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SB 21 could surpass ACES revenues If production expanded — with new fields, more drill rigs, more pads at legacy fields — state could be ahead by FY ’16 at $100 oil Kristen Nelson Petroleum News
A big dispute in the battle over passage of Gov. Sean Parnell’s oil tax change, Senate Bill 21, was how much the drop in oil taxes — particularly the elimination of progressivity — would cost the state in oil tax revenue.
The fiscal note provided by the Alaska Department of Revenue for the bill as passed by the Legislature provides estimates, although those estimates are based on production levels currently forecast by the department.
At current production forecasts, the state loses revenue under SB 21 into the foreseeable future, starting with a drop of $275 million in fiscal year 2014 at $100 oil, peaking at $475 million in FY 2017, and flattening out at $450 million in FY 2019.
But Revenue also laid out scenarios showing what would happen under SB 21 with additional production.
One new field In scenario A, additional production comes from a 50 million barrel field developed by a new entrant. This would be a field outside an existing unit and would be subject to the 30 percent gross revenue exclusion, with first oil in 2017 and peak production of 10,000 barrels per day in 2019. Total development cost for the new field would be $500 million.
At $100 oil, state revenue losses are the same in FY 2014 through FY 2018, but the loss in FY 2019 drops from $450 million less than ACES to $425 million less than ACES as production from this hypothetical new field comes online.
Four rigs in legacy fields In scenario B, Revenue projects the addition of four new rigs in legacy fields from 2014-19, each rig drilling four new production wells per year, each well producing 1,000 bpd beginning in 2014, with maximum production of 60,000 bpd for a total of 140 million barrels. Development costs for each well are estimated at $20 million; none of the oil in this scenario would qualify for the GRE under the provisions of SB 21.
At $100 oil, losses drop from $275 million to $200 million in FY 2014, and become positive at $25 million in FY 2015, rising to $75 million in FY 2016. There is no difference in FY 2017, but the state is ahead $225 million in FY 2018 and $50 million in FY 2018.
Rigs, new well pad Scenario C includes the four additional rigs in legacy fields, plus the new 10,000 bpd new field and also includes a new well pad within an existing major North Slope unit producing 125 million barrels of new production over eight years starting in 2014 at a total development cost of $5 billion. Oil from wells at the new pad does not qualify for the GRE.
The combined scenarios, at $100 oil, brings production revenue under SB 21 level with ACES in FY 2015 and increases state revenues from FY 2016 through FY 2019 by $200 million, $350 million, $1,100 million and $925 million.
A fiscal note from the Department of Natural Resources using the scenarios developed by the Department of Revenue show increased revenues from royalties under the combined scenarios of $91 million at $100 oil in FY 2014, rising to $435 million in FY 2019. Because SB 21 does not impact royalties, there is no change under currently forecast production volumes.
Mustang on books Mustang, the Brooks Range Petroleum Corp. North Slope field near the Kuparuk unit, will be the first new oil to come online under the new fiscal system, but that field is already included in the Department of Revenue’s projections of crude oil production, shown in the spring forecast as coming online after 2016.
Point Thomson is also included in Revenue’s forecast, with production beginning in 2016.
Under existing projections, not including the scenarios, new oil is expected to contribute 3.1 percent of North Slope production this year, 10 percent in 2014 and steadily rising to 27.1 percent in 2022.
The decline rate of currently producing fields is shown at 9.9 percent this year, gradually dropping to 6.8 percent in 2022 in the spring forecast.
With new oil included in the forecast, the production decline rate drops to 7 percent this year and to 2.2 percent in 2014, rising to 7.5 percent in 2022.
Spring forecast down The spring forecast is down from fall, at 548,700 barrels per day, compared to 563,200 bpd in the fall forecast. All of the difference comes from the North Slope, with Cook Inlet production for 2013 constant between the forecasts at 10,400 bpd.
The forecast also drops from 2014 and 2015, is the same for 2016 and rises thereafter to 350,100 bpd in 2022, compared to the fall forecast at 344,100 bpd.
The price forecast, however, rises between the fall and spring forecasts, with the Alaska North Slope West Coast price at $109.21 in the spring forecast, up from $108.67 in the fall forecast, and the ANS wellhead weighted average at $99.66, up from $99.24 in the fall forecast, a change of 54 cents for ANS West Coast and 42 cents for the ANS wellhead weighted average.
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