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First bills out for new Legislature Extension of stranded gas act, royalty reduction provisions among bills filed for 23rd Alaska Legislature, which convenes Jan. 21 in Juneau Kristen Nelson PNA Editor-in-Chief
A number of oil and gas related bills have been filed for consideration in the Alaska House in the 23rd Legislature, which convenes Jan. 21, including a proposal for reduction in the amount of oil and gas monies going into the permanent fund, an amendment to the Alaska Stranded Gas Development Act, an amendment to the state’s negotiated regulation making law and amendments to the state’s royalty reduction statute.
House Bill 11, by Rep. Norm Rokeberg, R-Anchorage, would reduce required deposits of oil and gas monies into the permanent fund from the 50 percent now required by statute to the 25 percent required by the state constitution.
HB 16, by Rep. Hugh Fate, R-Fairbanks, would amend the Alaska Stranded Gas Development Act, repealing the deadline for applications under the program and expanding the act to include gas sold by an Alaska Highway-route pipeline. The original act, passed in 1998, authorized the state to restructure certain taxes and royalty requirements to facilitate the development of otherwise non-economic gas reserves, but specified a liquefied natural gas project. HB 16 expands the definition of projects what would qualify under the act.
HB 34, by Rep. James Holm, R-Fairbanks, would repeal provisions of existing law which terminate statutory authority for negotiated regulation making in the state on July 1.
Amendments to royalty reductions HB 28, by Rep. Vic Kohring, R-Wasilla, and Rep. Rokeberg, tackles one of the ways the state can provide incentives to promote oil and gas development by amending existing law which allows for adjustment of royalties from oil and gas production “to encourage otherwise uneconomic production of oil and gas.”
Royalty reduction is one of nine state incentives Division of Oil and Gas Director Mark Myers described for the House Special Committee on Oil and Gas last year.
Many of the problems with royalty reduction which Myers detailed are addressed in HB 28.
“Royalty reduction is a very, very complex issue,” Myers told the committee in April.
The program allows the commissioner of the Department of Natural Resources “to modify royalty terms for production that wouldn’t otherwise be economically feasible,” Myers said.
The law covers fields not yet in production but which have been delineated; fields where production and economics are declining and the state provides an incentive so that the field won’t be shut in; and fields with shut-in production.
The incentive in place has a royalty floor of 5 percent for fields not yet in production and a royalty floor of 3 percent for fields in production or fields that are shut-in, Myers said.
When the Legislature passed the current law in 1995, “they put some clear standards into the royalty reduction,” he said. Evidence must be “clear and convincing” that “relief is in the state’s best interest.” And if commodity prices, technology or production profiles change after relief has been granted, and the field once again becomes economic without the relief, then “the state is able to recover the cost”
Myers said the state requires a significant amount of economic data to do the analysis, including production forecast, data on costs, etc. and because of changing oil prices, the analysis of what royalty reduction would help the economics is very difficult. “There’s really no range of outcomes where the royalty reduction actually changes the entire economics of the field,” he said.
This is partly due to the impact of changing oil prices compared to royalty changes: a royalty reduction from 12.5 percent to 5 percent is “equivalent to a dollar per barrel price of oil” and the large fluctuations in the price of oil can “often have a bigger … impact on the field than would a royalty reduction.”
Past experience In 1990, under a previous royalty reduction program, Conoco applied for a royalty reduction at Milne Point, Myers said, and after an analysis the state denied the application.
He said that one of the challenges of the royalty reduction program is individual company economics.
“Conoco obviously had different economics, not owning part of TAPS, not owning the tanker system, than did other companies.”
Conoco was producing some 20,000 barrels a day from Milne Point when it applied for royalty relief. BP later acquired the field and has increased production to some 49,000 barrels a day, Myers said.
When the state analyzed Conoco’s application it found the proposal would have cost the state $120 million over the life of the field. “Conoco claimed it was absolutely necessary. BP came in and actually increased development and enhanced the field and increased production without it,” Myers said.
Under the current law the state evaluated an application from Unocal for royalty relief for 10 platforms in Cook Inlet. The state analyzed the application, Myers said, and developed a proposal to grant royalty relief for some of the 10 platforms that were closer to their economic limit, while denying relief for other platforms.
Unocal decided, he said, not to pursue royalty relief under the state’s proposal.
The 10 platforms are producing today, he said, “at pretty similar rates to what they were producing in ‘97.” In November, however, Unocal announced plans to shut in two of its Cook Inlet platforms.
Myers said Phillips Petroleum Co. also applied for royalty reduction, this for the Tyonek deep oil formation which underlies the North Cook Inlet gas field. An initial review of the project by the state found project economics uncertain because of uncertainties both in capital costs and in the size of the accumulation. Phillips did not pursue the application, he said, “because I believe at that point they realized the royalty reduction wouldn’t swing whether or not they’d have developed it or not.”
That field, he noted, remains undeveloped.
Proposed amendments The amendments proposed in HB 28 expand royalty relief from applying only to entire oil or gas fields or pools to applying also to portions of fields or pools and remove a 1995-2015 window for the royalty reductions.
The bill replaces several convoluted paragraphs describing requirements for evaluation of applications in the 1995 law with one statement: “the commissioner shall provide for an increase or decrease or other modification of the state’s royalty share by a sliding scale royalty or other mechanism that shall be based on a change in the price of oil or gas and may also be based on other relevant factors such as a change in production rate, projected ultimate recovery, development costs and operating costs.”
The 1995 law set a floor of 5 percent for a royalty reduction. HB 28 provides that royalty reduction cannot exceed 75 percent of the royalty originally specified in the lease for a field not under production, and cannot exceed 90 percent of the royalty to extend the economic life of a field or to reestablish production of shut-in oil and gas.
There are also modifications in data required from the applicant and the bill provides that the data will be kept confidential. The statute now in effect allows the commissioner to make the applicant’s data available to the Legislature and the legislative auditor.
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