The debate over the governor’s decision to aggregate Prudhoe Bay satellites for production tax purposes was heard in the Alaska House Special Committee on Oil and Gas in early February, with the Alaska Oil and Gas Association taking the floor Feb. 1, followed by the departments of Revenue and Natural Resources Feb. 3.
AOGA reviewed the history of the economic limit factor or ELF for the committee, while state officials provided the administration’s perspective.
AOGA: Both price and volume 'critical'
Judy Brady, executive director of AOGA, introduced Tom Williams as the “conceptual father of ELF.” Williams, Alaska tax counsel for BP Exploration (Alaska) and chairman of the AOGA tax committee, went to work for the state in 1973, was commissioner of Revenue from 1979 to 1982, and has been with BP since 1987.
Both the price and volume of oil are “critical for state revenue,” Williams told the committee. To hold volume at just under a million barrels a day, the state needs new production — which requires new investment — from four sources: heavy oil, in-field development, satellites and wildcat exploration.
“The question is, does Alaska’s fiscal system encourage or discourage new investments in each of these areas?” Williams asked.
There are four components to oil and gas taxes. Royalties, the state’s cut from every barrel of oil or cubic foot of gas that comes from a state oil and gas lease, are “the mainstay of Alaska’s revenue system,” said Williams. Royalties are almost half of the general fund unrestricted revenues and “by far the largest source of oil and gas revenues.”
Like production or severance tax, royalties are sensitive to oil and gas price fluctuations. Property tax is not sensitive to prices, and income tax is only moderately sensitive because it is based on a proportion of all of a company’s operations, and the range of those operations makes the income tax less sensitive to oil and gas prices, Williams said.
AOGA: ELF aimed at sustaining production
In the 1970s the Alaska Department of Revenue wanted to make sure that the state’s production tax, which comes off the top, before any operating costs are figured, did not result in production being shut in.
The ELF, Williams said, first “saw the public light of day” in a 1977 Department of Revenue report as a recommendation to prevent total production costs from overtaking the value of oil or gas as production costs rise later in the life of a field. When ELF was passed by the Legislature, Williams said, the formula proposed by the administration was changed so that the ELF was based on a presumption that 300 barrels a day was needed for a well to break even at Prudhoe Bay.
In 1989, Williams said, field size was added to ELF, with 150,000 barrels per day added to the formula. The effect of the addition, he said, was that if a field produced more than 150,000 bpd, the 1989 change moved the ELF up towards one (an ELF of one means the field would pay the full production tax rate); if a field produced less than 100,000 bpd, the formula change moved the ELF down towards zero, which moved the production tax toward zero.
AOGA: 1989 ELF change aimed at smaller fields
In 1981 the Legislature reduced the state’s corporate income tax on oil and gas and in an attempt to compensate for that tax loss, increased the production tax to 15 percent from 12.25 percent, and suspended the ELF at Prudhoe Bay until 1987. When the Prudhoe Bay suspension ended, the state’s revenue was cut by $135 million for the next fiscal year.
The Legislature, Williams noted, said the 1989 change would increase revenue, give an incentive for small fields and give an incentive for development of West Sak heavy oil.
The 1989 ELF changes reduced production tax rates for all fields except Prudhoe Bay and Kuparuk. The Legislature was told by the administration that Prudhoe Bay and Kuparuk could afford higher taxes; reduced investments as a result of the higher taxes were expected to have a small impact on total production.
The Legislature was also told that marginal fields included all the Cook Inlet fields and Milne Point, Lisburne, Endicott, Niakuk, West Sak, Point Thomson “and probably any other field that will be discovered in Alaska.”
Endicott, which then produced some 100,000 bpd, was the largest field to have its taxes reduced under the 1989 ELF change, and the Legislature was told that under the new ELF, for “marginal fields the severance tax … will either be sharply reduced or eliminated entirely.” The Legislature was also told that smaller fields would pay less tax — even with the same well productivity as larger fields.
AOGA: Williams: marginal equals small
Williams told the committee that in the 1989 discussions, “marginal was not used in a dictionary definition of marginal: small was marginal. Probably any other field that would be discovered in Alaska would be marginal, unless it was a super giant. … This is a different concept of marginal than the standard concept, the dictionary definition.
“And it’s important to understand that, because that’s what the Legislature was told, not by the industry, so much, but by the administration,” Williams said.
The Legislature was told, he said, that a small field could pay no severance tax.
And the Legislature was told there would be revenue gains, that over the next 20 years the state would be ahead by some $2.7 billion “and in fact it was.”
Williams was asked how Alaska’s system compared to other countries, and if other oil provinces had anything similar to ELF, and he said he wasn’t an expert on how other countries worked, but he thought the real question for Alaska is: “Are you getting the oil that you should be getting? Are you getting the investments that will keep oil production up?” You don’t want to ignore what the rest of the world is doing, he told legislators, “but the real question is, are you seeing the investments here that need to be made? Do you expect to see them continue in the future” to keep production at a million barrels a day.
AOGA: Volume is the issue
Brady said oil will continue to be the mainstay of Alaska’s economy and the big issues around oil are price and volume.
“We can’t do very much about price,” she said.
Volume, however, is a different thing.
In 1989 the Alaska departments of Revenue and Natural Resources said that in 15 years production would be down below 500,000 barrels per day, Brady said. That prediction was made at a time when 2.1 million bpd were moving through the pipeline.
And that prediction was based on Prudhoe Bay and Kuparuk.
“The reason that we didn’t go all the way down was because of all the investments that were made in Prudhoe Bay and Kuparuk. And all the technological breakthroughs and all the things that the companies did to make sure that didn’t happen.”
Without those investments, Brady said, production would be about 300,000 bpd today.
The ELF changes in 1989, she said, were made “to help satellites and heavy oil, but those fields did not start coming on until almost 10 years later.” And they have been developed “on the basis of the promise that there would be no tax on those fields. It took about 10 years for them to be developed and starting to produce … and now we’re starting to talk about taxing them again, after the investments have been made.”
In 1989, Brady said, the state decided to “hit the big fields hard, but everything else is going to be home free because we need that production” that will come from small fields.
Volume is the issue, she said: “If we don’t get this production, no matter what the prices are going to be, we’re going to be in a world of hurts.”
AOGA: Aggregation by ruling
State law has allowed for aggregation of fields since before Prudhoe Bay came online, Williams said. Because of complicated patterns of leases and ownership in Cook Inlet, where you have economic interdependence you can lump the various pieces together to recognize the whole operation.
Pre-1989, he said, it didn’t make much difference if you lumped fields together or not. But the 1989 ELF changes, Williams noted, rewarded smallness, and after that lumping fields together made a big tax difference, “and that’s in fact what this recent decision was about, whether the satellite fields, the six satellite fields, that are sharing facilities with the main field at Prudhoe Bay, should be lumped together with that main field.”
Williams said the Department of Revenue has adopted regulations allowing it to give rulings in advance on whether satellites will be aggregated. Companies that are proposing satellites can get rulings from the department on how a satellite will be treated, if it will have a separate ELF from the fields whose facilities it will share.
“And so those rulings have been granted. That’s how the administrative response has been to deal with the issue.”
The state is counting on new investments and new production from heavy oil, in-field development, satellites and wildcat exploration to keep production at just under a million barrels a day through 2015, Williams said.
“The question is, does Alaska’s fiscal system encourage or discourage new investments in each of these areas?”
Brady said the Alaska Oil and Gas Association agrees “right now that the state tax system is working the best a tax system can work. It’s not the perfect tax system, but it’s pretty darn close. You’re getting investments in heavy oil, in satellites, in-field and in wildcats, so we are getting investments that we need right now with this tax system.”
The state, she said, gets “a consistently high overall return, especially on the medium prices — and even at high prices you’re getting a very substantial return.”
Industry hopes, she said, “that the fiscal system will stay the way that it is and as you look at it to see whether it should stay as it is, that you keep in mind that we continue to need these four kinds of investments.”
Revenue: Investment in forecast
Dan Dickinson, director of the Alaska Department of Revenue’s Tax Division, told the committee Feb. 3 that Revenue made its aggregation decision based on “what we thought was the appropriate way to tax those fields.”
And, he noted, Jim Bowles, president of ConocoPhillips Alaska, “sent a letter to the governor that identified the fact that he’d asked us for rulings on Alpine — the satellites at Alpine — that ConocoPhillips hopes to bring on over the next several years.”
The company based its economics on separate ELF treatment, Dickinson said, and told the state that if the Alpine satellites don’t get separate ELF treatment, those economics will have to be revisited.
And how likely is it ELF treatment will mean less investment in Alaska? Dickinson asked.
There are several factors, he said, one of which is that “most of these companies are capital constrained; they’re going to take capital and they’re going to invest it where they think they get the best return over time. And the best return isn’t necessarily again a single dimension, but they look at the upsides, the downsides, they … have a portfolio.” Sometimes, he told the committee, “I don’t understand” investment decisions the companies make and sometimes people in a company’s Alaska office don’t understand why headquarters made a decision the way they did.
Revenue: ELF results not what expected
Dickinson said he didn’t think the people who redesigned ELF in 1989 “got what they expected.”
“A lot of the focus (in 1989) was on standalone facilities, production facilities … folks went out and made investments and created their own production facilities,” he said.
“And that’s I think what people were focused on because they talked about the cost of the production facilities and you have all those costs associated with that production.”
But, he said, what has happened over time is that new production has been brought on that uses existing facilities and “that’s not what was contemplated, that kind of development.”
Revenue: Many fields have rulings
Committee Chair Vic Kohring, R-Wasilla, asked Dickinson if other fields with satellites could be hurt by aggregation.
Dickinson said Revenue’s regulations provide a process for getting “an advance letter ruling, just like they would from the IRS, that says we will not aggregate this field… essentially giving them some certainty” about production taxes.
Those letters have been issued, he said, and cover a good deal of production at the Milne Point and Kuparuk River fields. The division was careful, he said, not to overturn any of those existing rulings.
There are issues of taxpayer confidentiality, Dickinson said, and situations differ, but “we’ll have to figure out some way of getting that language out to everyone else as we make policy for adjudication…”
The purpose behind the division’s regulation, he said, “is to allow folks to understand what their taxes are going to be and I think another thing that it might be important for us to do is to be more precise when we grant these letters: to say, here’s the situation, here’s the tax situation.”
Revenue: Infrastructure differences
Committee Vice Chair Ralph Samuels, R-Anchorage, asked Dickinson about recent decisions at Kuparuk, and Dickinson said there are a series of decisions including West Sak, Tabasco, Tarn and Meltwater. Why, Samuels asked, did decisions go in favor of a separate ELF at Kuparuk, and against it at Prudhoe?
Dickinson said Tarn and Meltwater are examples of the difference: Tarn is some 10 miles from Kuparuk facilities, he said, and was developed from new drill sites. Meltwater is an additional six or seven miles out from Tarn, again on a new drill site.
“If you go to the west end of Prudhoe Bay,” where a lot of the Prudhoe satellites are, you find a drill site and “each well is going down to a different — at least before the aggregation decision — what might be a different field.”
If you focus on “what’s on the surface, on the economics of putting together these systems, I think you’ll see that that’s a very different situation,” Dickinson said.
Another difference between Kuparuk and Prudhoe, he said, is that “in Kuparuk there is a slight difference of ownership … between the satellites and the mother field” so satellite owners sending production to the main field have to deal with the different ownerships.
At Prudhoe, until 2000, “the satellites were owned in very different percentages than the mother field and that, I think, impeded a lot of the development.” The equity re-determination at Prudhoe resulted in everybody owning the same percentage of everything — the field and satellites, the roads, the production facility. “So that somebody didn’t say well, gee, if you put your production in this production facility on that road and you use that electrical line, I want to get reimbursed each time.”
Dickinson said the regulations clearly contemplate that decisions on satellites “would be issued beforehand, in other words, if it’s going to be a factor in the decision to invest, then you have the opportunity to get it before and to insist on getting the letter before you make your investment.”
Oil and Gas: Economies of scale
Bill Van Dyke, Department of Natural Resources Division of Oil and Gas petroleum manager, told the committee that at Prudhoe, the main field “supported the initial development” and the smaller pools are “like icing on the cake.”
There are multiple shared facilities at Prudhoe Bay, Van Dyke said, and for the satellite pools “they didn’t go out and build all new facilities to produce pools. No, they’re using the existing facilities. And that’s good. Because that means obviously development costs are a lot lower, because you’re just using what’s already there.”
The satellites at Prudhoe have been known, because the companies drilled through them early on, Van Dyke said, but because of disparate ownership development was difficult until the common equity agreement was reached in 2000.
There are a few facilities at Prudhoe that the common equity agreement does not cover, but those are in the minority. But for the most part, he said, “everybody owns the same interest in everything, and it really changed the way business is done in Prudhoe Bay. I don’t think it’s any coincidence that starting in the year 2000 after this common equity agreement that you could see the satellite production blossom at Prudhoe Bay.” The satellites are producing close to 50,000 bpd, he said. “It’s like finding a huge new oil field on the North Slope.”
Oil & Gas: Other opportunities
There are other investment opportunities on the North Slope, Van Dyke said, but companies will have to be able to make a profit in order to develop them. Companies look at factors such as the flow rate from wells, location in relation to infrastructure and access to that infrastructure, he said.
There are also some big fields that have been discovered but haven’t been developed because they’re offshore the Arctic National Wildlife Refuge “out in relatively deep water,” Van Dyke said, on the federal outer continental shelf.
Because they are remote, “they’re going to be very expensive to develop and so today they just sit there.”
The offshore wells, like Kuvlum and Hammerhead, even if the federal government decided to charge zero royalty and zero severance tax “those fields are probably uneconomic to develop today. So there’s not a whole lot government can do other than pay someone to produce them,” he said.
An onshore example of an uneconomic accumulation is the viscous Ugnu formation at Kuparuk, Prudhoe Bay and Milne Point. The accumulation is known because companies drill through it, but it sits there because it’s not economic to develop today.
There is a continuum of projects on the North Slope, he said, “they’ll always be projects that are very much uneconomic; they’ll be some in the middle that are maybe right on the edge; and they’ll be some that are highly economic. And that’s true today. That was true 20 years ago. And it will be true probably 20 years out into the future.”
Van Dyke said companies make decisions to develop on a case by case basis, looking at factors such as cash flow expected from a development, how much risk is involved and what the company’s forecast is for oil prices. A project that’s acceptable to one company might not be to another, he said. “They all forecast price differently. And they all evaluate the risks differently, both the geologic risk and the commercial risk and … the chances of changes in government take down the road.”
