SENATE FINANCE COMMITTEE March 29, 2012 9:06 a.m. 9:06:08 AM CALL TO ORDER Co-Chair Stedman called the Senate Finance Committee meeting to order at 9:06 a.m. MEMBERS PRESENT Senator Lyman Hoffman, Co-Chair Senator Bert Stedman, Co-Chair Senator Lesil McGuire, Vice-Chair Senator Johnny Ellis Senator Dennis Egan Senator Donny Olson Senator Joe Thomas MEMBERS ABSENT None ALSO PRESENT Janak Mayer, Manager, Upstream and Gas, PFC Energy. SUMMARY SB 192 OIL AND GAS PRODUCTION TAX RATES SB 192 was HEARD and HELD in committee for further consideration. Co-Chair Stedman discussed the meeting's agenda. SENATE BILL NO. 192 "An Act relating to the oil and gas production tax; and providing for an effective date." 9:07:16 AM JANAK MAYER, MANAGER, UPSTREAM AND GAS, PFC ENERGY, began the PowerPoint presentation titled "Discussion Slides: Alaska Senate Finance Committee." (copy on file) He indicated that the presentation would look in particular at the ideas of removing progressivity from the net production tax, having the net production tax be a flat 25 percent tax, and levying progressivity in the form of a gross tax on oil instead; the gross tax would begin at a certain rate and increase similarly to the progressivity under the current measure. Mr. Mayer discussed slide 2 titled "Difficulties in Existing Fiscal Structure." · The incorporation of progressivity into the Profit- Based Production Tax (Net) in ACES creates two 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 · 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 9:10:02 AM Mr. Mayer spoke to slide 3 titled "Summary of Progressive Severance Tax(Gross) Option." · 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 optioned modeled here has the following parameters: · Base rate of 0% · Progressivity of .25% commencing at a threshold of $65 (gross value at point of production) · At $125 GVPP, a tax rate of 15% is reached. At this point, progressivity is reduced to 0.05% · Progressivity is capped 20% Mr. Mayer noted that previously presented analyses had shown what a new progressive severance tax would look like if it was deductible for profit-based production tax purposes; however, for the sake of simplicity and from the perspective of retaining progressivity, the modeled tax was non-deductible for profit-based production tax purposes. He added that if the tax was deductible for the purposes of production tax, each increment of progressivity would have a partial offset in the form of reduced production tax and that it would result in smaller overall progressivity than might have otherwise existed. He pointed out that the progressive severance tax option would be levied solely on oil and would eliminate the decoupling issue because instead of having a variable rate applied, the flat 25 percent tax rate would be applied. He related that if everything was taxed at the 25 percent rate, the cost of gas versus the cost of oil no longer mattered. He furthered that the option eliminated the decoupling issue without having to answer questions regarding the separate accounting of costs for oil and gas, separate tax returns for industry, and the abilities of the state regarding auditing powers. He related that based on the wishes of the committee, what was modeled was a system with revenue similar to CSSB 192 at the $100 per barrel level, but one that also diverged and flattened the split between companies and the state at higher oil prices. Mr. Mayer discussed slide 4 titled "Benefits of Progressive 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 · 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 Mr. Mayer addressed the fourth bullet and stated that the incentives could be offered for a particular period of time or on an indefinite basis. He furthered that under this system, incentivizing was easier because the only information needed was what a particular production stream was, as well as the oil price. He reiterated that the model's parameters were aimed to have similar revenue to the state as CSSB 192 at a price of $100 per barrel and have an evening of the split between companies and the state at current price levels. 9:15:21 AM Mr. Mayer explained slide 5 titled "FY 2013 Revenue Comparison." He stated that the slide showed, on an FY 13 basis, the levels of production tax, total state take, total government take, and cash to companies of the three listed options at crude prices ranging from $40 to $150 per barrel. He observed that at the $100 per barrel price level, the total revenue under ACES was about $3.7 billion; Under CSSB 192, the revenue generated at same price was reduced to a little over $3.5 billion. He pointed out that CSSB 192 with the progressive severance tax option had slightly reduced revenue from CSSB 192 at a price level of $100. He warned that it was very difficult to attain exactly the same revenue at $100 per barrel and that there was a significant margin of error involved with the calculations at the macro level. He explained that, given the high margin for error, the structure seemed to "get quite close" to CSSB 192 at the $100 price level. He related that at prices upwards of $100 per barrel, in particular above the $130 level, the government take under the progressive severance tax flattened and resulted in a more even split; whereas, the model showed that progressivity under ACES and CSSB 192 continued to escalate at prices above $100 per barrel, which resulted in a higher take for the state. Co-Chair Stedman noted that the committee did not have time prior to the meeting to review the charts in the presentation. He stated that prior testimony in committee had indicated that the current tax system functioned well at a price of $100 per barrel, but that it became problematic at prices north of $100. He added that the committee was zeroing in on the $100 range due to the current system's problems at prices over that level. Co-Chair Stedman clarified that the government take numbers on slide 5 included property taxes, severance taxes, income taxes, and royalties. He inquired if the model showed that at a price of $100 per barrel, CSSB 192 with the progressive severance tax option was close to CSSB 192 and was within $70 million. Mr. Mayer responded in the affirmative. Co-Chair Stedman noted that he had been looking at the wrong line and corrected that under the severance tax option, the difference in the cash position was closer to $130 million. He observed that the progressive severance tax option was pretty close to CSSB 192 at prices of $90 and $80 per barrel. Co-Chair Stedman requested a clarification on slide 5 and asked for an explanation of the $40 and $50 per barrel price range. Mr. Mayer responded that at prices below $65 per barrel, there was no difference between the two CSSB 192 options because progressivity did not occur until higher oil prices. Mr. Mayer discussed slide 5 and stated that although the two CSSB 192 options were identical to each other at the $40 and $50 per barrel range, they were higher than ACES at those price levels due to the 10 percent floor that was entailed in both the CSSB 192 options. 9:20:43 AM Co-Chair Stedman spoke to slide 5 and noted that the FY 13 revenue projections from the Revenue Sources Book represented the homogenized numerics and that it included companies with no production. He added that companies with no production were absorbing around $400 million in credits and that it had an impact on the numbers. Co-Chair Stedman requested PFC Energy to run the tables again using only current producers in FY 13 as inputs. He furthered that he would like to get a feel for how the numbers moved in the currently producing category and inquired if Mr. Mayer had looked at that aspect yet. Mr. Mayer responded that he would see if additional analysis in the requested area was possible. Co-Chair Stedman noted that there was a lot more work to be done, but that it was his goal to keep the committee informed throughout the process. Co-Chair Hoffman noted that under the projections for FY 13 and at the current price of around $109 to $110 per barrel, the revenue generated from the progressive severance option would represent a reduction of one-third of $1 billion in revenue to the state over ACES; however, the total cash returned to companies at the same price was $217 million and was substantially lower than the reduction in revenue to the state. Co-Chair Stedman interjected that the figures Co-Chair Hoffman was referring to were reflective of oil prices at $110 per barrel. Co-Chair Hoffman reiterated that the figures represented the current projections for revenue in FY 13. Mr. Mayer inquired if Co-Chair Hoffman was pointing out that the additional cash received by companies would be lower than the reduction in take to the state. Co-Chair Hoffman responded in the affirmative. Mr. Mayer replied that the gap between the two numbers was a function of the federal government take being increased. Co-Chair Hoffman queried if the state had any control over the increase in federal take. Mr. Mayer responded in the negative. Co-Chair Hoffman opined that oil futures were currently selling for roughly $200 per barrel. He pointed out that slide 5 did not go up to the $200 price level, but that there was an even more substantial reduction to the state and oil companies at that price. He observed the need to examine where oil futures were at currently. He offered that a common mistake made during the formulation of ACES was that people had looked at the $40 to $70 per barrel range; however, futures at the time were way above that price range and the oil prices rose as expected. Co-Chair Stedman reiterated the comments of Co-Chair Hoffman and clarified that the figures on slide 5 would change when the non-producing companies were excluded from the data. Co-Chair Hoffman stated that the committee needed to examine what futures were selling for and what the take would be under those scenarios. He reiterated that he believed futures were selling for around $200 per barrel. 9:25:32 AM Co-Chair Stedman pointed out that the numbers on slide 5 showed that at prices north of $130 per barrel, the percentage split between the industry and the state should remain fairly close to constant. He requested that Mr. Mayer explain how the split worked above $130. Mr. Mayer responded that Co-Chair Stedman was correct regarding the government to industry take above $130 per barrel and directed the committee's attention to slide 6. Mr. Mayer spoke to slide 6 titled "FY 2012 Revenue Comparison" and discussed the top left chart. He stated that at the $100 per barrel price level there was very little difference between the three options, that there was a slightly increasing divergence from $110 to $130, and that there was flattening out of government take above a price of $125. He added that the $125 per barrel price was the inflection point at which the decreased progressivity of the progressive severance tax option occurred. He noted that the purpose of the minimal .05 percent progressivity was to offset the slightly regressive nature of the royalty and hold government take flat from that price onward. Co-Chair Hoffman offered that there was another way to view the difference in the split. He stated that at prices above $130 per barrel, the state's take under the CSSB 192 progressive severance option would continue to decline and the industry's share would continue to rise in comparison to ACES. Co-Chair Hoffman asserted that he agreed with this view. Co-Chair Stedman agreed that Co-Chair Hoffman's perspective was another way of looking at the situation. Co-Chair Stedman stated that currently, the percentage of the pie would shrink to the industry, even though their dollars increase. He furthered that currently, the state's percentage of the pie continued to get larger. He observed that under the CSSB 192 progressive severance option, the percentage sharing would stay constant at prices north of $130 per barrel; however, if you compared the progressive option to ACES, a substantial reduction could be seen. He commented that the $200 per barrel range could be calculated and represented on the slide in dollar terms. He pointed out that at a price of $200, the costs would move because the state was under a net system. He opined that if the price was at $200 for very long, there would be an incremental rise in costs which would "pull that down a bit." He pointed out that the idea was to stabilize the sharing relationship between the industry and the state without sending the state into a regressive environment. Co-Chair Hoffman pointed out that one of the primary concerns from industry was that there was no advantage for development because it kept losing more share at the high end. He added that industry had expressed concerns regarding high end pricing scenarios and concluded that the CSSB 192 progressive severance tax option addressed those concerns. Co-Chair Stedman requested an explanation of the four quadrants on slide 6. 9:30:24 AM Mr. Mayer spoke to the four charts on page 6 and stated that the top left chart reflected revenue from the production tax, including the severance tax. The red line represented ACES, the yellow line reflected CSSB 192, and the blue line represented CSSB 192 with the progressive severance tax alternative. The bottom right chart depicted the cash to companies for each of the three given options. He stated that cash to companies experienced the same divergence and evening at higher price levels as the prior chart, but that the two CSSB 192 options returned more cash to companies at those price levels when compared to ACES. He observed that all three scenarios had a very similar result at prices below $100 per barrel; however, at very low price levels, both the CSSB 192 options resulted in reduced cash to companies and increased take to the state as a result of the 10 percent tax floor that was in CSSB 192. He continued to speak to slide 6 and stated that the bottom left and the top right charts depicted what the total state and government take would be under the given scenarios. He added that because there were other elements at play, the gap between the options looked significantly smaller when you compared the total state take to the total government take. Co-Chair Stedman requested that PFC Energy include some of the take numbers in percentages when it removed the non- producing companies in its calculations. He pointed out that the state based its numbers on the homogenized data, which represented the entire revenue stream to the state, while the industry ran its own numbers. He stated that the industry and the state numbers did not match up and that the disparity between the two was partly a function of the approximately $400 million impact of non-producer credits. Co-Chair Hoffman commented that if oil futures were selling for $200 per barrel, it would be nice to have the graphs depict that price range. He requested that PFC Energy provide the $200 pricing scenario in future graphs and opined that the numbers would probably reflect a difference north of $1 billion. Co-Chair Stedman reiterated the request of Co-Chair Hoffman. He clarified that he had requested PFC Energy to bring the x-axis to $150 per barrel because the lines ran parallel at prices north of $125 to $130, but that the graphs could be remade with the x-axis stretching to a price of $200. He added that it might be a distraction to look at prices such as $230 per barrel when the price was currently at $120. Co-Chair Hoffman commented that if futures were selling at $200 per barrel, looking at that price should be considered. Co-Chair Stedman voiced agreement with Co-Chair Hoffman and reiterated that the charts would be produced for the committee. Mr. Mayer remarked that he could look into the question of what the ANS West Coast and crude oil futures in general were trading at; however, given that spot prices were currently around the $120 per barrel mark, he would be "very surprised" to see futures trading dramatically above that price to the levels that had been suggested. [The comment was in respect to the recently discussed oil futures price of $200 per barrel.] He furthered that he would look into the matter of oil futures and get back to the committee. Co-Chair Stedman directed the presentation to slide 7 and stated that incentives for new production was another area of challenge. 9:34:56 AM Mr. Mayer spoke to slide 7 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 · Here, a reduced rate of Progressive Severance Tax has been modeled, using the following parameters for new production: · Base rate of 0% · Progressivity of .05% commencing at a threshold of $65 (gross value at point of production) · Progressivity is capped 5% · Following slides show a new, high-cost 10 mb/d development under · The regular rate · The reduced rate (with a time limit of 7 years) · The reduced rate (with no time limit) Mr. Mayer recapped that one of the benefits of the progressive severance option was that it overcame the decoupling issue without addressing the complex issue of accounting for costs; furthermore, it also created a number of ways to provide significant incentives for new production. He added that the progressive severance tax's increased options for incentives were a result of not having to look at the question of which costs came with a particular production; under this system, only the production numbers associated with the production stream and the crude oil price needed to be determined. Mr. Mayer began to speak to slide 8. Co-Chair Stedman requested a clarification on slide 7 and asked for an explanation of the third bullet point. Mr. Mayer responded that the following slides were based on a stylized, 10,000 barrel per day (bbl/d) high-cost development that had been used in previous analysis in the committee; furthermore, using the hypothetical development as a benchmark, the slides examined the levels of government take and the project economics in each of the three scenarios. Mr. Mayer explained slide 8 titled "Severance Tax-20% Maximum (New Producer)." He stated that using the hypothetical development and applying a 20 percent maximum on the severance tax, the slide's model showed levels of government take that were relatively steady at the 75 percent to 76 percent mark. He added that the slide showed a little regressivity, but that the structure was more perfectly steady when it was applied to base production or an existing producer. He reiterated that the scenario represented a very high-cost field and that it only broke even at oil prices a little south of $100 per barrel. He added that the scenario had a negative net present value (NPV) in the $40 and $60 per barrel cases and did not achieve a positive NPV until the $100 level; furthermore, the $100 price level only gave the scenario an internal rate of return (IRR) of around 11 percent. He concluded that the scenario's development was marginal, even at an oil price of $100 per barrel. Co-Chair Stedman requested an explanation of the expenses that were used in the slide. Mr. Mayer responded that the expenses were based on capital expenditures (CAPEX) and operating expenditures (OPEX) of about $17 per barrel. He stated that the OPEX costs in particular were accurately reflective of recent high-cost new developments. He shared that the expenses were particularly indicative of the newer producers who may have to share facilities and incorporate implicit costs and back-out agreements. He added that the high level of CAPEX was reflective of the significant increases in capital costs for new developments, particularly in areas where there was little or no existing infrastructure. He noted that the costs associated with the slide reflected a light oil development, but that the CAPEX and OPEX rose significantly in some of the viscous oil projects that had been proposed. 9:40:00 AM Co-Chair Stedman observed that there were members of the public who were probably unfamiliar with the charts and requested a walkthrough of the four quadrants on slide 8. Mr. Mayer responded that the top left portion of slide 8 depicted a basic cash flow diagram and that capital spending was reflected in the yellow. He continued to describe the cash flow diagram and stated that it showed negative production in the early years, followed by production, and then positive revenue over time with declining production. He pointed out that the revenue curve came from production and that it was represented in the blue; however, as a result of inflation, the actual production decline curve was steeper than what was depicted. He explained that the impact of inflation partly offset the slide's decline curve and resulted in higher nominal cash flows in the forward years, even as production itself declined. He shared that the red represented the operating costs, while the black line represented the after-tax cash flow that was produced. He added that in the early years, the diagram showed an after-tax cash flow that was not as strongly negative as the yellow of the CAPEX and that the disparity between the two was a result of the impact of the 20 percent capital credit. Mr. Mayer discussed the blue table next to the cash flow diagram and stated that it depicted the basic economic metrics of the NPV and IRR for the stylized project at prices of $40, $60, and $100 per barrel. Mr. Mayer spoke to the table on the upper right portion of slide 8 and stated that it depicted the total levels of government and state takes at each of the prices ranges. He shared that different elements, such as royalty, severance tax, or production tax were examined as a portion of divisible income and that they were summed horizontally on the chart to equal the total state or government take. Mr. Mayer discussed the two bottom charts on slide 8 and stated that they depicted the particular development's total state and government take figures in dollar terms and in percentages. Mr. Mayer addressed slide 9 titled "Severance Tax-20% Maximum with first seven years at a 5% maximum (New Producer)" and stated that the slide showed the same discounted rate as the previous slide, but with a maximum rate of 5 percent for the first seven years; the maximum rate would then revert to the 20 percent after the seven- year period. He remarked that if you compared this scenario to the previous slide, the economics of the two options were identical in the $40 and $60 per barrel cases because the progressive severance tax did not apply below that price range; however, at higher price levels, the NPV of the project rose from $29 million to $77 million, which resulted in an increase to the IRR from 11 percent to 12 percent. He concluded that slide 9 showed a further reduction in government take from the previous slide, particularly at the higher price levels, and that the government take levels peaked at around 73 percent, regressing only slightly from that point onward. Co-Chair Hoffman inquired if the having the maximum rate at 5 percent for the first seven years could be considered a tax holiday. Mr. Mayer responded that it was a tax reduction, but that it was not a tax holiday entirely because every barrel was still taxed, only at a lower rate. Mr. Mayer spoke to slide 10 titled "Severance Tax-5% Maximum (New Producer)." He stated that the slide illustrated the same scenario as the previous slide, but had the maximum rate stay at 5 percent indefinitely. For the first seven years, the cash flows of the scenarios on slides 9 and 10 were identical; however, after that period, the cash flow from slide 10 increased significantly due to the 5 percent maximum being applied across the board. He noted that the NPV from slide 10's scenario had increased to $119 million when compared to slide 9's NPV of $77 million. He concluded that the increase in slide 10's NPV represented a gain of 1 percentage point to the IRR of the stylized project. Slide 10's scenario had a flattening of government take from the $70 per barrel price range and upwards. He concluded that the scenario had a government take figure of about 65 percent if you looked at the lifecycle of the project as a whole. 9:45:09 AM Mr. Mayer explained slide 11 titled "20-year Revenue Impact of Reduced Rate for New Production" and stated that it examined the potential impact, over a 20-year period, of offering the discussed benefits for new production. He reiterated that there were a variety of ways to identify new production and offered that the simplest way was to provide incentives for production from new areas, such as the incentives for new oil under HB 110. He warned that the problem with only defining new production on the basis of being from a new area was that most of the new production was expected to come from within existing areas. He furthered that the second option for incentivizing new production would be to apply the benefits through the regulatory process, such as providing authority to the "executive" to approve that particular new plans of development provided new production; if the determination was made that the development plans provided new production, the lower rate of taxation could be applied to those projects. He added that with the first two options for defining new production, it was easy to apply a time limit to the reduced rate because there was clear initial start of production. He related that the third option available for incentivizing new production, particularly for existing producers, was to incentivize production above a set decline level. He mentioned the current 6 percent base rate of decline and stated that the decline at a given time could be determined and the curve of the decline could be projected forward. In this third option, any production above that determined curve of decline would have the preferential rate of taxation applied to it. He observed that with the third option, it would not be possible to apply a time limit because there was not a particular stream of production and starting date from which to set a stopping point. He added that if a time limit was applied to the first two options and the goal was to equalize the impact of the benefit for new production, a different gradient might be applied to new production above the 6 percent base rate "so that over time, the benefit of those two options were more equal. If one doesn't apply a time limit at all, then one doesn't need to differentiate on that basis." Mr. Mayer drew the committee's attention back to slide 11 and stated that the purpose of the slide was to determine an initial figure that would result from the 20-year impact of a policy for new production. He observed that the 2013 impact would be next to nothing because there would be very little production that would count as new during that year. He shared that the slide examined the increasing impact of the policy over time and that it used the Department of Revenue's (DOR) 20-year production figures, as well as the department's cost forecasts. He added that the 20-year production figures extended to 2032 and that the cost figures ran to approximately 2021. 9:49:04 AM Co-Chair Stedman interjected that the committee had not yet seen cost figures from DOR extending to 2021, but that it had seen figures that went through 2016. He observed that the cost figures extended farther out than the committee had been aware of and requested that the document be produced for committee members. Mr. Mayer continued to address slide 11. He stated that using DOR's production profile and cost estimates enabled the modeling of the cash flows under a range of scenarios. In order to get a rough estimate based on DOR's forecast, which included projects in development and anticipated new development, the slide used the 6 percent decline curve and applied the differential between old and new production over the course of 20 years. He furthered that the slide examined the difference in the NPV of the cash flows if the 20 percent maximum rate was applied to all production versus applying the 5 percent maximum rate indefinitely to all production above the 6 percent decline. He pointed out that there was approximately a $10 billion difference in the NPV of the cash flows for the production tax over that 20-year period at the $100 per barrel price level. He added that when production above a 6 percent decline was taxed at the lower rate, the slide's NPVs of the 20-year cash flows dropped from about $40 billion to $30 billion. He related that his intention with the analysis was not to suggest that the figures would represent how policy would work in practice because significant parts of the production were new projects, while relatively little would come from increased production in existing fields. He furthered that the analysis did not suggest that the 6 percent decline curve would be applied the way it depicted, but that it showed how big, in theory, the potential difference could be if the preferential rate was applied. 9:52:03 AM Co-Chair Stedman recalled that one of his concerns during previous discussions with Mr. Mayer had been that when the committee conceptualized a process or adjustment for incremental production, the state was not put into a position where "several years out, we have walked down some curve and we have no revenue." He expressed the need for caution regarding how to transition into new production in a manner that treated state and industry fairly. Mr. Mayer spoke to slide 12 titled "Regime Competiveness: Relative Government Take (Existing Production)." He stated that the slide benchmarked competiveness against a range other regimes, particularly the Organisation for the Economic Co-operation and Development (OECD) countries, which were represented by the yellow bars. He related that at a price of $100 per barrel, the ACES existing producer scenario was a little under Norway, who was the highest taxing OECD producer; however, if the price was increased to $140, ACES for an existing producer would be significantly above Norway. He shared that CSSB 192 represented only a slight reduction in government take in comparison to ACES and that it was a difference of only about 1 percentage point. He stated that under the severance tax option for CSSB 192, the scenario's government take dropped from 73 percent or 74 percent down to about 70 percent. Mr. Mayer explained slide 13 titled "Regime Competitiveness: Relative government take (New Development)" and stated that the slide examined the same competiveness but in the case of a new development. He reiterated that under ACES, the levels of government take were frequently higher for new developments than they were for existing production, partly due to the development's higher cost structure, but also because without an existing base production portfolio there was not as much benefit from writing down existing expenditures on current production. He pointed out that both the CSSB 192 and ACES scenarios for new developments were above Norway on the slide. He stated that the severance tax option with the 5 percent maximum for seven years took the government take down significantly, but that it was still around some of the higher taxing jurisdictions; however, if the 5 percent maximum was applied indefinitely, the levels of government take became quite competitive with some of the higher-cost developments, such as the unconventional developments in Louisiana and Texas. 9:56:10 AM Co-Chair Stedman inquired why Alaska would want to be below developments in Louisiana and Texas in terms of government take. Mr. Mayer pointed out that the chart made a distinction that the Louisiana and Texas plays were different from conventional developments and added that the reason that there was a difference in government take "between the two" was because that, relatively speaking, costs were higher for unconventional developments than they were for regular onshore drilling. He stated that higher costs led to a higher government take; however, the costs from plays like Louisiana and Texas remained below the costs on the North Slope. He stated that although government take was one part of the metric, the associated costs were another factor that determined if something was economic or not. He concluded that a jurisdiction being competitive on government take did not necessarily make it an attractive destination for investment. Co-Chair Stedman inquired if the variable severance tax option with the 5 percent maximum for seven years could be tweaked by either stretching the seven-year time period or by changing the maximum rate in order to enable the state to adjust as needed in the range between the two severance tax options on slide 13. Mr. Mayer responded in the affirmative and that by changing the seven-year period to a greater timeframe, the bars could be adjusted within the specified range. Co-Chair Stedman further inquired if this method of adjustment could potentially be used to target different hydrocarbons. Mr. Mayer responded in the affirmative and added that one benefit of taking progressivity out of the production tax was that question of costs was no longer important; the only information needed for calculations under this system was to know the production volumes associated with a given production stream and the price of oil. He added that for a particularly challenged hydrocarbon type, such as heavy oil where a greater incentive might be required, one alternative was to reduce the production tax on all production and then make up the difference for existing production by further raising the progressive severance tax; this would enable the overall take for existing production to remain close to the same, while still enabling additional incentives for particularly challenged development. Senator McGuire inquired if the regime competiveness slides could be remade to include oil prices at $140, $150, and $160 per barrel. Mr. Mayer responded that he would do so. Co-Chair Stedman offered that it might be easier if the regime competiveness slides were remade in $20 increments, such as $80, $100, $120, $140, and $160 per barrel. Senator McGuire observed that Co-Chair Hoffman had requested that the slides display up to a price of $200 per barrel. Co-Chair Stedman responded that $200 per barrel could also be displayed. 10:00:24 AM Senator Thomas wondered, given the large number of variables, how regime competiveness was calculated. He inquired how much investment was actually taking place in the top four countries on slides 12 and 13. He stated that the top four countries were not places that he would do business in and observed that there several other countries above Alaska on the slide that also fit that profile. He pointed out that the slide depicted Alaska below Venezuela, which had nationalized its oil fields and opined that there were a variety of countries that might be undesirable for oil companies to do business with. He furthered that there were jurisdictions within the U.S. that Alaska would probably never be "directly" competitive with, based on the cost of doing business in those areas versus the costs on the North Slope of Alaska. He concluded that he was struggling with the concept of how a determination was made regarding what was competitive, other than using strict dollar terms. Co-Chair Stedman added that Ireland and Greenland had very low government take on the regime competiveness slides, even though the two countries essentially had no oil. He furthered that the numbers could look attractive in these two areas, but that prospectivity was pretty low. Mr. Mayer agreed that the points made by Co-Chair Stedman and Senator Thomas were valid. He concurred that at the higher level of the scale, there were a number of countries that may be significantly less attractive destinations for investment; however, government take was only one variable regarding a destination's competiveness and desirability for investment. He related although some jurisdictions may have greater political risks or a higher government take, they might have resources that could be developed at minimal cost; therefore, in certain circumstances, projects remained attractive despite high levels of government take. He stated that Ireland and New Zealand had a very attractive fiscal regime, but that they did not have significant resources. He pointed out that Alaska did have a higher government take than regimes in the Lower 48; however, the costs in Alaska were also much higher, particularly for conventional onshore production. He shared that in Alaska, the competiveness difference was compounding because there was a higher government take and higher associated costs. He concluded that all of the aspects needed to be considered regarding a regime's competiveness, but that the slides examined government take because the committee had been relatively focused on that metric. He added that the slides excluded other factors and compared Alaska to other jurisdictions on the basis of government take. 10:04:10 AM Senator Thomas asserted that the production level "per well" was another important aspect to consider and inquired if Mr. Mayer agreed. Mr. Mayer responded in the affirmative. 10:04:23 AM AT EASE 10:05:37 AM RECONVENED 10:05:41 AM Co-Chair Hoffman pointed out that there was an article in that morning's newspaper that quoted the governor regarding his comments on commitments from industry. He related that the article had quoted the governor as saying that he would veto legislation if it did not include commitments from industry. He stated that he did not recall any commitments from industry in HB 110, and inquired if Co-Chair Stedman had received any communications from the governor regarding that topic or any proposed ideas of commitments. Co-Chair Stedman replied that he had not been contacted by the governor's office regarding industry commitments and stated that he was only aware of what he had read in the newspaper regarding that issue. He recalled that EXXON Mobile had testified that the state would need additional production every year matching the Oooguruk and Nikaitchug fields in order to flatten out the oil decline. He continued that Alaska's oil decline was $3 billion to $5 billion a year, and was not $5 billion over an eight or ten-year period. He related that the scale and magnitude that was discussed in the press and the magnitude of what was needed to flatten out the oil decline were not comparable. He opined that if additional production in the magnitude of Oooguruk and Nikaitchug was needed, the expectation of advancing production to 600,000 bbl/d on state lands was problematic; however, he was open to ideas of how to achieve that goal. Co-Chair Stedman noted that Iraq did not appear on any of the slides and inquired if Mr. Mayer had any comments on where Iraq would be on the list. He noted that Iraq had a service contract regime where companies were paid per barrel. Mr. Mayer responded that Iraq had a relatively high government take and that it was mostly due to the service contract fiscal structure for new developments involving international oil companies. He furthered that in Iraq's service contract system, a number of points were negotiated as part of the awarding of the contract and that international oil companies were paid for oil produced above existing levels of production. A country using the service contract system would have a set level of production that it was unable to go above; the country would then pay a company for the barrels that it could produce above that existing production plateau, but paid "very little" for anything below that level. Senator McGuire thanked Mr. Mayer for his hard on work on SB 192. SB 192 was HEARD and HELD in committee for further consideration. Co-Chair Stedman discussed the following meeting's agenda. ADJOURNMENT 10:09:37 AM The meeting was adjourned at 10:09 AM.