We have SB 21 and combinations with previous taxes, because not everything went away and was replaced with a standalone SB 21. It was stacked on and transitioned from other taxes. All those things playing together created what some of us view as anomalies. The oil companies saw those as the way the tax law was written and so it should remain that way. They have testified against all changes to oil and gas taxes.

Petroleum News: Realistically, do you expect any kind of response other than that? Their job is to look out for their interests.

Seaton: I have never said that if we have a tax code that allows 85 percent or 100 percent that somebody shouldn’t use the tax code. That’s our fault, not theirs. It could be theirs if they knew these things ahead of time when the discussions were taking place, which we didn’t know and they kept quiet about. But they are not required to tell us when we make mistakes, either. So I don’t knock any company for doing that. I’m just saying we need to clean up our system. There is no tax system that’s perfect.

I mean ACES had problems. I had a bill in to modify ACES at the time Gov. Parnell was doing SB 21. I offered one (HB 51) before that to get rid of that top 25 percent bracket. Instead of modifying that system, we went to an entirely different system.

With tax systems, we’ve got this problem that’s kind of like a pendulum that swings one way and gets overloaded then comes back and swings too far the other way. My goal is to get us a reasonable accommodation for both the industry and the resource owner, the taxing authority, which is the state of Alaska.

Petroleum News: So how did you and Rep. Wilson manage to craft something that got out of the House?

Seaton: We had to modify what we wanted to see. A very good example is we both knew taking one-third of the company’s expense and giving them a tax credit for that, whether it’s a cash credit or a write off was too high an amount. The original amendment, No. 12 that was offered on the floor and a tie vote 19-19, that amendment said we would no longer do credits at 35 percent, we would do them at what Gov. Parnell originally proposed, which was a 25 percent tax credit. So it was an instantaneous ramp down started next year. In those negotiations the group that Rep. Wilson represented wanted a step down approach and we worked on that. It would be a 2 percent reduction each year, so we were not really happy with where we were. But we looked at what’s acceptable. How can we get there? The minority was concerned it was too slow a ramp down. They wanted a 3 percent ramp down, so the proposals were modified. It was a situation where nobody was getting what their philosophy supports.

We had three goals the whole time this discussion was taking place. One was to reduce immediate expenditures. That related to everybody agreeing July 1 getting rid of the qualified capital credits. That would be an immediate change in expenditure. The other one was to lower the long-term liability for the state.

That was done in two ways. One was reducing the rate at which you gave credits to 25 percent. The other was the credits couldn’t be carried forward if you were a producer who had reached the economics of your field, and that was 15,000 barrels per day.

So we were saying if you were developing a 15,000 barrel or bigger field, once you reach your production goal, you were no longer able to carry your credits forward. I was originally at much lower than 15,000, but 15,000 seemed to be an area where we could reach a compromise on. That’s just the nature of it. As far as I was concerned once you went into commercial production, then you shouldn’t be carrying forward tax credits or generating tax credits to carry forward. So that was really the genesis of how this got done.

Petroleum News: Whether this version prevails or not, what do you think this reveals about the dynamics of the Legislature?

Seaton: We are trying to balance those things. The third goal was that for 12 years we have tried to diversify the players on the North Slope, especially because there was perceived basin control by three large companies, so the tax credits were a mechanism to be able to financially participate in new operations and get them up there. What is the right level of those? Well you’re always picking and choosing and trying to make your best estimate.

I don’t think anything nefarious has been going on. All of the tax bills have always had problems. We had the gross tax and that grew out of itself when production was going down and we were getting more oil than water. Then we had the Economic Limit Factor. That was not designed right. People could keep water wells going basically then drastically reducing their tax rates because they had a bunch of none productive wells, even though that had good producing wells, but it was a field wide number of well.

So ELF that was when I came in: It was broken. We had Kuparuk paying zero production tax. That was the tax system. No one was cheating, but that wasn’t the intention in the design of the system. Then you have to come in and make a change. We had a series of low oil prices and oil companies wanted to be protected at low oil prices and wanted a profits-based tax.

There was some cheating going on there and people went to jail, that kind of stuff. That was the reaction to that. ACES came in and the pendulum went too far and we came back with SB 21.

In my opinion the pendulum swung back too far. There is no progressivity and as far as an effective tax rate of 35 percent, you don’t reach that until you get to $170 a barrel. So at $110 a barrel, the effective tax rate is about 25 percent. That’s a big problem I have with the tax credits. We have an effective tax rate at 25 percent but we are giving a tax credit at 35 percent.

Petroleum News: Do you think you can emerge from this special session with a bill that reflects stability? That seems to be a buzz word: stability.

Seaton: I hope so. We are looking at our payout system, that’s mainly what we are looking at. Every other big field or small field, there is very few of them that get a tax payout. You go around the world and see where there is government participation there really isn’t anything like our system. Our problem now is that it’s protecting on the low end, but there isn’t as much recovery on the high end. If you have to get to $170 before you get to your 35 percent tax rate on profits. It’s a long climb. The rate at which you’re giving credits is higher for the effective tax. It’s very difficult for that kind of system to work. That’s why we want to take the tax credits down to 25 percent.

Petroleum News: Closer to your home, the Cook Inlet Recovery Act seems to have worked for the industry and the state. What are your thoughts on that?

Seaton: A big part of that, which people don’t recognize, is the consent agreement on gas sales. We’re really talking about gas sales. Oil in Cook Inlet is really about 15,000 to 18,000 barrels a day. People don’t realize we were artificially stuck at $2 per thousand cubic feet for years and years and years by the RCA. They viewed their job as keeping the price as low as possible for consumers. Since there was excess gas on the oil production, they didn’t really have to make a profit on the gas.

But nobody is going to go out and explore for gas and not make a profit on the gas so when you are wanting that exploration, we gave a big tax credit, but we also went through this large negotiation, and now gas in Cook Inlet is the highest price in the world. That’s because there has been a down pressure around the world, but when you’re talking about less than $2 for Henry Hub and your talking $7 in Cook Inlet, it’s hard not to see where the price supports the production. Plus, the contracts go through 2023 and end up at $8.19, plus if there is any change in taxes that flows through as well.

So the Cook Inlet Recovery Act worked, but one shouldn’t say that it was the credits that was the only thing that drove that because when people can see they can make a profit on something, they will explore and develop. That’s what our consultants said, that $5 to $7 is sufficient price to develop the most expensive gas around the world, deep offshore as well as shale.

There were two factors, one was the credits. The other was if we find gas we can sell it at a profit, which is a major determinant. You can offer all the credits that you want. Nobody is going to invest if they can’t make a profit on the product they sell.

Petroleum News: So I’ve heard the term “the sale is over” for Cook Inlet. Is that accurate?

Seaton: We are fairly close on Cook Inlet. The Senate’s version ramps them down slower. We concentrated more on the wells and only if you are already producing after the first of the year. The North Slope is where we have a lot of differences. We said we will continue to offer the cash credits but on a ramped down level - we were ramping down to 25 percent - and we are only going to do that for people working on a plan and developing it.

In other words, you found something and we are getting oil in the pipeline - producing wells, not just going out and exploring. Just general exploration is the riskiest investment you can make and it’s 20 years in the future.

So we narrowed the scope of the projects that would get credits. We lowered the amount of the credits. And we lowered the size of the producing amount that needed help to keep those projects going. We were very conscious of one of our three goals to keep projects that were stimulated healthy so that they can go forward.

One of the proposals out of the Rules Committee was we’re going to get rid of credits altogether and we’re just going to let you carry forward all your expenses. Companies who have production and are paying taxes could use those, but the companies who are building out a field are maybe looking at eight years before they go to production. They wouldn’t have any finance case.

They can’t go to a bank and say I’ve got a bucket of expenses can you loan me money on this load of expenses I’m accumulating until I get my field going. That’s a long timeframe and doesn’t have any stability to get any financing. That’s why we didn’t go with that. It would basically devastate the new companies who are trying to move into the development phase.

Petroleum News: Still closer to home, there is still AKLNG. While it may not reach Homer, it still hits the Kenai Peninsula. I realize it’s not been on too many people’s radar, but what’s your take on what’s happening?

Seaton: Every project around the world is challenged at these prices. When you are selling liquefied natural gas, after liquefying it and transporting it to Japan or China for less than the price you can domestically sell it for in Alaska. That is a non-existent economic model. You need enough price in a negotiation to provide financing. I think we’re in a delay situation. We’re still doing the investment to get to the final engineering design stage, so I think the project will have its EIS and application to FERC. But until we can see a future market, we’re on hold.