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Vol. 18, No. 5 Week of February 03, 2013
Providing coverage of Alaska and northern Canada's oil and gas industry

Competitiveness issue

Econ One: Parnell’s bill would put Alaska back in running, benefit new players

Kristen Nelson

Petroleum News

State revenues would drop under oil fiscal regime changes proposed by Alaska Gov. Sean Parnell, but investment in oil projects in the state would compare more favorably to opportunities available in similar areas in the Lower 48 and abroad.

And new participants, who fare worse than incumbents under the present tax system, would fare better than incumbents under the proposal.

Economist Barry Pulliam of Econ One Research told the Senate Special Committee on TAPS Throughput in a Jan. 24 background briefing on the tax proposal that the biggest changes are elimination of progressivity, capital credits and the state purchase of losses under the current production tax system, ACES, Alaska’s Clear and Equitable Share.

The governor’s proposal also contains a gross revenue exclusion to provide an incentive for development of new oil by eliminating 20 percent of new oil from production taxes. The requirement that carry forward losses may only be applied against production eliminates upfront payouts from the state and focuses on the governor’s goal of increasing production.

Investment elsewhere

Why make a change?

High oil prices have meant increased investment elsewhere, but not in Alaska, Pulliam said.

Investment matters because less than half of the oil considered recoverable from the North Slope has been produced to date.

With production to date of 16.2 billion barrels, federal government estimates put remaining oil at 5.6 billion barrels of discovered conventional resources; 19.2 billion barrels of undiscovered conventional resources; 9.9 billion barrels in the Arctic National Wildlife Reserve; and 5.5 billion barrels of unconventional resources.

That’s a lot of oil, Pulliam said, but “it’s not low-hanging fruit.”

It’s challenging, it’s offshore, and what is onshore “is higher cost and going to be more challenging to get at than the oil we’ve produced to date.”

Impact of ACES

Alaska oil production was taxed under a gross system referred to as ELF for economic limit factor until the Petroleum Profits Tax, PPT, was introduced in 2006.

PPT had a 22.5 percent base tax rate, with progressivity increasing the rate at 0.2 percent per $1 over $40 net, a 20 percent capital credit and a maximum rate of 50 percent.

PPT was amended in 2007 with ACES, which has a 25 percent base net tax rate and progressivity increasing the rate at 0.4 percent per $1 over $30 net, 0.1 percent per $1 over $92.50 net and a maximum rate of 75 percent.

State revenues have grown dramatically under ACES: about $20 billion in additional revenues since it took effect, compared to projected revenues under the old gross system.

Pulliam showed figures for the period under ACES comparing revenues with those projected under PPT and ELF: ACES $26.4 billion; PPT $17.2 billion; the old gross system $6.3 billion.

Capital spending impact

But there has also been an investment impact.

Pulliam said North Slope capital spending came down in the mid-2000s, “started to rise in 2005 as oil prices rose, went up again in ’06 and it’s come up a little bit since then, but has been relatively flat over the last four or five years” while “capital spending elsewhere has really exploded over that time period.”

Of total spending, about 70 percent was by large producers and the remaining 30 percent by all others.

Pulliam also showed capital spending broken out by mature units and new units — those not in production in 2003.

“The increase in the spending has been for those new units,” he said, while “... spending at the mature units has been relatively flat.”

Drilling, exploration and development, has generally been declining. While some 200 wells a year were drilled in the early 2000s, “we’ve dropped off: The most recent year is about 150 wells per year,” with most of that drilling by majors.


Econ One benchmarked Alaska activity against OECD, Organization for Economic Cooperation and Development, areas that share many characteristics with the North Slope: similar political and legal structure; similar risk; significant prospectivity, but with much of the “low-hanging” fruit already produced; development of remaining resources largely high cost; and resources developed in large part by the private sector.

Econ One compared the areas — the North Sea, key producing areas in the U.S., Canada and Australia — by production, capital spending, employment and drilling by indexing values based on 2002, allowing comparisons across different production levels.

Production in Alaska has dropped about 50 percent over those 10 years, a decline Pulliam said is mirrored in the North Sea, “an area that was discovered and developed about the same time as Alaska,” and shares with Alaska characteristics of being an expensive and difficult area to do business.

He noted the United Kingdom has recently modified its tax structure “to try and attract more investment and get more production” with the result of “announcements of multiple project sanctioning just recently.”

Areas in the Lower 48 — Gulf of Mexico outer continental shelf, Texas, California, North Dakota Bakken — all show flattening or increasing production, as does the Lower 48 overall. While California hasn’t had an increase in production, there is a “lessening of the decline” as more oil has been produced from mature fields, he said.

A capital spending comparison, also indexed, between Alaska, U.S. and worldwide (Alaska based on North Slope tax return information; U.S. based on top 50 public companies; worldwide based on top 75 companies) shows that while U.S. and worldwide exploration and development spending tended to track oil prices, rising when prices rose in 2006 and 2007, and rising again beginning in 2010, it remained “relatively flat in Alaska,” Pulliam said.


Econ One looked at a 50 million barrel development, evaluating net present value — the value of the stream of payments expected over time, based on an investment made today, discounted at 12 percent. It looked at internal rate of return, basically a hurdle rate companies used to compare projects; it looked at cash margins, the cash the project is expected to generate; and it looked at net present value to the state of revenues from the project, also at a 12 percent discount rate.

One factor making projects in the Eagle Ford in Texas and the Bakken in North Dakota attractive is that “a large amount of the production comes very quickly, whereas the more traditional wells play out over a longer time period.”

In the Eagle Ford, 40 percent of reserves are produced in the first year; in the Bakken it’s 30 percent in the first year, Pulliam said. Alaska conventional oil projects produce a little less than 5 percent in the first year, peak at a production rate of about 10 percent and then decline.

System comparison

Under Alaska’s old gross tax system, a combination of royalty and tax was somewhere in the 20 percent range, Pulliam said. By comparison, royalty and tax in the Lower 48 is about 30 percent, particularly on private lands.

Because those are gross systems, net present value, NPV, to the producer continues to rise as oil prices rise.

Looking at a hypothetical 50 million barrel field, under ACES the crossover point for NPV — less to the producer — for a new participant is about $80 a barrel; for an incumbent about $100 a barrel. NPVs are higher in the lower price range because of the progressivity built into ACES, Pulliam said.

The cash margins under ACES, while substantially reduced from the gross system, are slightly better for new participants, because Alaska provides “a small producer credit so that gives them a slightly higher margin.”

For incumbents, the cash margin is relatively flat under ACES, because while Alaska provides “a lot of incentive upfront, we take a lot, particularly as prices go up ... with the progressivity,” Pulliam said.

Government take is higher for new participants than for incumbents because the new participant can’t shelter income before production begins, but once it begins production is subject to the same progressive tax rate, “so it doesn’t get the bump at the front end but it’s got to pay the price as production starts,” Pulliam said.

The “bump” is the result of two things: When you invest you get a credit, “but the other thing that happens is additional spending reduces your tax rate; it reduces it on all of your production,” and because of progressivity as prices go higher, “the level of that reduction gets higher and higher.”

The governor’s proposal

The governor’s proposed changes — elimination of progressivity and capital credits and the state’s purchase of credits and losses and establishment of a 20 percent gross revenue exclusion for new oil — provides a balance, Pulliam said, by reducing tax rates at high prices, balanced with elimination of credits.

“The state does continue to receive, at any price level, the highest percentage of the revenue from the oil production,” he said.

Pulliam also said that because it remains a net system, the proposed changes maintain “the alignment between the state take and the producers’ incentives and their operations.”

He said he thinks the proposed system provides “a good incentive for new development without taxing the state treasury along the way and having to fund that new development,” while the gross revenue exclusion “offers the lower effective tax rate for new development.”

The proposal also “sends a very positive message to potential investors,” he said.

While the new proposal is “relatively neutral” it is somewhat regressive (lower percentage of take at higher prices) because the state’s royalty is taken on the gross.

Pulliam said the goal “was to have a government take that was competitive with what is available elsewhere and that range is generally viewed ... if you look at these other areas that are having success ... somewhere in that 60 to 65 percent range.” He said that “you get too much above that range and the investment measures don’t fare as well.”

The 50 million barrel project

For the 50 million barrel project Econ One used as an example, the incumbent has larger total cash flows, $1.544 billion, than under ACES ($1.120 billion), but the NPV at a 12 percent discount is similar: $319 million under the governor’s proposal compared to $322 million under ACES. Pulliam said that is because the state won’t be subsidizing initial work, so the incumbent will have a larger cash outlay at the beginning.

On the state side, there is a big difference in total revenues, but almost none in NPV, again because the state isn’t subsidizing development: $1.612 billion under the governor’s proposal, compared to $2.264 billion under ACES, but with NPV of $449 million under the governor’s proposal compared to $444 million under ACES.

The state’s cash flows are going to be lower, “but the NPV of those cash flows is going to be about the same. So we won’t be paying out large sums up front, but we’ll be collecting less — at least at this price level ($100 per barrel West Coast ANS) on an ongoing basis.”

Pulliam said the governor’s proposed tax changes would benefit new participants who are “disadvantaged in many respects right now, because they don’t have ... the ability to buy down their tax rate,” and so can’t have the same internal rate of return or NPV numbers an incumbent can have.

Under the governor’s proposal the new participant would have a cash flow of $1.603 billion, compared to $998 million under ACES, and an NPV of $318 million compared to $203 million under ACES.

The state would have total revenues from a new participant under the proposal of $1.521 billion compared to $2.452 billion under ACES, and an NPV of $451 million under the proposal compared to $627 million under ACES.

Overall, Pulliam said, the governor’s proposal — both for NPV and for cash flow — would put the state right “in the game with what’s available in the Lower 48.”

“It’s a significant improvement from where we’ve been,” he said.

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