SENATE BILL NO. 192 "An Act relating to the oil and gas production tax; and providing for an effective date." Co-Chair Stedman stated that there would be a short presentation by PFC Energy and that the committee would adopt a committee substitute (CS) for SB 192. He furthered that PFC Energy would be brought back for further discussion regarding a component that had not been included in the CS. He noted that the committee would also be discussing how it would balance the schedule between the Finance Committee, PFC Energy, and the industry so that there was ample time to analyze the information. He observed that there were differences in some of the modeling, cost assumptions, as well as other aspects. Co-Chair Stedman asked for a brief description of PFC Energy. He pointed out that PFC Energy was hired by the Legislative Budget and Audit Committee, a joint House and Senate committee that handled consultants. 9:54:56 AM TONY REINSCH, SENIOR DIRECTOR, UPSTREAM & GAS, PFC ENERGY, explained that PFC Energy was an above ground risk and analytical consultant to the oil and gas sector. He detailed that PFC Energy advised international oil companies, governments, regulators, and national oil companies on issues of policy finance economics. 9:55:23 AM JANAK MAYER, MANAGER, UPSTREAM & GAS, PFC ENERGY, began a PowerPoint presentation titled "Discussion Slides: Alaska Senate Finance Committee" (copy on file) and explained slide 2 titled "Difficulties in Existing Fiscal Structure": · The incorporation of progressivity into the Profit- Based Production Tax (Net) in ACES creates three significant problems · Large-scale gas production at low gas prices could in the future significantly reduce production tax revenue from existing oil production · Resolving this problem within the framework of ACES requires significant complexity · Approach to decoupling in CSSB 192 requires ability to split costs between oil and gas production, creating high degree of administrative burden, and limiting capacity of state to effectively audit · Combination of high credits with high tax rates can produce excessive levels of support for certain spending, and weak incentives for cost control · Effective After-Tax rate of Government support for exploration can be over 100% at high price levels · Options for incentivizing new production are limited, and relatively complex · Proposed incentives within existing framework focus on either allowances to reduce Production Tax Value, or revenue exclusions (tax holiday) 9:58:25 AM Mr. Mayer discussed slide 3 titled "Summary of Progressive Severance Tax (Gross) Structure": · A Progressive Severance Tax (Gross) option would instead remove progressivity from the Profit- Based Production Tax (Net), instead levying this tax at the flat, base rate of 25% · To retain an element of progressivity, a new Progressive Severance Tax (Gross) would then be added to the system. The tax would: · Be non-deductible for Profit-Based Production Tax purposes · Be levied on gross production (net of royalties) · Be levied solely on oil · The tax would use a progressivity structure not dissimilar to that under the current system, with progressivity coefficients that apply at different thresholds. · The proposed Progressive Severance Tax would use the following parameters: · No severance tax below $65 Gross Value at Point of Production (GVPP) · Progressivity of .25% commencing at a threshold of $65 GVPP · At $125 GVPP, a tax rate of 15% is reached. At this point, progressivity is reduced to 0.05% · Progressivity is capped at 20% 10:00:00 AM Mr. Mayer spoke to slide 4 titled "Benefits of Progressive Severance Tax (Gross) Structure": · By removing progressivity from the Profit-Based Production Tax (Net), and having the progressive element of the structure be a Progressive Severance Tax (Gross), two things become much easier to achieve · The issue of gas production reducing production tax revenue ceases to be a problem without progressivity in the Profit- Based Production Tax · Complex provisions to split costs between oil and gas production under CSSB 192 are thus no longer required · Much of the issue of excessive spending support ceases to be a problem · Even with 40% exploration credit, effective after-tax Government support for exploration flat at 65% · Significant incentives can be provided to new production, by eliminating or reducing the Progressive Severance Tax (Gross) for new production · A wide range of levels of government take can be achieved using this structure, depending on the parameters applied 10:02:19 AM Mr. Mayer turned to slide 5 titled "FY 2013 Revenue Comparison." He stated that the slide showed a revenue comparison of how the severance tax option compared to some of the other alternatives. He related that the red and yellow lines depicted ACES and CSSB 192 as being very similar in terms of revenue, but there was a very slight reduction from ACES in CSSB 192. He stated that the severance tax option was represented by the light blue line and that it diverged from ACES and CSSB 192 from around $100 to $110 per barrel; furthermore, from $130 per barrel and upwards, the scenario flattened and evened out the split between the government and producers at around the 72 percent or 73 percent government take level. He pointed out that the slide compared the severance option to the placement of a 40 or 50 percent cap on progressivity under the current system. The 50 percent cap option was represented by the darker blue line and the 40 percent cap option was reflected by the green line. He observed that the chart was based on FY 13 Department of Revenue (DOR) numbers for production and costs; on that basis, the severance tax option's split of revenue from production tax and the split between cash to companies versus revenue to the state were in between the 40 and 50 percent cap options. 10:04:14 AM Mr. Mayer looked at slide 6 titled "FY 2013 Revenue Comparison." He pointed out that in terms of total state and government take, the severance tax option was between the 40 and 50 percent cap options. Mr. Mayer highlighted slide 7 titled "FY 2013 Revenue Comparison." He stated that the comparative revenue table showed that at around the $100 per barrel price level, the total revenue under the severance tax option was projected be slightly above that of the Senate Resources Committee version of CSSB 192; at prices above $100 per barrel (i.e. a $150 to $200 per barrel) there was a balancing of the government take "between the two." He referenced the government take figures on the lower right table and stated that the severance tax option's government take flattened out at about 73 percent from the $150 per barrel range and above. Co-Chair Stedman pointed out that there were a lot of numerics in the tables and that although it may take some time, it would be helpful if the committee had some comparison material. Mr. Mayer replied that the table in question was done consistent with DOR methodology and that it did not include tax credits that were claimed against current production. He noted that the state was expected to expend $400 million in FY 13. 10:05:59 AM Mr. Mayer looked at slide 8 titled "FY 2013 Revenue Comparison - Adjusted for Credits Not Claimed Against Current Production." He stated the slide's table examined the production tax in terms of total state take in order to include the $400 million tax credit expenditure. Senator McGuire noted that when the decoupling issue was discussed, the state projected about $80 million in losses per year. She inquired if the projected losses were reflected in the cost chart as a savings that would be returned to the state. Mr. Mayer replied that the projected losses were not included in the figures and that the chart was based solely on FY 13 revenue numbers. He stated that the projected losses would come to the state as savings in the event of significant gas production. Senator McGuire commented that the point was important to note. 10:07:12 AM Mr. Mayer discussed slide 9 titled "Impact of Rising Operating Costs." He shared that the slide showed an important impact that came from shifting progressivity from the net to the gross; the impact was a question of what the shift looked like in different cost environments compared to the existing system. He noted that DOR projected that in FY 13, the cost per barrel of oil produced would be $11.70. He observed that the chart compared the difference in revenue under ACES and the severance tax option; anything above the zero line represented an increase in revenue compared to ACES, while anything below the line was a decrease in revenue. The slide showed that at the $70 per barrel price level and at $12 per barrel operating costs, the revenue between ACES and the severance tax option were identical; the two options also generated the same revenue at the $60 per barrel level and the same cost per barrel level. He stated that revenue increased below the $60 per barrel level in all of the instances because of the impact of the higher floor that was in CSSB 192. He related that in the $12 per barrel cost scenario, the severance tax option had reduced revenue at the $100 per barrel tax level when compared to ACES; in comparison, it had relatively similar revenue compared to CSSB 192 at the $100 to $130 per barrel level, but had significant reductions in revenue past $130 per barrel as the split between producers and the state was capped. 10:09:05 AM Mr. Mayer stated that when looking at what would happen under significantly higher operating cost assumptions, it was important to understand that the progressive severance option saw an increased take at price levels in the $70 to $140 per barrel range. He explained that at $12 per barrel operating costs and at a $100 per barrel price, production tax rates under ACES were probably around 35 percent. He furthered that if the operating costs were at a higher rate of $24 per barrel, the tax rate under ACES could drop to 28 percent; the drop in the rate was a result of a reduction in the production tax value (PTV) after the costs had been deducted. He related that in some of the higher cost per barrel cases, the progressivity that was put in place on the gross (through the progressive severance option) may be higher than the progressivity experienced under ACES when production costs were particularly high; this was a result of the progressive option being calibrated to the $12 per barrel level. Mr. Mayer reiterated that a $12 per barrel operating cost was the current average on the North Slope. He noted that from a producer perspective, the progressivity at higher cost levels may be viewed as problem; however, on the other hand it was important to consider the current system's lack of cost control incentive. He furthered that particularly at high marginal tax rates and when there was the ability to deduct costs from progressivity, the effective support from the state for new capital and operating expenditures could be very high; in that sense, it was a significant incentive for controlling costs in the future. He concluded that part of the discussion going forward would be about the two sides of the progressive option's progressivity at higher operating costs. 10:11:55 AM Mr. Mayer discussed slide 10 titled "Data on Operating Costs." He stated that the top right chart depicted the historical average costs for Prudhoe Bay, Kuparuk, and the North Slope; in recent years, operating costs in the areas were between $10 and $12 per barrel. He noted that in 2010, Prudhoe Bay had a slightly higher operating cost of $12 per barrel compared to Kuparuk's cost of around $10 per barrel and that the North Slope average was a bit over $10 per barrel. He pointed out that based on FY 13 numbers, the North Slope average was projected to rise to $11.70 per barrel. He directed the committee's attention to the chart on the upper left portion of the slide that showed a longer time period. He related that ConocoPhillips was unique because it reported Alaska separately as a region in its financial reporting. ConocoPhillip's 10-K reports [required annual report to the U.S. Securities and Exchange Commission] showed an operating cost of about $12.50 per barrel in 2011 and costs below the $10 per barrel mark for prior years. He spoke to the chart in the lower middle portion of the slide. He related that the DOR forecast for average operating costs on the North Slope predicted a cost around the $12 per barrel mark until around 2017, at which point the costs were expected to continue to rise every year. Mr. Mayer explained that the levels of averages on slide 10 could disguise some of the granularity that existed (e.g. BP's costs may reflect something different than what was shown for ConocoPhillips). He opined that although Prudhoe Bay and Kuparuk's costs were probably similar for both companies, BP's other assets might have higher operating costs. He added that new producers could have higher cost assets that would involve higher operating costs (i.e. $16 to $18 per barrel). He pointed out that new production, which would have a higher cost structure, could have lower rates of progressivity applied to it. He offered that the committee may also want to have the lower rate of progressivity apply to higher cost projects that had been brought on line in the recent past. 10:14:46 AM Mr. Mayer spoke to slide 11 titled "Impact of Inflation": · Under ACES, thresholds and coefficients for progressivity are specified in nominal terms, without indexation · As a result, when economics over the long- term rather than just 2013 are examined, we see the effects of 'bracket creep' or 'stealth tax' · In real terms, as prices increase, thresholds for progressivity decrease, and the higher take that comes with progressivity occurs at lower and lower price levels · Similarly, unless progressive severance thresholds are indexed to inflation, progressive severance will apply at steadily lower thresholds over time · Indexing thresholds will also go some way to addressing the cost sensitivity issue Mr. Mayer noted that it was particularly important to put in place indexation for inflation in reference to the two prior slide's information regarding the impact of costs when progressivity was levied on the gross rather than the net. As long as the real costs did not also rise, the indexing would result in progressivity rising along with it if costs rose in nominal terms. He added that cost rising in real terms was another question related to the issue of incentives for cost control. 10:16:19 AM Mr. Mayer discussed slide 12 titled "Incentives for New Production": · Significant incentives can be provided to new production, by eliminating or reducing the Progressive Severance Tax (Gross) on any combination of: · Production from new areas · Production from new plans of development (determined through the regulatory process to be for "new production") · Production above a fixed decline rate · One possibility for a reduced rate of Progressive Severance Tax is: · No severance tax below $65 Gross Value at Point of Production (GVPP) · Progressivity of .05% commencing at a threshold of $65 GVPP · Progressivity capped at 5% Mr. Mayer stated that based on some of the numbers, the slide's example of a possible way to reduce progressivity would result in a significant improvement in the economics for some projects and would have levels of government take around the mid-60 percentage range instead of the mid-70 percentage range. 10:17:23 AM Mr. Mayer highlighted another consideration related to incentivizing new production. He explained that production from new areas was straight forward; however, the impact of new areas would be minimal because in the near term most of the new production would come from existing areas. He stated it was important to think about how incentivizing production above a fixed decline rate would work. Mr. Mayer spoke to slide 13 titled "Production Above a Decline-Fixed v Annual Calculation." He pointed out that the slide's two charts used DOR revenue production forecast data and that data was looked at in two different ways. He noted that the slide was an exercise and that it was important to pretend that the production was reflective of one producer rather than multiple producers. The charts depicted what the production from a single producer would look like if production above a decline rate was determined in two different ways. The left chart assumed there was a determined rolling average decline; the option would use the recent average decline to determine how much new production there was in the current year when compared to the prior year. He stated that based on the slide's production curve, the rolling average method resulted in very little production being classified as new production. He stated that there two reasons for the lack of new development classification under the rolling average option: (1) only the previous year was examined to determine a production level above the decline rate and (2) in any years in which incremental new production existed, the rolling average went from a decline to an incline and as a result, it became difficult to produce additional production above the high threshold. 10:19:46 AM Mr. Mayer continued to speak to slide 13 and offered that the chart on the right depicted the scenario with a simpler and more "effective" method by selecting a specific point in time and projecting what production would look like going forward based on the decline rate; there would be a significant "wedge" of new production if anything above the decline rate would be incentivized with a lower taxation rate. If the goal was to incentivize production above the 6 percent decline, the strategy provided was useful and would allow companies to work towards a lower tax rate in a way that a year-by-year process would not allow. 10:21:15 AM AT EASE 10:24:33 AM RECONVENED 10:25:01 AM Co-Chair Hoffman MOVED to ADOPT the proposed committee substitute for SB 192, Work Draft 27-LS1305\T (Bullock, 4/2/12). Co-Chair Stedman OBJECTED for the purpose of discussion. 10:25:29 AM DARWIN PETERSON, STAFF, SENATOR BERT STEDMAN, reviewed the changes in the new CS for SB 192. He relayed that all sections (Sections 1, 5, 7, 8, 10, 11, and 12) pertaining to oil and gas tax decoupling had been removed from the bill because the process of removing progressivity from a profits based production tax and applying it to the gross value was a de facto decoupling. The increased production allowance (Section 13) was removed, which had proposed a $10 per barrel reduction in PTV for each barrel of oil delivered to the Trans-Alaska Pipeline System that was above the base volume as determined from the prior calendar year. 10:26:20 AM Mr. Peterson walked through the bill sections. Section 1 amended the production tax so that progressivity on oil was calculated on the gross value at the point of production. The section maintained the 25 percent base tax on the PTV of oil and gas that was currently included in the ACES statute. He relayed that Section 2 was identical to Section 6 from the previous bill version. The section repealed AS 43.55.011(f) and set a new minimum tax of 10 percent of the gross value at the point of production for areas with historical production of 1 billion barrels of oil to date; the provision would apply only to the Kuparuk and Prudhoe legacy fields. Mr. Peterson explained that Section 3 repealed the existing progressivity based on the PTV (AS 43.55.011(g)) and replaced it with a new progressive severance tax on the gross value. He elaborated that on a monthly basis progressivity on oil produced in a legacy field would be calculated as follows: no severance tax below $65 gross value at the point of production, progressivity of 0.25 percent commencing at $65 gross value at the point of production at $125 gross value a tax rate of 15 percent was reached progressivity would be reduced to 0.05 percent, and progressivity would be capped at 20 percent. He furthered that the concept had been introduced by PFC Energy on March 30, 2012 and had been referred to as "Severance Tax Option Number 1." 10:27:51 AM Mr. Peterson turned to Section 3, page 3 that would establish a reduced rate for the progressive severance tax on oil produced outside of the legacy fields. The rate would be calculated as follows: no severance tax below $65 gross value at the point of production, progressivity of 0.05 percent would commence at a $65 gross value, progressivity would be capped at 5 percent, and the lower tax on fields outside Prudhoe and Kuparuk was only applicable for the first seven years of production (page 3, line 2). Mr. Peterson relayed that Section 4 was a conforming amendment to statute that dealt with the payment of taxes by a producer; the section included the new progressive severance tax and the 10 percent minimum tax. Section 5 (page 6) was a conforming amendment that instructed DOR to adopt regulations to calculate the new progressive severance tax based on the gross value at the point of production. 10:29:06 AM Mr. Peterson shared that Section 6 was identical to Section 12 from the previous bill version. The section amended AS 43.55.160 by adding three subsections to describe the allocation of lease expenditures to oil or gas production or exploration in different areas of the state. Section 7 was same as Section 14 of the previous bill version and would amend AS 43.55.165(h), which dealt with lease expenditures. The Section required DOR to allocate lease expenditures between oil and gas production based on the gross value at the point of production. Mr. Peterson explained that Section 8 (page 8) was the same as Section 15 of the previous bill version; it added a new subsection to AS 43.55.170, which was the section of statute that dealt with adjustments to lease expenditures. The section would require DOR to adopt regulations that provided for reasonable methods of allocating adjustments to lease expenditures, payments, and credits between different categories of oil and gas production. 10:30:06 AM Mr. Peterson communicated that Section 9 included the Petroleum Information Management System. The only change was the placement of the system under the purview of DOR instead of AOGCC. Section 10 repealed AS 43.55.160(a)(2) that dealt with the monthly progressivity calculation based on the production tax value. He expounded that under the new CS the section was irrelevant given that progressivity would be taxed on the gross value at the point of production. Mr. Peterson discussed that Section 11 was uncodified law that required DOR to develop a work plan for the Petroleum Information Management System; the section required that the system be operational before January 1, 2014. He concluded with Section 12 that established an effective date of January 1, 2013. Co-Chair Stedman REMOVED his OBJECTION. There being NO FURTHER OBJECTION, Work Draft 27-LS1305\T was ADOPTED. 10:31:36 AM Co-Chair Stedman noted that the incremental production from Prudhoe Bay and Kuparuk was not included in the CS; his office was working with PFC Energy and would meet with them to work out details related to the item. He had concern about using the 2013 decline curve versus the curve from 2011 or 2012; he believed the committee needed to take a look at the item. He shared that his intent was to "get a CS on the table" in order for the industry offer a more fine-tuned opinion on the bill. SB 192 was HEARD and HELD in committee for further consideration. Co-Chair Stedman discussed the following meeting's agenda.