|
Finance discussing committee substitute Resources CS for SB 21 has been tweaked; focus remains increase in production; as with original bill, immediate revenues down Kristen Nelson Petroleum News
More revenue now or the potential of more production and more revenue in the future?
That’s the tradeoff facing legislators as they discuss changes in Alaska’s oil and gas production tax.
Senate Finance’s committee substitute for Senate Bill 21, the governor’s oil tax changes, retains most of the features of the Resources CS, while turning a few knobs a little differently, Finance Co-Chair Kevin Meyer said March 12 when the Finance CS was introduced.
The base tax rate, set at 35 percent in the Resources CS, was dropped to 30 percent in the Finance version, with the offsetting $5 per taxable barrel allowance retained. The Finance CS drops the gross revenue exclusion from 30 percent to 20 percent, corresponding to the drop in the base rate, and expands definitions of applicable new oil to include oil from legacy fields which has not been in production, an area of the CS where work continues with the departments of Natural Resources, Revenue and Law. Application of the GRE is also limited to the first 10 years of production under the Finance CS.
The net operating loss carry forward can be monetized under the Finance CS, but only in exchange for investment in the state.
As the committee’s vice chair, Anna Fairclough, put it in discussing monetizing the NOL — it’s Alaska’s money and Alaskans should benefit.
The Finance CS also adds a provision reducing what industry has called a punitive interest rate for delinquent payments, currently the fed rate plus 5 percent or 11 percent, whichever is greater, compounded quarterly, to the lesser of the fed rate plus 3 percent or 11 percent, compounded quarterly.
As with the governor’s bill as introduced, progressivity is eliminated and qualified capital credits are eliminated.
Government take leveled The combined government take — all applicable state and federal taxes — which ranges from 69 percent to 77 percent at oil prices from $80 to $140 per barrel for new entrants currently (under ACES, Alaska’s Clear and Equitable Share) drops to 60 percent across that price range under the Finance CS. The government take for existing producers, which ranges from 66 percent to 75 percent from $80 to $140 per barrel under ACES, drops to an even 63 percent under the Finance CS.
Under the bill as originally proposed, those rates were 55 to 58 percent across those price ranges for new entrants, and a range from 56 percent to 60 percent under the Resources CS; and 62 to 64 percent for existing producers under the original bill, compared to 64 to 65 percent under the Resources CS.
The manufacturing tax credit added in the Resources CS doesn’t change under the Finance CS, nor do exploration areas and extension of the small producer credit to 2022 is retained.
Meyer complemented the work the Resources Committee did on the bill.
The goal of the Finance CS was to be competitive, to get more oil in the pipeline, he said, noting that the GRE and $5 per barrel allowance are only applicable when oil is produced.
Revenue consequences The divergence in committee views on the proposal were captured in comments from two of the members.
If these changes resulted in no more production than under ACES the fiscal impact — the reduction to state revenues — would vary from $1 billion to $1.3 billion in fiscal 2014, to as much as $1.4 billion to $1.8 billion in FY 2019.
Sen. Lyman Hoffman, D-Bethel, called those numbers “truly staggering” and said that moving “this much cash across the table” would have detrimental effects on the state’s operating budget and called any drilling resulting from the change “hypothetical.”
Finance Co-Chair Pete Kelly, R-Fairbanks, asked whether it was the role of legislators to protect the interests of government or the interests of the people of Alaska. He said the interests of Alaskans include jobs and the ability to have a future in the state.
Too much is already being spent on government, Kelly said.
The state has too much government because it probably took too much from investors and now has to look at giving some back so they’ll invest in the state, he said, urging that the proposed changes be measured not against what government wants but against what people want.
Competitiveness issue Consultant Barry Pulliam of Econ One, for the administration, and Janak Mayer of PFC Energy and independent consultant Roger Marks, both under contract to Legislative Budget and Audit, all said the changes would make the state’s fiscal system more competitive.
Pulliam said that compared to ACES all iterations of SB 21 made the state more competitive.
The net present value for a $20 a barrel capex development gets progressively better for the investor from SB 21 through the Resources CS to the Finance CS, Pulliam said. He said government take numbers from the Econ One model run for the administration were close to those of the Legislature’s consultants.
He also said that under the CS numbers for new entrants are almost identical to those for incumbents, unlike under ACES where economics weren’t as good for new participants. The small difference between incumbents and new producers under the Finance CS, with the new producer slightly better off, are driven by the small producer credit, Pulliam said.
Overall the changes put the new participant on a level playing field with the incumbent, he said.
Pulliam discussed the 10-year cutoff on the GRE, telling legislators it would raise the tax on new production just as wells become less economic, and could result in early shutdown. He said reducing the 20 percent GRE to 15 percent and allowing it to run to the end of well life would have about the same economic value for the producer.
Government take competitiveness analysis by PFC’s Mayer showed the state more competitive at modeled price ranges from $80 a barrel to $140 a barrel, with the 60 percent government take for a new entrant falling between take rates for Texas and Australia under the Finance CS, and between Louisiana and Egypt at about 62 percent for incumbents.
Marks addressed the revenue implications of reducing taxes to make the state more competitive.
Alaska got where it’s at today, he said, as the result of a large tax increase in 2007.
Marks said North Slope infrastructure — which he valued at some $60 billion including the trans-Alaska oil pipeline — couldn’t go anywhere; he called it “captive investment” and compared that to Alberta which increased its royalty at about the same time, but without “captive investment.” Drillers there simply moved their rigs, he said; production in Alberta fell; royalties were subsequently reduced and production came back.
On the North Slope, however, production continued and the state made a lot of money.
But, with lots of opportunities to produce oil around the world, corporations chose to invest their finite capital where they could make more money and Marks said that between 2007 and now there was a worldwide increase of about 50 percent in upstream capital, while in Alaska capital has stayed about the same as when oil prices were $60 a barrel.
And production dropped, he said, from some 850,000 barrels per day to 550,000 bpd.
He said that in taking the state from noncompetitive to competitive you can’t compare revenues using the same number of barrels, because with a competitive regime there will be more barrels produced. But, he said, there will be lead time before there is more production.
Marks said he looked at increasing production in 10,000-bpd increments to see what it would take to make more money over a 20-year period under the Finance CS. The crossover point, he said, is 70,000 bpd.
He noted that’s not a lot — production dropped 300,000 bpd over six years and there are about 4 billion barrels of proved reserves on the North Slope, so producing 5 percent of that would be 70,000 bpd.
The tradeoff, he said, is a certain amount of ACES revenue now versus more-or-less non-ACES revenue down the road.
| 