Legislature heads back to oil tax fray

Alaska House, Senate leadership put production in top three issues for session; governor expected to offer new bill in January

Kristen Nelson

Petroleum News

Returning Alaska House Speaker Mike Chenault, R-Nikiski, and in-coming Senate President Charlie Huggins, R-Mat-Su, told the Resource Development Council Jan. 3 that budgets, the oil tax and an in-state gas pipeline would be the top three issues when the Legislature gavels in Jan. 15.

The last Legislature struggled in both its 2011 and 2012 sessions with the oil production tax and with revisions to the state’s in-state gas pipeline statute, failing in the end to agree on changes to either.

The House passed a version of the oil tax bill introduced by Gov. Sean Parnell in 2011, but it failed to gain any traction in the Senate, which studied the issue and developed its own bills in the 2012 session, the first of which failed to reach the floor of the Senate and the second of which passed the Senate at the very end of the session, but was not considered by the House.

The 2010 federal census and redistricting produced a different Legislature in the 2012 elections.

This year the Senate majority is dominated by Republicans, 13 of the 20 members with two Democrats caucusing with the Republicans, whereas in the last Legislature the 16-member Senate Bipartisan Working Group consisted of 10 Democrats and six Republicans, with four senators in the Republican minority. Three of the previous Legislature’s minority Republicans are now in leadership positions in the Senate: Huggins as president, John Coghill as majority leader and Cathy Giessel as the Resources Committee chair.

The House, as in the previous Legislature, has a Republican majority, with rural Democrats caucusing with the Republicans.

Revenue Commissioner Bryan Butcher said in early December when the department rolled out its fall forecast that the department was working with the Department of Law on what would go into a tax change proposal.

This time around, he said, the department has had the time and the consultants to dig through the tax issues “and really try to come up with as well-rounded an approach as we possibly can.”

Butcher said the administration plans to submit a tax bill to the Legislature in January.

2011-12

The governor called the Legislature into special session immediately after it adjourned to consider oil taxes and the in-state gas line; the in-state gas line again stalled in the Senate.

The governor introduced a special session oil tax bill April 18, the first day of the session, and withdrew it April 25, citing lack of support in the Senate.

Parnell called the position of some in the Senate “hard-line,” and said “the Senate appears incapable of passing comprehensive oil tax reform.”

The governor’s special session bill combined the new-field tax allowance proposal the Senate developed at the end of the regular session (a 30 percent 10-year allowance on both the base tax and progressivity) with a similar approach for existing fields, a 40 percent deduction on progressivity only.

House Bill 110, passed by the House in 2011 and never taken up in the Senate, provided across the board tax reductions for all North Slope oil production. Senators said in 2011 that they needed more information before considering changes in the state’s oil production taxes, changed in 2006 with the Petroleum Profits Tax and again in 2007 with ACES, Alaska’s Clear and Equitable Share. The progressivity rates in ACES at current oil prices have been cited by industry as a disincentive to investment in the state, because the state takes progressively more in taxes as oil prices rise. Crude oil prices have risen above what was projected when ACES was passed.

Additional oil

Some members of the Senate Bipartisan Working Group said they believed ACES was working just fine.

Others in the majority, including Senate Finance co-Chair Bert Stedman, R-Sitka, said progressivity at high oil prices was a concern, noting that when work was done on ACES in 2007 the focus was on oil prices in a much lower range than they were in 2011-12.

As for what should be changed, legislators were told by consultant Pedro van Meurs in tax discussions prior to the 2012 session that total government take (state and federal taxes) for existing fields was within the world-wide norm at 70 to 75 percent.

North Slope production is on the decline and Parnell set a goal to increase throughput on the trans-Alaska oil pipeline to 1 million barrels per day (from less than 600,000 bpd).

More oil moving through the line would require an increase in investment and in the 2012 regular session senators focused on finding a way to incentivize additional oil production without reducing taxes on existing production.

After weeks of work, first in Senate Resources and then in Senate Finance, senators produced a comprehensive oil tax bill, Senate Bill 192, but that bill wasn’t able to garner enough support in the Senate Bipartisan Working Group to reach the Senate floor for a vote.

Following that, Senate Finance proposed a change only to taxes on oil from new fields, attaching that to a House bill providing credits and production tax breaks for unexplored or underexplored basins close to communities in need of more reasonably priced energy supplies.

The House Rules Committee moved the so-called “middle earth” provisions for unexplored basins to another bill, and the Senate’s new oil tax reduction was never considered in the House.

Poorly received in Senate

Senate Resources members objected to the fact that the new bill, Senate Bill 3001, had about the same overall tax reduction as the governor’s original 2011 proposal, HB 110.

Butcher said that the level of cut in oil taxes was close to that in HB 110, and said that was the level of tax cut the administration believed necessary to make a tax change “meaningful” enough to attract the new investment needed to increase production.

The House Resources and House Energy committees considered the bill and heard what the Senate had heard in the regular session from PFC Energy’s Janak Mayer, that while cutting taxes across the board is the simplest way to incentivize investment, that method moves a lot of cash across the table unnecessarily, because a lot of the work the companies do in legacy fields is economic.

New field development is particularly challenged under the ACES tax regime, Mayer said, but incentivizing specific new oil developments, while putting money where it will do the most good in inducing more production, is more challenging than across-the-board cuts, both administratively and for industry.

The House committees had gotten to the point of taking testimony from industry April 25 and were preparing to hear public testimony April 26 when the governor pulled the bill.

Industry representatives, who had not yet testified in the Senate, told the House committees that House Bill 3001, the governor’s special session tax proposal, made significant enough changes in the tax rate that it would result in more investment.

Proposed versus passed

Bert Stedman, R-Sitka, co-chair of Senate Finance, said the committee would zero in on the progressivity aspect of ACES.

What follows is a reprint of a portion of an article from the April 1, 2012, issue of Petroleum News.

Then and now

An October 2007 presentation to legislators by consulting firm EconOne included a slide entitled: “ACES Preserves Investment Climate.”

Stedman said March 22 that he asked PFC Energy, which is currently consulting for the Legislature on oil tax issues, to take a look at some of the old analysis and do comparative updates. He said the cost structure and the price range are different today than they were a few years ago, and wanted the committee to be able to see the differences.

Janak Mayer, manager in the upstream and gas practice of PFC Energy and project manager for the firm’s work with the Alaska Legislature, said a lot of the analysis done during ACES came to the conclusion that ACES preserved the investment climate.

But Mayer said there are a lot of voices today saying “ACES has not preserved the investment climate or at least has not, in the current day, enabled an investment climate as significant as might be ideal.”

He said that to understand those differences it was important to look at the analysis that was performed during the ACES debate, to look at what has changed since then, “and why therefore might we draw some different conclusions looking at this data pool today as opposed to the ones that were drawn back in 2007.”

The 2007 analysis looked at seven hypothetical field developments with “a stylized production profile and particular capital and operating costs,” Mayer said. The basic differences between 2007 and 2012 hold true across all the examples, he said, noting the sample field he selected from the 2007 analysis was “not dissimilar in its characteristics to the sort of hypothetical new development” that PFC Energy has used in some of its analysis.

ACES as proposed

Mayer said the second thing “is that cost assumptions are much lower than any recent experience would suggest” in the 2007 analysis, which was based on $10 a barrel capital expenditures and $9 a barrel operating expenditures for a hypothetical new development, while the analysis PFC Energy presented for a similar development was based on $17 a barrel for both capex and opex.

Then there is the price of oil.

Analysis in 2007 was done on a minimum of $20 a barrel and a maximum of $100 a barrel “with a focus in particular on what the economics looked like at a $40 stress-test price and a $60 base case price for crude oil,” he said.

The production profile for the hypothetical new development in the 2007 analysis was one that would maximize returns for the producer, with “quite a high peak production rate and a relatively high decline rate, meaning that most production value occurs in the first 10 years,” Mayer said, estimating that for a 60 million barrel field the peak would probably be 20,000 barrels per day with a rapid decline. He said a peak at some 11,000 or 12,000 bpd and a slower decline “is at least a little more consistent with some of what we’ve actually seen in terms of historical production data from North Slope developments” and particularly from new fields in that size range — Oooguruk and Nikaitchuq.

Benchmarking data

Where the 2007 benchmarking put Alaska under ACES as proposed at the high end of the median, the PFC Energy benchmarking at $100 a barrel put Alaska just under Norway, which has the highest government take of any developed country, and above Norway at the $140 a barrel level, Mayer said.

Looking at the hypothetical new development which was attractive under the 2007 assumptions, Mayer said that as the 2007 assumptions are changed to reflect 2012 prices and costs, with ACES as enacted rather than as proposed, “this goes from being an attractive field development under the previous cost assumptions to being suddenly one that really is very marginal.”

The flatter production curve (lower peak production, longer field life), gives the project “strongly negative value to a company” at the $40 to $60 a barrel range, with a breakeven point probably in the $80 to $90 a barrel range and one which only starts to have any positive economic value at $100 a barrel.

Stedman summed up the presentation by noting that by the time this proposed new development is taken “from the proposed ACES to the enacted ACES and then adjust it for cost and price, we have a substantial different outcome” than that in the 2007 analysis.

—Kristen Nelson