SENATE FINANCE COMMITTEE March 6, 2013 1:32 p.m. 1:32:45 PM CALL TO ORDER Vice-Chair Fairclough called the Senate Finance Committee meeting to order at 1:32 p.m. MEMBERS PRESENT Senator Pete Kelly, Co-Chair Senator Anna Fairclough, Vice-Chair Senator Click Bishop Senator Mike Dunleavy MEMBERS ABSENT Senator Kevin Meyer, Co-Chair Senator Lyman Hoffman Senator Donny Olson ALSO PRESENT Michael Pawlowski, Advisor, Petroleum Fiscal Systems, Department of Revenue; Barry Pulliam, Managing Director, Econ One Research, Inc.; Joe Balash, Deputy Commissioner, Department of Natural Resources; Senator Hollis French. SUMMARY SB 21 OIL AND GAS PRODUCTION TAX SB 21 was HEARD and HELD in committee for further consideration. SENATE BILL NO. 21 "An Act relating to appropriations from taxes paid under the Alaska Net Income Tax Act; relating to the oil and gas production tax rate; relating to gas used in the state; relating to monthly installment payments of the oil and gas production tax; relating to oil and gas production tax credits for certain losses and expenditures; relating to oil and gas production tax credit certificates; relating to nontransferable tax credits based on production; relating to the oil and gas tax credit fund; relating to annual statements by producers and explorers; relating to the determination of annual oil and gas production tax values including adjustments based on a percentage of gross value at the point of production from certain leases or properties; making conforming amendments; and providing for an effective date." 1:33:07 PM Vice-Chair Fairclough communicated that the meeting would include invited testimony from the Department of Revenue (DOR), Department of Natural Resources (DNR), and Econ One. She shared that public testimony would begin in the following meeting at 3:00 p.m. MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS, DEPARTMENT OF REVENUE, relayed that the administration had been asked to provide responses to initial questions on the legislation and on the relationship between gross revenue exclusions (GRE) and credits in particular. BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC., provided a PowerPoint presentation titled "Comments to Senate Finance SB21/SRES CS SB 21" (copy on file). He shared that the goal was to address members' questions on how various credits would work and interact with one another. He pointed to slide 2 titled "North Slope Tax Rate under SRES CS SB21 with $5/bbl Production Allowance." The administration had heard some concern about the 35 percent base rate (an increase over the 25 percent rate). He explained that under the proposed system the rate would work in tandem with the $5 per barrel production allowance, which would lower the rate. He stated that in reality the 35 percent rate would never apply (as indicated on slide 2, which included a net taxable value scale of $0.00 to $200 per barrel). Co-Chair Kelly asked if the chart showed the production tax or the overall state tax. Mr. Pulliam responded that the chart only showed production tax. Co-Chair Kelly asked for verification that slide 2 did not include the royalty. Mr. Pulliam replied in the affirmative. He elaborated that the slide illustrated the tax rate that would apply on the production tax at various prices; it was possible to translate the values into West Coast prices by adding approximately $40 per barrel. 1:37:00 PM Mr. Pulliam looked at slide 3 titled "GRE Equivalent Value from Specified Production Allowance (35% Tax Rate)." He addressed that the various mechanisms (operating at a single tax rate) were designed to achieve a system that was not regressive; a system that had a slight progressive component that countered the regressive effect of the royalty. The system could be accomplished with a GRE, per barrel allowance, or capital credit. He discussed the relationship between the per barrel allowance and GRE. The current CS included a $5 per barrel allowance and a 30 percent GRE for new oil. The $5 per barrel allowance represented by the blue line on slide 2 showed what kind of GRE it achieved. He elaborated that the allowance could be thought of as a GRE; it declined as price rose and rose as the price fell because the fixed barrel allowance remained the same. For example, under the CS at approximately $80 per barrel the $5 allowance crossed the 20 percent GRE mark. The chart illustrated that an allowance level of $10 per barrel would be equivalent to a 40 percent GRE at the $80 per barrel price; the allowance level at $15 per barrel was equivalent to a 60 percent GRE at the $80 price. He reiterated that the allowance percentage would decline as the price rose. The concepts were similar but were structured differently; the GRE provided a percentage off of the value of the oil, whereas the per barrel allowance provided a varying percentage off the value of the oil. He reiterated the different structures. 1:40:56 PM Vice-Chair Fairclough welcomed Senator Hollis French to the committee room. Mr. Pulliam turned to slide 4 titled "Capital Credit Equivalent Value at Specified Production Allowance." He relayed that the per barrel analysis could also be looked at on a capital credit equivalent. The slide showed the $5, $10, and $15 dollar per barrel allowances to indicate how they would translate into a capital credit. The slide indicated that at a $10 cost in capital a $5 allowance was equal to a 50 percent capital credit; a $10 per barrel allowance at a $10 cost in capital would equal a 100 percent capital credit. As capital spending increased the fixed per barrel percentage declined. The allowance was mechanically different than a capital credit, but it accomplished some of the same things. He pointed to a key difference of the capital credit under ACES where a 20 percent credit was paid upfront; whereas, the allowance would only be earned as oil was produced. He elaborated that the items had a different net present value (NPV) effect, but they worked towards the same goal. 1:43:06 PM Mr. Pulliam moved to slide 5 titled "Annual State Revenues and Producer Cash Flows at $100 West Coast ANS ($2012) Lower Cost Oil Alaska Development New Participant in Alaska" illustrated the cash flow differences between ACES and the CSSB 21(RES). He directed attention to the lower graph showing state revenues; the blue bars represented the state's cash flows under ACES. The negative cash flow as development on the field got underway corresponded with the state's purchase of credits and net operating losses from the new participant; the combination of the two equaled approximately 45 percent of the development costs in the early years. As production began later in the fourth year and into the fifth year, positive revenues began to be collected under ACES. The green bars represented CSSB 21(RES); there were no outflows from the state given that it was not purchasing credits. The net operating losses were carried forward and recovered later against the tax obligation. The tax rate was lower under the CS; therefore, the green bars shown were lower. He pointed out that the timing of the different mechanisms under ACES and the CS was different; ACES provided the credits upfront; whereas, under the CS the credits and allowances were given as oil was produced. Mr. Pulliam moved to slide 6 titled "Annual State Revenues and Producer Cash Flows at $100 West Coast ANS ($2012) Lower Cost Oil Alaska Development Incumbent Participant in Alaska." The lower graph related to state revenues showed a loss under ACES for the first years of development due to the purchase of credits and a loss in tax revenue. He relayed that the net difference to the state for an incumbent was larger in the early years than it was for a new participant. He explained that an incumbent investing in a new field would have the ability to deduct expenses against their tax obligation. He detailed that the incumbent would not be able to buy down the rate, but expenses would be deducted at the 35 percent. There was a different effect on the incumbent than on a new producer. 1:47:12 PM Mr. Pulliam continued on slide 9 titled "Producer and State Economics under Alternative Systems New Participant Investment in 50 MMBO Field $20/Bbl Development Capex, 16.67% Royalty Rate." The slide showed how the different allowances and their duration would affect the producer and the state in a hypothetical development of a 50 million barrel field in and around the legacy fields. The first column showed the present value to the producer on a per barrel basis under the CS at the 35 percent base rate combined with the $5 per barrel allowance; at $100 per barrel West Coast ANS price the development would have a NPV of $3.60. Columns 2 and 3 showed the effect of the 30 percent GRE; the NPV increased to $4.59 shown in column 2, which represented a 10-year period. Column 3 showed the impact of providing the 30 percent GRE for the life of production; the NPV increased to $4.86. He detailed that the change between columns 2 and 3 was not as great as it was in the first 10 years given that the bulk of a field's oil was produced in the early years and nearer-term was more valuable on a NPV basis. He believed the analysis would help with any discussion on how cutting off the GRE or some of the allowances would impact various items. The data showed that the majority of the benefits would be obtained by allowing the GRE for the first 10 years of a field's life. Mr. Pulliam addressed what would happen if an allowance was used without the GRE (slide 9). Columns 4 and 5 illustrated an increase in the allowance by $5 per barrel for new production. The additional $5 allowance would increase the NPV, although not as significantly as the 30 percent GRE. Columns 6 and 7 showed how an additional $10 allowance would increase the NPV. Columns 8 and 9 demonstrated how using only a capital credit allowance on top of the base system would impact the NPV. He stated that the capital credit was consistent with what was provided under ACES; the credit could be claimed immediately as opposed to being carried forward. 1:52:32 PM Mr. Pulliam explained that columns 10 and 11 on slide 9 showed the NPV under ACES and without any production tax respectively. He detailed that ACES and a no production tax scenario were both used when evaluating whether the various mechanisms made sense economically for the state. He addressed conclusions based on the chart. He shared that the scenarios providing a GRE or an allowance included in the CS substantially improved producer economics unless the price of oil was very low; in the $80 range the CS did not improve economics relative to ACES. He noted that ACES had the highest NPV at $1.26 (column 10); however, the state's NPV was negative and it turned out to be a more favorable system for producers. He surmised that the scenario was not positive for the state. Mr. Pulliam turned to the second section on slide 9, which showed the impact on government take. For example, a new producer developing a field with the characteristics on slide 9 and qualifying for the GRE would fall under column 3; government take would be just below 60 percent in the $100 to $120 per barrel range. An additional $5 per barrel allowance would put government take at approximately 62 percent to 63 percent (column 5). The scenario would not be as generous to the producer, but it would still fall within a competitive range. He communicated that there were various ways to benefit producers' economics with the GRE and per barrel allowance without providing upfront state funding. 1:56:28 PM Senator Bishop asked which of the scenarios on slide 9 would provide producers with the best advantage for the most oil production at $100 per barrel. Mr. Pawlowski asked for clarification on the question. Senator Bishop explained his question. Mr. Pawlowski responded that he would look for any scenario that provided the highest NPV; column 11) "no production tax" would provide the highest NPV for a producer. Out of the proposed options, column 3 (the lifetime 30 percent GRE) would provide producers with the highest NPV. Vice-Chair Fairclough remarked that the response was contrary to testimony from current producers in relation to legacy fields. She detailed the new explorers were happier with the Senate Resources Committee CS, but that other industry testimony had been in support of the capital credits, despite the higher NPV under the lifetime 30 percent GRE shown in the Econ One presentation. Mr. Pawlowski clarified that the slide included an analysis for new participants only. He pointed out that the Alaska Oil and Gas Association (AOGA) had testified that a system should avoid the tendency to pick winners and losers. He stressed that the economics shown on slide 9 completely changed for a company with an existing tax liability that could write its expenditures off. The incentives were about creating a level playing field between new entrants and existing producers. He believed that the administration had more work to do with the committee on the topic of what was fair for legacy production. 1:59:57 PM Mr. Pulliam turned back in the presentation to slide 7 titled "Producer and State Economics under Alternative Systems Incumbent Investment in 50 MMBO Field $20/Bbl Development Capex, 12.5% Royalty Rate." The slide was structured the same as slide 9; however, incumbent investment had an existing tax obligation and any incremental decisions impacted the obligation. He pointed out that at $100 per barrel the NPV under ACES was $5.98 (shown under column 10); the figure was close to the no production tax scenario NPV of $6.12. He stated that it was a pretty good place for producers to be. Column 1 demonstrated that the NPV would be $4.57 without the GRE, which was not as favorable. He referred to prior testimony that the GRE did not apply to new oil within legacy fields compared to columns 2 and 3 where the enhanced economics were applied and the NPV increased above the ACES number. He believed the testifier had thought that the bill represented a tax increase at lower price levels and that without the GRE they were being treated unfairly relative to new producers/fields. The chart also included other credit scenarios. 2:02:44 PM Mr. Pawlowski clarified that the discussion pertained to an incremental investment and its economics and not ongoing production in the legacy fields. The administration had distinguished its analysis between the two systems and had looked at what an additional participating area (PA) or the expansion of a PA would mean within a legacy field under the CSSB 21(RES). He acknowledged that additional opportunities existed that did not meet the criteria. Mr. Pulliam directed attention to slide 8 titled "Producer and State Economics under Alternative Systems New Participant Investment in 50 MMBO Field $20/Bbl Development Capex, 12.5% Royalty Rate." The slide showed information for a new participant with a 12.5 percent royalty. He noted that the variance between the 12.5 percent and 16 percent royalty made a difference to the producer economics. He detailed that under the 12.5 percent royalty a producer's NPV was $4.26 under the base scenario in column 1 the $100 per barrel price; the NPV was $3.60 under the 16.67 percent royalty (slide 9). The higher royalty resulted in higher take and lower NPV. He elaborated that higher the royalty, the less of a tax bite a producer would be able to withstand in order to maintain similar economics. A producer looking to develop a new field could always look for royalty relief with DNR if the economics on a 16.67 lease were not working. 2:05:44 PM Mr. Pawlowski believed it was important to address the various metrics (e.g. NPV, government take, and other) for the public's understanding. He added that it was important to remember that NPV and government take were only two of the metrics. He encouraged committee members to review earlier presentations that had included cash margins and internal rates of return. He referenced testimony that had pointed out a balance between all of the metrics used by a company when making investment decisions. Mr. Pullium continued to address slide 8. The top section illustrated the producer NPV and the section that followed showed the government take. The three lower sections of the slide pertained to the state including the NPV of the state production tax, the NPV of the total state cash (including production tax, royalties, income tax, and property taxes), and the NPV of the total state cash where the state received 50 percent of the royalties (e.g. the National Petroleum Reserve - Alaska where 50 percent of the royalties went to the federal government). He noted that in the three lower sections the investment did not look any different from the producer standpoint; however, the scenarios were different from the state's standpoint. He explained that ACES and SB 21 were both net tax systems therefore the royalties were not taxable barrels yet the cost of production was deductible. The NPV for the state was lower in the scenarios in which the state only received 50 percent of the royalties. 2:08:32 PM Mr. Pawlowski pointed out that stress tests against the no production tax scenario hoped to identify situations where the state had materially improved through its fiscal system. The administration saw the scenario as a system that went too far and could not be justified as a way to incentivize production. Another concern related to how the movement of the GRE, credits, and allowances affected the production tax revenues. The NPV information on slide 8 had been included to show where the state would win or lose related to production tax revenues. Depending on the price some of the scenarios did not produce a desirable outcome for the state. 2:09:52 PM Mr. Pulliam looked at slide 10 titled "Impact of "Interest" on Loss Carry Forward 50 MMBO New Field With 16.67% Royalty $20/BBL Development Cost, New Participant." The slide broke out producer and state economics and showed what would happen if there were different levels of interest; because it pertained to new development a 30 percent GRE would be provided to the producer. He pointed to column 4 that showed the 15 percent carry forward increase under CSSB 21 (RES). At the $80 oil price level the producer economics remained constant at $0.62 per barrel regardless of different loss carry forward rates. He explained that the carry forward provision included a 10-year sunset; therefore, at very low prices all of the losses may not be used. He noted that at $80 per barrel the state economics were $307 million regardless of the loss carry forward rate because a producer would not be able to use the entirety of the loss carry forward. He detailed that the scenario would change at $100 to $120 per barrel and the producer would use the entire loss carry forward. He pointed out that at $120 per barrel the producer NPV with no loss carry forward was $8.25 compared to an $8.71 NPV with a 15 percent loss carry forward. Column 6 showed a system where losses could be deducted as expenditures were made. A 35 percent deduction would be received up front and the NPV would equal $9.06 at the $120 per barrel price. He compared columns 4 and 6 and explained that a 15 percent loss carry forward obtained a similar result as deducting the losses right away. 2:14:09 PM Mr. Pulliam turned to slide 11 titled "Average Government Take ACES v. SB21/HB72 and SRES CS SB21 for All Existing Producers (FY2015-FY2019) and Other Jurisdictions." The slide illustrated the difference between the take for ongoing operations compared to the take for new production. The graph looked at the government take projected over a 5- year period (FY 15 to FY 19) from ongoing operations on the North Slope. He noted that while some new investment would occur, the investment was dominated by ongoing production and legacy fields. Under CSSB 21 (RES) the government take began at low prices in the mid-60 percent range and approached 65 percent as time went on. He relayed that government take for new investment was typically lower in the low-60 percent range, particularly related to the allowance and GRE. He noted that the last couple of slides related to development and the GRE; he turned the floor over to Mr. Pawlowski. Mr. Pawlowski asked DNR Deputy Commissioner Joe Balash to discuss PAs, the GRE under the CS and time limitation concept issues. 2:16:59 PM JOE BALASH, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, pointed to a slide from a past Pioneer Natural Resources presentation (slide 13) and asked the committee to take the information into account if it was considering the inclusion of a time limitation on the GRE. The slide showed an image including the original offshore development (represented in green); Pioneer was evaluating whether or not to pursue the Nuna development (represented in purple as a separate pool). The department was currently considering whether to grant the company with a PA for the development. He elaborated that original production had begun in 2008 or 2009. He explained that any time limit imposed would shorten the time under which the PA would qualify for a GRE or additional dollar per barrel allowance associated with the new areas. He urged the committee to consider linking any time limitation to a PA to ensure that the beginning of the limit was tied to the time production began. 2:19:44 PM Senator Bishop asked Mr. Balash to reiterate his testimony. Mr. Balash communicated that production at Oooguruk began in 2008/2009. He explained that if a 7-year clock had been started at the time of the first production, it would run out in 2015. He expounded that any additional production within a unit would be bound by the clock if a GRE limitation were placed at the unit level. He asked the committee to consider placing any time limitation at the PA level. He referenced the Pioneer slide and noted that a 7- year clock would have run out by the time the Nuna Project came into production. Senator Bishop surmised that the light blue portion of the image should not have a time limit. Mr. Balash replied in the affirmative; that the clock would start over at each PA. Vice-Chair Fairclough pointed to the Pioneer slide (slide 13, but labeled slide 6) and noted that it could be argued that the Nuna development would not qualify for a new PA if it were 50 percent new. She asked how DNR would ensure that a company could not create a new PA within an existing field. She wondered about criteria the department would use to keep subjectivity low for PA approval. Mr. Balash replied that the slide showed a two dimensional representation of the leases contributing to a unit; however, the formations represented on the slide occurred at depth as well. He elaborated that the green portion showed the original sets of sands that were developed, which represented a portion of the PA at Oooguruk. The Nuna formation was in a different location and occurred at a different depth; therefore, DNR was able to measure the land by depth, longitude, and latitude. He believed the department used section lines for the track numbers. He detailed that it was relatively easy for the department to keep two distinct PAs separate. The slide showed that production from Nuna would come onshore at a different location than the original offshore island Oooguruk had produced from. He explained that metering would be straight forward and barrels could be accounted for easily. Mr. Balash discussed that it was more challenging when original PAs were expanded in the legacy fields. He explained that under CSSB 21 (RES) the burden would be on the lessees to demonstrate that a new part of the reservoir would contribute to production; a portion that had not contributed previously because it had been inaccessible due to old drilling technology or other. The producer would be required to prove the area was new through seismic information (4-D seismic) or through reservoir engineering practices looking at fluid dynamics and pressures. Approval to expand the PA would be provided if the producer could prove the area was new. The second step would be for the producer to prove to DOR that it was producing from the new area and that it could account for the barrels produced separately from the original production; if the producer could not demonstrate these items, the area would not qualify for the GRE. 2:26:10 PM Senator Bishop surmised that there was a clear distinction between the original Oooguruk field and the Nuna project. Mr. Balash replied in the affirmative. He elaborated that the areas were in different formations and locations and likely had differing geochemistries. Mr. Pawlowski addressed the Nuna example on slide 13. He relayed that there were three criteria related to the GRE under the CS (Sections 28 through 30). He read that "the oil or gas is produced from a lease or property that does not contain a lease that was within a unit on January 1, 2003" or oil and gas that was produced from a PA that was within a unit formed before January 1, 2003 (Section 28, page 26). Under the CS any new unit would receive a permanent GRE; within units formed prior to January 1, 2003 the criteria were either a new PA or an expansion of the PA. He relayed that modifications needed to be made in Section 28 to the bill language if a time limit were placed on the GRE in order to allow for distinguishment in the future. The current CS language did not contemplate a future situation where a unit would clock out on the GRE and where a new PA would not be subject to the GRE. Vice-Chair Fairclough asked for clarification on the bill section. Mr. Pawlowski pointed to page 26, line 26 through page 27, line 11 (Section 28). The particular language of concern appeared on page 26, lines 29 through 31. 2:29:12 PM Mr. Pawlowski turned to a Pioneer Natural Resources graph on slide 14 [last slide in the presentation, labeled slide 11]. The slide showed a production profile for a new development; the administration believed the slide helped explain the clock related to drilling (i.e. how many years it took to drill). He detailed that a 7-year time limit would only allow for 1 to 2 years of GRE benefits given that production would not actually begin until approximately year 3. Consideration should be given to the time it took to drill out a development and the potential within the units to have multiple PAs located on top of each other. Mr. Pawlowski directed attention to a supplemental slide titled "Production Tax Revenue Impacts of Various Base Tax Rates FY 14 - FY 19" dated March 6, 2013 (copy on file). He relayed that Senator Dunleavy had asked the administration to provide a sheet showing the fiscal impacts of various base rates across the projected production and price forecasts in the fall 2012 Revenue Sources Book. The top of the slide showed the estimated production tax revenue under ACES for FY 14 through FY 19. He noted that the figures included the credits paid out and all other mechanisms existing under current law. The only piece not included was the refunded credits (credits paid through the operating budget to companies with tax credit certificates), which was ultimately an expenditure and liability to the state as opposed to a revenue impact. Mr. Pawlowski pointed out the various base tax rates ranging from 25 percent to 35 percent and projected revenues based on the tax rate for FY 14 through FY 19. For example, with a 27 percent tax rate the revenue for FY 15 would be $2.875 billion. He noted that the figures did not include any additional credits or incentives that may be offered in a bill. He relayed that the slide was intended to give committee members a starting place to evaluate what a base rate would generate and what incentives offered against the rate. The lower portion of the table illustrated the delta from the forecast revenues under ACES. For example, with a 27 percent base rate the revenue would be $532 million less than the ACES forecast. He reiterated that the figures did not include any additional credits. 2:33:41 PM Vice-Chair Fairclough asked for verification that the slide answered Senator Dunleavy's question. Senator Dunleavy replied in the affirmative. Vice-Chair Fairclough communicated that public testimony on the bill would begin at 3:00 p.m. 2:34:34 PM AT EASE 2:35:52 PM RECONVENED Vice-Chair Fairclough noted that the documents and past presentations for SB 21 were available on BASIS. SB 21 was HEARD and HELD in committee for further consideration. ADJOURNMENT 2:36:31 PM The meeting was adjourned at 2:37 p.m.