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." 9:13:45 AM DAN STICKEL, ASSISTANT CHIEF ECONOMIST, TAX DIVISION, DEPARTMENT OF REVENUE, presented the draft fiscal analysis of CS SB 21 (FIN) (copy on file). He turned to Slide 1 titled, "Provisions in CSSB 21 (FIN) and their Estimated Fiscal Impact as compared to Fall 2012 Forecast ($millions)." He cautioned that the fiscal analysis was a draft and the fiscal note could contain differences. The slide displayed the data from the fiscal note for the previous version of the bill [CSSB 21 (RES)]. The analysis listed the 12 provisions of the legislation that had a potential revenue impact and the provisions for refunded credits that impacted the operating budget. Mr. Stickle reviewed the provisions. He highlighted the differences (items highlighted in grey) in the Senate Finance Committee Substitute (CS) compared to the Senate Resources Committee version of SB 21. The first provision eliminated the progressive portion of the tax and remained unchanged. The second provision adjusted the base rate from 35 percent of the production tax value down to 30 percent in the finance CS. The finance version decreased revenues to the state compared to the resources CS that imposed a higher base rate production tax. The third provision eliminated the qualified capital expenditures for the North Slope, and remained unchanged in the finance CS. The finance CS monetized the net operating loss credit and increased it to 30 percent to match the base rate. The department deemed that the net operating loss (NOL) credits would not be taken against tax liability; but instead used by companies that did not have a tax liability. The change to the NOL credit impacted the operating budget. Mr. Stickle discussed the Gross Revenue Exclusion (GRE) for certain wells. The Resources CS applied the GRE to specific units, Participating Area (PA) or portions of PAs. The finance CS applied a lower exclusion of 20 percent, which was applied to any well that met certain qualifications on approval by DNR. The range ($0 to $50 million) displayed assumed that at the lower end only new developments would receive the GRE. The higher end of the range assumed that any production in "under development" and "under evaluation" components of the department's production forecast would receive the exclusion. The fiscal impact would likely fall in the middle of the range. Mr. Stickle detailed that the extension of the small producer credit was unchanged. The finance CS retained the elimination of the mandatory two year credit provision. The community revenue sharing fund and the $5 per barrel tax allowance were left unchanged. The new corporate income tax credit for qualified oil and gas service expenditures remained intact. Mr. Stickle noted that a new provision in the finance version was included to reduce the interest rate on late payments or assessments for most taxes administered by the Department of Revenue (DOR). He predicted a small impact in revenues in the early years and a growing impact over time. The extension of the exploration extension credit was unchanged from the prior version of the bill. He reported that the combined impact of the revenue provisions totaled $900 million to $1.1 billion increasing to $1.5 to $1.9 billion in FY 19. Mr. Stickle offered that the impact was mitigated to some extent by the impact on appropriations. The impacts on the operating budget were divided into three items. The first impact resulted from credits taken in one versus two years. The provision advanced the entire $150 million liability in refunded North Slope Credits to FY 14. The provision was net revenue neutral. The limitation to the Qualified Capital Expenditures (QCE) credit decreased refunded credits by $150 million per year for the North Slope, which benefitted the operating budget. The finance CS expanded the NOL credits from 25 percent to 30 percent and impacted the operating budget by approximately $25 million per year. Mr. Stickle communicated that the total fiscal impact for both the state's operating budget and revenue was approximately $1 billion to $1.3 billion in FY 2014 increasing to $1.4 billion to $1.8 billion in FY 2019. 9:22:11 AM Vice-Chair Fairclough questioned the GRE for wells as listed on line 5, slide 1. She referenced that the range for 2014 was zero to $50 million for certain wells. She asked what production level the $50 million was based on. Mr. Stickle replied that the potential $50 million impact in FY 14 included the under development and under evaluation portion of the forecast and the number of barrels for one half of the fiscal year. The fiscal impact was based on the 20 percent revenue exclusion for the total number of barrels. Vice-Chair Fairclough asked the department to provide information regarding the number of barrels used to calculate the analysis. She thought the assumption was valid but she countered that the barrels were not calculated in new dollars. Mr. Stickle replied that he would provide the information. Vice-Chair Fairclough wanted to understand the $50 million figure used in view of the revenue impact. She wondered what price per barrel the revenue impact was based on. Mr. Stickle stated that the draft analysis was based entirely on the fall 2012 revenue forecast. Vice-Chair Fairclough asked whether the analysis included new barrels. Mr. Stickle explained that analysis on line 5 reflected production that was not currently on line but was expected. The production forecast was divided into three components. The production classified as under development or under evaluation in the production forecast were new wells expected to produce but not currently producing oil. Vice-Chair Fairclough asked if the wells would qualify for GRE under the legislation. Mr. Stickle replied that the department provided a range from zero to $50 million because qualification of the wells remained uncertain. He anticipated that the impact fell somewhere in the middle. Senator Hoffman remarked that the numbers included in the draft fiscal analysis were "staggering." He pointed out that the low end estimate of the losses through FY 2019 totaled $7.5 billion or an average $1.25 billion every year. He added that the high end of the spectrum amounted to $9.5 billion or $1.5 billion per year. Without any changes to Alaska's tax structure, the state needed to borrow up to $400 million from the state's savings account [in FY 2014]. He warned that the lost revenue would have detrimental effects to the state's operating budget and savings accounts. He suggested serious consideration of the budgetary process. He estimated that $1.6 billion dollars withdrawn from savings would be necessary to balance the budget within the first year of the enacted legislation. He cautioned that the committee must carefully review the numbers and the impact that the bill had on the needs of Alaskans. Co-Chair Meyer agreed with Senator Hoffman's concern about the potential loss to the state's treasury. He reminded the committee that the current fiscal year's deficit was due to decreased oil production. The fiscal note could not predict the amount of increased production the state could expect as a competitive participant in the global markets. He noted his "frustration" with the fiscal note and stated that if production was not expected to increase, the committee was wasting its time with the legislation. MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS, DEPARTMENT OF REVENUE pointed out that DOR included "scenario analysis" comparisons of increased new production predicted in the forecast. Senator Olson wondered how many barrels of new production were necessary to make up the lost revenue anticipated in the next five years. Mr. Pawlowski reported that the information was still under analysis. Co-Chair Meyer asked about the fiscal note comparison with the Senate Resources CS. Mr. Stickle replied that he had not compared the two fiscal analyses. The finance version of the bill had a larger fiscal impact under the forecast. The Senate Resources version impact ranged from $800 million to $900 million in FY 14 to $800 million to $1 billion in FY 19. 9:30:02 AM Mr. Stickle addressed Slide 2: "Production Tax Revenue, less refunded and carried-forward credits." He explained that the slide depicted a graph of production tax revenue under the Alaska Clear and Equitable Share (ACES), SB 21, CSSB 21(RES) and CSSB 21 (FIN). The graph displayed the net production tax revenue minus North Slope refundable credits. The graph addressed major provisions of the bill and lacked data for corporate income tax service industry credit, the expansion of the exploration credit, the reduction in interest rates for late payments, and assessments of taxes. He related that all versions of SB 21 provided a better net impact to the state than ACES at the lower price ranges for oil. The net impact was lower than ACES at higher oil prices. The net impact of CSSB 21 (FIN) at the current price of oil was higher than the other versions of the bill when compared to ACES. Mr. Stickle continued with Slide 3: "General Fund Unrestricted Revenue, less refunded and carried-forward credits." He highlighted that the blue line depicted on the chart represented total unrestricted revenue to the state under the ACES regime compared to each version of SB 21 assuming no changes in production and using fall forecast numbers. Senator Bishop asked whether the projections were based on the 2012 fall revenue forecast. Mr. Stickle concurred and clarified that the revenue analysis was projected for FY 14 price scenarios. Mr. Pawlowski interjected that FY 15 was chosen because it was the first full fiscal year the tax changes would be in effect. Mr. Stickle noted that the following slides illustrated three different production scenarios. He reviewed Slide 4: "Production Scenarios." Scenario A: · New 50 million barrel field developed by small producer without tax liability · Peak production = 10,000 bbls/day · Development costs = $500,000,000 · Qualifies for GRE and NOL Mr. Stickle turned to Slide 5: "Scenario B: Production Scenarios." Scenario B: · Operators of existing unit add 4 drill rigs to current plans · Each rig adds 4,000 bbls/day in new production each year o Which each then decline at 15 percent per year · Does not qualify for GRE Mr. Stickle cited Slide 6: "Production Scenarios." Scenario C: · Operator of existing legacy unit builds new drill pad · Development cost = $5 billion · Adds 15,000 bbls/day in 2014 increasing to peak rate of 90,000 bbls in 2018 · Does not qualify for GRE Mr. Stickle addressed Slide 7: "Projected Revenues under production scenarios - at $90 per barrel ANS." He explained that the graph compared CSSB 21 (FIN) under the different scenarios to ACES under the production forecast in FY 14 - FY 19. After a few years of additional production at $90 per barrel, SB 21 yields more revenue with scenarios b and c than with ACES minus the additional production. The graph intended to provide an estimate of the revenue change derived from a certain amount of production. Mr. Stickle discussed Slide 8: "Projected revenues under production scenarios - at $100 / barrel ANS." He detailed that scenario b in FY 18 and FY 19 provided a comparable amount of revenue to ACES. Scenario c provided more revenue under CSSB 21 (FIN) than under ACES. Mr. Stickle discussed Slide 9: "Projected Revenues under production scenarios - at $120/barrel ANS." Scenario C showed closer projected revenues compared to ACES at the $120 price of oil. He disclosed that progressivity under ACES kicked in with a higher surcharge at $120 per barrel. Mr. Stickle examined Slide 10: "Projected revenues under production scenarios at forecast ANS price." The final slide illustrated the comparison using the forecast price. In the early years, less revenue was projected with SB 21 using all three scenarios than under ACES projected. The FY 2017 - FY 2019 time frame exhibited a level of revenue that was similar to ACES. He reiterated that the analysis was not a forecast but illustrated how much additional production was necessary under SB 21 to equal the revenue under ACES. Co-Chair Meyer expressed that the previous slides addressed his concerns regarding information about the amount of additional production necessary to offset the fiscal impacts of changing the tax regime. He wondered which scenario DOR felt was most likely to occur. Mr. Pawlowski stated that any scenario was "imperfect." The conclusion drawn from scenario a was that new field development was not sufficient to offset the revenue impact. Scenario b demonstrated that more production in the legacy fields significantly improved the revenue outlook. He detailed that the analysis in scenario b included a 15 percent decline each year. The more realistic scenario was scenario b; the addition of rigs in a legacy field. The development of "large pads" (scenario c) was a more "difficult" and long term investment. But was a more desirable investment for the state. 9:39:53 AM Mr. Stickle added that DOR felt the scenarios were "plausible" but could not attach a percentage probability. Co-Chair Meyer asked whether the analysis included the cost for credits under ACES. Mr. Stickle thought that they were factored in. Mr. Pawlowski answered in the affirmative. He added that "the analysis portrayed what incremental production would have to happen under the CS to get towards ACES as forecast." Senator Hoffman reiterated analysis that showed that the state was foregoing $1.4 billion at the low end and $1.8 billion at the high end. He cited scenario C. He commented that the analysis did not look promising. He wondered whether a business would make a similar adjustment to revenues. Mr. Pawlowski replied that the scenarios included only basic areas of new investment. The committee could model additional incremental production if further evaluation was desired after balancing future industry testimony. Senator Hoffman voiced that any additional investment was purely hypothetical, if any additional drilling occurred at all. But the revenue the state was foregoing under ACES was not. Co-Chair Meyer relayed that according to industry testimony; a more competitive environment in the state meant more industry activity. Co-Chair Kelly pondered whether the legislators were "here to protect the interest of the government or are we here to protect the people of Alaska." He opined that the state "spent too much." He believed that too much discussion occurred among legislators about "keeping money for government." He believed the problem was too much government. The state took too much money from investors under ACES and now must examine how to "give some money back so business will stay here and continue to invest." He felt that the state must give back measured against what the people wanted not what the government wanted. He wanted the legislature to examine how the state spent money. He stated that "a $5.7 billion operating budget was ridiculous." The state savings would be expended because the state spends too much not because of oil tax reductions. He wanted to protect the ability of Alaskans to spend their money by ensuring jobs were available. Senator Olson wondered how revenue sharing would work under the new legislation. He indicated that revenue sharing would be appropriated from to the general fund instead of linked to progressivity. 9:48:37 AM Mr. Pawlowski offered that the finance CS mandated that state revenues were deposited into the general fund. The original version "softly dedicated" corporate income tax revenue to the revenue sharing fund. He deemed that the finance CS authors decided that corporate income tax revenues were general fund revenues. He explained that the revenue sharing statue guided the decision. The legislature may appropriate either $60 million per year or up to the amount necessary to bring the balance of the fund up to $180 million. The CS took the appropriation from the broader pool of the general fund instead of the specific corporate income tax. Senator Olson wondered whether the legislature could radically change the revenue sharing contribution. Mr. Pawlowski answered that the original language required that the legislature appropriated the revenue from progressivity into the revenue sharing fund. The amount of the appropriation was maintained in statute. The statutes focused on how much the fund needed which provided stronger guidance for full funding given that the legislature chose to appropriate to the revenue sharing fund. Senator Olson asked what the bill's potential impact on the revenue sharing fund was. Mr. Pawlowski replied that no difference existed. The amount deposited into the fund was subject to legislative appropriation. Co-Chair Meyer added that the revenue sharing language was the same as what was currently in ACES. The fund was subjected to legislative appropriation. 9:51:24 AM AT EASE 9:56:09 AM RECONVENED BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC. presented the Power Point presentation "Comments on Senate Finance CS SB21." Mr. Pulliam began with Slide 2: "Summary of Investment Measures New Participant Investment in 50 MMBO field $20/Bbl Developmental Capex, 12.5 % Royalty Rate." He explained that the spreadsheet contained a comparison of "investment metrics" between ACES and various versions of SB 21 and other oil producers in the world. He noted that the net present value (NPV) (measured at price per barrel) for the investor improved with each version of SB 21. Mr. Pulliam pointed out that the new provision in the CS allowed losses to be monetized in contrast to losses being carried forward. The carry forward allowed a new participant's economics to look similar to an established producer. Mr. Pulliam continued with Slide 2. He directed attention to Government Take figures and noted that Alaska was more competitive compared to other parts of the world. He believed that the investment climate looked very good to an investor. Mr. Pulliam turned to Slide 3, "Summary of Investment Measures Incumbent Investment in 50 MMBO Field $20/Bbl Development Capex, 12.5% Royalty Rate" He reported that the spreadsheet contained the same analysis as slide 2 for the incumbent. The figures in column four that reflected the finance CS were identical to the chart for the new participant. Unlike ACES, a new participant had the same or better tax rate as the incumbent. He exemplified that at $100 per barrel, CSSB 21 (FIN) offered a higher NPV to the new participant ($5.97) than the incumbent ($5.87). The small difference was driven by the small producer credit extended until 2022. The credit was a write off to buy down the incumbent's current tax obligation. Monetization of the early investment by the new participant placed the new participant in the same financial footing as the incumbent. He suggested the committee re-examine the need for the small producer credit while simultaneously allowing monetization of the losses. Co-Chair Meyer asked whether the need for the credit was necessary while offering a net operating loss (NOL). Mr. Pulliam responded that both the NOL and monetizing losses placed the new participant on a level playing field with the incumbent. He thought that made the small producer credit unnecessary. Co-Chair Meyer asked how that would impact the fiscal note. Mr. Pulliam replied that would amount to $25 million to $50 million per year with the same number of producers. More producers would continue to qualify for the small producer credit and the impact would increase. Mr. Pulliam concluded that the finance CS "leveled the playing field" between the new and incumbent investors and created a more favorable investment climate. Senator Bishop asked for an explanation of a cash margin. Mr. Pulliam explained that a cash margin was the producer's cash flow after tax payments divided by the number of barrels that were produced. According to the spreadsheet, a producer had a cash margin of $44.16 under CSSB 21 (FIN) in contrast to $29.48 for ACES. Senator Bishop noted that the cash flow under the finance CS was better than in North Dakota. Senator Dunleavy asked whether any of the new or incumbent participants related what they thought of the proposed tax legislation. Mr.Pulliam heard favorable responses, particularly from new participants. 10:07:28 AM Mr. Pulliam discussed Slide 4: "Duration of the GRE." · GRE has the effect of reducing` tax rate · Removing GRE during life of a well is a tax increase on that production (to the nominal rate) · Increase occurs as well productivity is declining and per unit costs are rising · can shorten productive life of a well and total recoveries · Better Alternative would be a lower GRE over life of well that provides same economics to the producer. Mr. Pulliam identified the methods that provided incentives in the tax systems: (1) GRE, (2) per barrel allowance, (3) capital credit (ACES). The incentives lowered tax rates and improved the economics for the producer. He shared his concern about limiting the GRE over time. He demonstrated that a lower GRE extended over the life of a well was a better option through the following three slides. Mr. Pulliam highlighted Slide 5: "Well Production Profile Initial 1,500 BPD, 12% Decline Rate." ¾Approximately 50 percent of oil [was] produced during the first 5-7 years of well life ¾Well productivity declines while $/Bbl operating costs rise over time ¾Maintenance and Workovers Extend the Production Life of a Well Mr. Pulliam explained that the slide contained a graph that depicted the annual and cumulative production over a 20 year period of the well. The GRE would raise the tax rate of the well while it was becoming less productive and profitable. He suggested the effect was contrary to the objective of the legislation. Mr. Pulliam reviewed Slide 6: "Relationship Between Length of GRE and Percent of NPV of Drilling Cost Initial 1,500 BPD, 12% Decline Rate." The slide graphed the relationship over time. He exemplified that if the GRE was offered at 20 percent at $100 per barrel over 5 years the NPV for the producer amounted to 30 percent of the cost of drilling the well. The GRE was similar to a 30 percent capital credit. If the limit was extended to 10 years the NPV totaled 40 percent and beyond 10 years the NPV valued 45 percent. Alternatively, the GRE could be reduced to 15 percent for the life of the well. The alternative produced the same results for the producer and "eliminated the potential for having an earlier shut in for the well." He recommended that the committee consider a lower percentage GRE over the full life of a well. Mr. Pulliam discussed Slide 7: "Example of Tax Calculation With and Without GRE." He noted that the analysis on the chart was based on the rates included in the finance CS. The calculation was based on gross production of 100,000 barrels at 12.5 percent royalty amounting to 87.5 thousand taxable barrels. The calculation without the GRE minus expenses amounted to a taxable value of $70 per barrel. The total production tax value was $6.125 million taxed at the 30 percent tax rate minus the $5 production allowance of $437.5 thousand for a net taxable total of $1.4 million. The tax as percentage of the net value of production was 22.9 percent. The tax as a percentage of the gross value of production was 16 percent. The same variables with a 20 percent GRE ($20 per barrel) were subtracted out of the taxable value resulting in a taxable value of $50. The taxes due minus the $437.5 thousand ($5 per barrel) totaled $875 thousand. The same variables applied at a GRE of 15 percent. The taxable value was $55 per barrel which resulted in a slightly higher tax due of approximately $1 million dollars. The tax was higher with the lower GRE. 10:18:15 AM Co-Chair Meyer indicated that the resources CS version set the GRE at 30 percent. The taxes would be significantly less at the 30 percent rate. Mr. Pulliam confirmed and replied that the tax base rate was set higher at 35 percent. The tax rate and GRE offset each other. Co-Chair Meyer commented that CSSB 21 (FIN) attempted to accomplish the same rate as the Resources CS but with a lower tax rate and higher GRE. He surmised that it wasn't an even exchange. Mr. Pulliam agreed the numbers were not exact but thought that it was close enough. In response to a question by Co-Chair Meyer, Mr. Pulliam reiterated that he advocated lowering the GRE for the entire life of the well instead of the 20 percent GRE with a limited duration. Senator Bishop wondered whether the "theory" behind extending a lower GRE was to incentivize keeping the well producing while in decline. Mr. Pulliam concurred. Mr. Pulliam addressed Slide 8: "Example of NOL Credit Related to New Investment Of $1 Billion." He understood the intent of the NOL credit. He described that the chart exemplified the NOL over a five year period. The chart depicted a capital spending column and tax loss column at 30 percent. The tax loss, or portion of, would be the amount monetized. The intent of the CS was to tie the amount of monetization to the continued investment. The first year loss was monetized out of a loss in the second year and the remainder of the loss was carried forward, which continued through year three. In the fourth and fifth year the tax loss for the year was monetized at the full amount and there was no carry forward. In the 5th year production began and the monetized amount over the 5 year period was 50 percent and the carry forward totaled 50 percent. The carry forward losses were increased at 15 percent per year. The carry forward was counted against the tax obligation as it became due. The monetization was tied to the ongoing investment in an effort to avoid investments for the sole purpose of investing without production. He believed that the 30 percent tax rate itself dissuaded illegitimate investments. He suggested that investors could pre-qualify the project. Pre-qualification could accomplish a level playing field between the incumbent and new investor and ensured that the investment was legitimate. 10:28:14 AM Senator Bishop asked whether the loss was split between the producer and the state under the NOL credit. Mr. Pulliam answered in the affirmative. He added the carry forward would apply to the producer's tax obligation going forward. Vice-Chair Fairclough reported that she presented the NOL concept based on the idea that "people that wanted the state's money should invest that money into the state." Consultants suggested using capital credits to accomplish the objective. Mr. Pulliam turned to Slide 9: "Annual State Cash Flows New Participant Investment in 50 MMBO Field $20 Bbl. Development Capex 12.5 Percent Royalty Rate. He explained that two graphs on each side of the slide illustrated NOL's carried forward with and without the GRE and NOL's monetized with and without the GRE in relation to taxes specifically production tax (depicted in blue.) He highlighted that the main difference was that monetization of the NOL's meant that the state would collect taxes sooner and if the NOL's were carried forward tax collection was delayed. Mr. Pulliam discussed slide 10: "Shares of Per-Barrel Values Under SFIN CS SB 21 (30 % Base Rate, $5 /Bbl. Allowance, Losses Monetized) for All Producers (FY 2015 - FY 2019) He explained that the graph illustrated the profit share among the state and federal government and the oil industry. He summarized that as the price of oil raises the state and industry shares were similar and the federal government share was smaller. Mr. Pulliam examined Slide 11: "Interest Rates 1977 - 2012" He noted that provisions in the finance CS contained changes to the overdue tax interest rate, which he concurred with. The current law required the highest of 11 percent or the federal funds rate plus 5 percent. He believed the 11 percent rate was very high and was sympathetic with industries disapproval of the rate. He opined that the rate was punitive and the state should charge a penalty instead. He explained that the graph looked back over the time since ANS (Alaska North Slope) oil was produced and depicted the tax rate declining except for a period of time in the late 1970's and early 1980's. He encouraged the committee to eliminate the 11 percent and tie the interest rates to the federal funds rate plus 3 percent. He felt that was a simpler system and more equitable for both sides. Co-Chair Meyer liked the suggestion to change the interest rate. SB 21 was HEARD and HELD in committee for further consideration. 10:37:36 AM