Legislature(2013 - 2014)SENATE FINANCE 532
03/14/2013 09:00 AM FINANCE
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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." 3:18:31 PM Co-Chair Kelly MOVED to ADOPT the proposed committee substitute for SB 21, Work Draft 28-GS1647\Y (Bullock, 3/13/13). Senator Hoffman OBJECTED for the purpose discussion. SUZANNE ARMSTRONG, STAFF, SENATOR KEVIN MEYER, referred to "Proposed Changes in Senate Finance CS SB 21 Version 28- GS1647\Y" (copy on file). Maximum Base Tax Rate: Established in Section 9 (page 4, lines 30-31 and page 5, lines 1-11) January 1, 2014 - December 31, 2016: 35 percent Effective January 1, 2017: 33 percent Repeals Progressivity: No Change from Senate Resource Version No Change from Governor's Version Per Bbl Allowance: $5.00/bbl Established in Section 23 Gross Revenue Exclusion: Established in Section 30 (part of Section 12 as Payment of Tax) · Produced from a lease or property not within a unit on January 1, 2003: 20 percent In Senate Resources Version at 30 percent In Governor's Version at 20 percent · Produced from a participating area established after December 31, 2011: 20 percent In Senate Resources Version at 30 percent In Governor's Version at 20 percent · Produced from a well that has been accurately metered and measured by an operator and that DNR has certified was not contributing to production before January 1, 2013 (certified through required POD): 20 percent Net Operating Loss, Monetizable: Section 16, Section 17, Section 19 Monetizable or carry forward annual loss credit (in the amount equivalent to production tax rate): January 1, 2014 - December 31, 2016: 35 percent January 1, 2017: 33 percent Manufacturing Credit against State Corporate Income Tax: Established in Section 7 Provides for a manufacturing credit applied against a taxpayer's corporate income tax liability for a qualified oil and gas service industry expenditure that occurs in the state. · The total amount of credit may not exceed the lesser of 10 percent of expenditures or $10 million. · Must be a taxpayer to qualify for the credit. · Non-transferable · The expenditure cannot be the basis of another deduction under the Corporate Income Tax Law · Reduces the shelf life of the credit to five years Eliminates Qualified Capital Expenditure Credit: For Expenditures after 1/1/2014 Exploration Incentive Credit: Not extended to 2022 Will sunset July 1, 2016 Small Producer Tax Credits: Not extended to 2022 Will sunset 2016 *Small producers that currently receive the credit. If production started after April 1, 2006, then the small producer is allowed to take the credit for 9 years after the start of commercial production. Very likely that even though the credit sunsets in 2016, there will be companies that are allowed to take the credit in years after 2016. Interest Rate for Delinquent Taxes: Amended under Section 4 Adjusts how the interest is calculated on delinquent taxes: 3 percentage points above the annual rate charged member banks for advances by the 12th Federal Reserve District. Alternative to the greater than approach (current statute) or the lesser than approach (in Version 28-GS1647\P) Slide by Barry Pulliam of Econ One - 3/12/2013 Conforming Sections: 1, 3, 5, 6, 8, 14, 20, 31, 32, 33 Community Revenue Sharing Provision: Removes reference and tie to corporate income tax receipts. Does not change how the formula works, or distribution of funds. 3:24:47 PM Co-Chair Meyer requested an explanation of the fiscal note. MICHAEL PAWLOWSKI, ADVISOR, PETROLEUM FISCAL SYSTEMS, DEPARTMENT OF REVENUE, spoke to the fiscal note dated 3/14/13 at 12:10 PM. He related that while he had participated in the development of the fiscal note from a review standpoint, he had not developed the numbers himself; however, he could walk committee members through the components in the fiscal note in relation to the CS. He looked at page 1 of the fiscal note. He pointed to the inclusion of a $100,000 line item in the services section for 2014 that was for the revision in the interest rate that was in the CS and stated that although the Department of Revenue (DOR) was moving towards the adoption of the tax revenue management system, there was still work that needed to be done on the existing tax systems to reflect the change in the interest rate and the way it was levied with the tax system; the $100,000 was the cost of the department to implement the change in the interest rate. Mr. Pawlowski spoke to page 4 of the fiscal note, which was the table that itemized the 10 different pieces in the legislation that had a fiscal impact. He noted that the fiscal impact in the note did not include potential revenue impacts from potential increases in productions; the fiscal note was based entirely on the revenue forecast and the forecasted price of oil across the time period in the table on page 4. He pointed to FY15 on the second column and related that it was the first full fiscal year of the impact of the bill as the effective dates were designed in the CS; line 1 showed the revenue impact of eliminating the progressive portion of the tax, which was $1.5 billion in FY15. He furthered that line 2 showed that the increase of the bas tax rate from 25 percent to 35 percent would raise an additional $1.075 billion and would essentially generate $425 million less than what was being collected under progressivity. Mr. Pawlowski continued to speak to page 4 of the fiscal note. He discussed line 4, which depicted a further revenue increase to the state with the limitation of credits qualified capital expenditures (QCE) for the North Slope; this line represented the credits that were claimed against a tax liability and was projected to result in additional revenues to the state of $700 million in FY14. He spoke to the net operating loss credit increase to 35 percent for calendar years 2014 through 2016 and 33 percent for 2017 that was on line 4; these increases were refundable and were dealt with below in the operating budget component. He relayed that the gross revenue exclusion (GRE) on line 5 was provided as range, which was reflective of the fact that in order to qualify for the GRE in the CS, there were some portions that the Department of Natural Resources (DNR) needed to certify to DOR; there was a burden of proof by the industry and work that was conducted by DNR. He pointed out that the team at DOR had identified the possible potential range of projects that might, in "perhaps the worst case scenario," qualify for a GRE based on DNR's certification; in that year, it ranged from a low side of $25 million to a high side of $175 million. Mr. Pawlowski continued to address page 4 of the fiscal note. He pointed to line 6 and the provision requiring that credits that were taken over 2 years be eliminated. He explained that the credits were reflected in FY14, but because the North Slope capital credits were not continued, the issue did not add to the revenue impact in the note after that fiscal year; these credits were based on expenditures in FY13 that would be taken over 2 years under the existing Alaska's Clear and Equitable Share (ACES) system. He pointed to line 7 and related that the minus $250 million in FY14 was bringing an impact that would have been spread into FY15 in order to close out the state's obligation based on the expenditures. He related that the next substantive change in the fiscal note was on line 8, which reflected the $5 per taxable barrel (bbl) allowance; this would be a reduction in state revenue of $825 million in FY14. He stated that the credit under AS 43.20 for qualified oil and gas industry expenditures was indeterminate, but the more stringent language that Senate Finance Committee had adopted limited the potential range of companies that could qualify in expenditures; this effect dropped to $25 million and the credits were no longer transferable, but accrued directly to tax paying entity. He discussed line 10 and the reduction in the interest rate from federal funds rate plus 5 percent, or 11 percent, to the federal funds rate plus 3 percent; the effect of this was indeterminate, but was projected to be a $25 million reduction that would possibly rise over time as delinquent taxes or true-ups carried a bigger interest rate over a time period. Mr. Pawlowski continued to discuss page 4 of the fiscal note and stated that the total revenue impact in FY15 ranged from $575 million to $775 million. He pointed out that the range of the revenue impact reflected a combination of the impact of the GRE being applied to potential projects that were not currently contributing to production within existing units, the qualified oil and gas industry expenditures, as well as the interest rate provision; this was offset to a degree by the reduction in the next section and was an impact in the operating budget. He expounded that because qualified capital expenditure credits would no longer be offered on the North Slope under the current version of the bill, DOR projected that about $150 million less would need to be appropriated to the tax credit fund for the reimbursement of those credits; additionally, the subsequent reduction was an impact of the increase in the net operating loss credit rate to 35 percent and then 33 percent. He reported that the increase in the net operating loss credit rate was projected to add an additional $40 million to the operating budget and that the net operating impact was actually $110 million; DOR had wanted to reflect that increasing the rate for the net operating loss credit did have a cost. He discussed the bottom of page 4, which depicted a total fiscal impact of $465 million to $665 million in FY15. 3:33:52 PM Co-Chair Meyer noted that the fiscal note reflected an increase in the 3rd year out, which was partially due to the reduction in "base rate from 35 percent to 33 percent; on the other hand, the fiscal note did not include any new oil. Mr. Pawlowski confirmed that the note did not include possible new oil. He stated that the "bump" in FY14 of "775 to 875" was really the addition of line 6 on page 4, as well as the $150 million in the operating budget, which combined represented an additional $400 million impact to close out the outstanding qualified capital expenditure credits that were accrued based on expenditures before the effective date of the act. He stated that Co-Chair Meyer was correct that the note's increases in the out years reflected additional potential GRE eligible production along with the decrease in the base rate. Mr. Pawlowski directed the committee's attention to page 5 of the fiscal note and related that it was the standard scenario sheet that used to walkthrough the fiscal presentation that was given on the previous CS; he offered that members would recognize the same scenarios, but that based on the request of the committee, DOR had made a few modifications. He stated that the "At Forecasted Production" was depicted at different prices and that at $90 per bbl, the state would see roughly $75 million in additional revenue under the prosed CS over ACES in FY14; this number rose to $325 million at $90 per bbl, but in FY15 at $120 per bbl, that the CS would represent $925 million less revenue than ACES; these revenue impacts did not include other impacts of the bill, such as the removal of the credit split, the impact of the elimination of qualified capital expenditure credits, or the net operating loss credits. Mr. Pawlowski continued to address page 5 of the fiscal note and pointed to scenario B. He stated that the scenario represented 4 rigs being added within the legacy units, which were each drilling 4 wells that each produced 1,000 bbl at the begging of production with a decline of 15 percent. He explained that perhaps 50 percent of the incremental production might not be contributing to production, so the table for scenario B assumed that half of the oil qualified for the GRE; however, if oil did not qualify for the GRE, "this" number would be higher and "lower at the higher prices." Mr. Pawlowski discussed scenario C on page 5 of the fiscal note and stated that it kept the same GRE application for the 4 rigs, but also applied the GRE to the large new development; the scenario assumed and showed the fiscal impact of a large new development in a legacy field that received the GRE. He stated that the scenario showed that even at a price of $120 per bbl of oil, the revenues to the state would surpass what would have been collected under ACES by 2018 if ACES continued at the forecasted production. 3:37:32 PM Co-Chair Meyer remarked that 2018, or maybe slightly before that, was the breakeven point and inquired how many bbl of oil scenario C assumed. Mr. Pawlowski was unsure how many bbl it would be in that year and explained that the scenarios did not assume a set number of bbl, but instead built decline curves to mimic actual production within a field. He further explained that rigs would be drilling a well that declined at 15 percent a year and that the scenario C was more reflective of a realistic scenario. He added that the scenarios were modeled based on activity and production curves, but that he could provide the committee with that information. He stated that the reason the tables on page 5 were provided over a range of oil prices was to show the sensitivity of revenues to price. He pointed out that scenario B at the $100 per bbl price from FY15 through FY19 showed increases and related the scenario showed revenue increases of $225 million in FY15 at that price. He concluded that determining the state revenues was a function of the price of oil, the production, and the spending. Senator Hoffman looked at page 5 of the fiscal note and concentrating on 2017 through 2019 because it was the period that would show the long-term implications of the maximum base tax rate. He pointed out that the price was currently at $110 per bbl, but wondered if DOR had an idea of what the price would be in 2019; furthermore, the range between "425 and 1.3" was a wide range and the prices depicted went from $100 per bbl to $120 per bbl. He wondered what "those" impacts would be at the current price of about $110 per bbl. Mr. Pawlowski responded that he did not know offhand what the $110 per bbl number would be, but that he could have the number run for the committee; the reason that the $120 per bbl number was chosen was because the range in the forecast period rose in that time period in FY19 to about $118.29 per bbl. 3:40:44 PM Senator Hoffman stressed that the information about the impacts at current prices was very critical to the committee and that it would not be doing its due-diligence unless it saw those numbers from the department. Senator Hoffman addressed scenario A on page 5 of the fiscal note and directed the committee's attention to FY19, which was when the base rate would be at 33 percent; he inquired what DOR thought the state would be pushing across the table in scenario A if it assumed the forecasted production of a 50 million bbl field at a price of $110 per bbl if only one 50 million bbl field was developed. Mr. Pawlowski responded that he would have to run the $110 per bbl number. Senator Hoffman observed that the same question applied to scenario B and C in order to help the committee do its due- diligence before the legislation was moved on. Senator Hoffman directed the committee's attention to page 4 of the fiscal note and FY17 through FY19; he noted that that the maximum base tax kicked in at 33 percent in January 1, 2017. He pointed to the bottom lines of the FY 17, FY18, and FY19 columns and observed that at the high end, there was about $1.25 billion being pushed across the table in FY17; this number increased in FY18 and FY19 to $1.3 billion. He acknowledged that intent of stemming the decline and offered that he was willing to take risks; however, more information, particularly regarding "these other numbers," would be required because the stakes were tremendous at the high end. He expressed desire to see more oil, but warned that the risks needed to be assessed because the numbers were staggering. He requested that the numbers be depicted at a price of $110 per bbl of oil and opined that the numbers looked good when you only considered prices of $90 per bbl and $100 per bbl. He offered that the price of oil had continued to rise for the last 6 years. Co-Chair Meyer thought that it would be easy to find the point in between $100 per bbl and $120 per bbl and asked the department to provide the requested information. Mr. Pawlowski responded that he would do so. He directed the committee's attention to the fiscal line on the bottom page 4 of the fiscal note, which stated that the forecasted price ranged from $109.61 per bbl in FY14 to $118.29 in FY19 and explained that the generated number would look very similar to the trend that was in the fiscal note. 3:45:39 PM Senator Hoffman offered that at a price $110 per bbl, the impacts in FY18 and FY19 would probably be north of $1 billion. Mr. Pawlowski responded that this would be true for the forecasted production table in scenario A on page 5 of the fiscal note, but that DOR would generate the number for scenarios B and C where additional production would come into play. He added that it was a fair question and that DOR would generate the numbers. 3:46:35 PM AT EASE 3:46:56 PM RECONVENED 3:47:00 PM Senator Hoffman wondered if the numbers for when the GRE kicked in after 2019 could be run by DOR because he thought they would be significant. He acknowledged that normally a 5-year outlook was presented, but offered that the GRE could very substantially; furthermore, the number that included the effect of GRE needed to be considered, but was not included in the charts before the committee. He observed that the fiscal note had indeterminate amounts all the way across and that it would be nice to have the additional information when considering a piece of legislation so large. Co-Chair Meyer acknowledged that fiscal notes typically looked 5 years out and thought that it would be pretty speculative to ask DOR to forecast the note much farther out. He asked Mr. Pawlowski if Senator Hoffman's request was doable. Mr. Pawlowski stated that he would confer with some of people at DOR who generated those numbers in the long-term forecast and see what the range of "comfortabilities" was in providing those numbers. He recalled an answer that was generated by DOR for Vice-Chair Fairclough that had a breakdown of the under development, under evaluation, and currently producing bbl looking forward that would or could potentially qualify for the GRE; furthermore, the way the Senate Finance Committee's CS was drafted, there was a burden of proof within the legacy units to come to DNR to demonstrate through geological and geoscience means that "that" oil was not contributing to production in order to qualify for the GRE. He expressed that DOR wanted to careful not to assume that too much or not enough applied to the GRE, but that it was trying to over-assume what would apply for the GRE in order to be clear with the committee and public and put serious fiscal impacts on table for the committee to consider. He concluded that he would look at the request and get back to the committee with a response. 3:50:34 PM Co-Chair Meyer expressed frustration. He stated that the committee had been working on the bill during mornings and afternoons for 2 weeks and that DOR could have prepared the analysis past 5 years out if it had known that it was desired. Senator Hoffman WITHDREW his OBJECTION. There being NO further OBJECTION, the CS was ADOPTED as a working document. 3:51:58 PM RECECESSED 6:16:22 PM RECONVENED Co-Chair Meyer observed that Senators Stedman, Giessel, and Wielechowski were present in the committee room. 6:18:02 PM SCOTT JEPSEN, VICE PRESIDENT OF EXTERNAL AFFAIRS, CONOCOPHILLIPS (via teleconference), addressed possible confusion regarding a presentation that ConocoPhillips had conducted on February 28 and offered that there might be a misinterpretation that the comments about the future development activities that were mentioned in the presentation referenced a new initiative; however, the referenced activities were not incremental and were a continuation of what the company had already been doing. Furthermore, the presentation's activities did not represent a new initiative and was not something above and beyond what ConocoPhillips had been previously doing. He referred to a graph on slide 2 of a PowerPoint presentation titled "Senate Finance Committee CSSB21" (copy on file); the graph demonstrated that investment followed upside. He pointed out that Alaska had resources, but that it was hampered by the ACES tax regime; furthermore, the high progressivity in ACES was a tremendous impediment to increasing investment in Alaska. He offered that the graph showed that ConocoPhillips had a constant budget of $900 million per year the last 3 years in Alaska and compared this to Lower-48, which had high upside; ConocoPhillips' investment in the Lower-48 had grown from about $1.5 billion to close to $5 billion during the same 3-year period. He reminded the committee that these investments in the Lower-48 were in oil plays and not in natural gas plays; furthermore, ConocoPhillips was focusing its attention on oil plays like the Bakken and Eagle Ford. 6:22:44 PM BOB HEINRICH, VICE PRESIDENT OF FINANCE, CONOCOPHILLIPS (via teleconference), spoke in support of CSSB 21(FIN), but indicated that his company still had several areas of concern regarding the bill. He discussed slide 3 titled "Changes to ACES to Improve Alaska's Investment Climate." He related that ConocoPhillips had been advocating for the elimination of progressivity from the tax system, as well as the creation of a flatter tax rate over a broad range of prices; the third thing the company was advocating for was establishing a tax structure that created an attractive investment climate for Alaska. He discussed the need for a competitive tax rate and potential incentives for both legacy and new field development that would help balance Alaska's high-cost environment. He related that although ConocoPhillips' analysis of CSSB 21(FIN) was in its early stages, the progressivity and flatter tax rate concerns had been addressed well in the bill; however, there were still several areas of concern. He opined that CSSB 21(FIN) still represented a tax increase at lower prices, which was a result of the higher base tax rate; furthermore, the second issue surrounded the mechanics of how the new GRE language would apply within the legacy fields. He recalled comments that ConocoPhillips' CEO had made the previous week, in which he had stated that ConocoPhillips would do more in Alaska with the right tax framework. He concluded that ConocoPhillips was doing what it could in Alaska under the existing structure, but saw that it could do more if the appropriate changes were made. Co-Chair Meyer inquired if the bill had reached the point where it would create a climate that would spur additional investment and hopefully more production in Alaska. Mr. Heinrich replied that although CSSB 21(FIN) was an improvement over ACES that ConocoPhillips was pleased to see, the company would have to examine projects on a project-by-project basis; furthermore, because of the current structure of the legislation, ConocoPhillips could not say that the opportunity slate would improve across the board. He explained that some projects would be improved as a result of the bill, while others may not improve because of the loss of the tax credit structure. 6:26:10 PM Co-Chair Meyer recalled a graph that had depicted the breakeven point to be 70,000 bbls per day (bbl/d) and offered that another graph would show that figure to be closer to 55,000 to 60,000 bbl/d. He noted that the state would be looking at where it would find the additional new bbl of oil and hoped that the industry would provide some encouragement that the changes in CSSB 21(FIN) would result in 55,000, 60,000, or more bbl/d. Mr. Jepsen responded that ConocoPhillips was not at the point where it could tell the committee how much it would do differently if CSSB 21(FIN) was passed; additionally, CSSB 21(FIN) was a step backward from the previous version of the bill. He acknowledged that CSSB 21(FIN) was an improvement over ACES, but that ConocoPhillips could not currently state which projects would happen and which ones would not; whether projects went forward would depend on whether the investment climate in Alaska was sufficient to attract significant new investment dollars. He concluded that some elements of CSSB 21(FIN) would take more analysis to determine their impacts on investment decisions and spoke about the need to further examine the way the GRE was described in the bill. Senator Hoffman asked how long it would take ConocoPhillips to determine whether the bill would spur it to invest in Alaska, as well as what the size of the investment might be. Mr. Jepsen replied that the company would make those decisions as projects matured to a funding decision. He recalled that ConocoPhillips had stated that there were certain things it could do if HB 110 had passed because that bill had provided a high degree of confidence about the competiveness of Alaska projects over a broad price range and offered that "this one does not." He expounded that ConocoPhillips would have to look at projects in the context of the price outlook at the time of funding, other opportunities for investment, and how it competed on margin. He concluded that some projects would fare better under CSSB 21(FIN), while others would not. Senator Bishop remarked that the committee had worked hard on the bill, had done heavy lifting, and had moved the base tax rate almost 7 percentage points down. He understood the position of the oil industry, but offered that industry needed to understand his position with constituents and the people of Alaska. He thought that the ConocoPhillips' presentation would have had an additional slide with a check mark on the "increased activity box." 6:30:52 PM DAMIAN BILBAO, HEAD OF FINANCE, BP ALASKA (via teleconference), spoke in support of CSSB 21(FIN), but expressed concerns that the bill's base tax rate remained too high. He referred to his prior testimony on March 5, 2013 and recalled asking a question regarding whether the current CS to SB 21 made Alaska more competitive for investment. He explained that when BP made decisions every year about where to invest, there were many global options; furthermore, these options competed against each other on a fiscal basis for investment. He reported that currently, Alaska trailed other investment alternatives and failed to compete globally for investment and offered that PFC Energy had testified that a base rate of 30 percent with the $5 per bbl credit took Alaska from a lower tier of competiveness to an average level of competition. He opined that CSSB 21(FIN) raised the base rate back to 35 percent, which was well above the ACES rate of 25 percent, and lowered it to 33 percent after a few years; this made Alaska less than average in competing for investment globally. He stated that although the base rate in CSSB 21(FIN) remained too high, it made 2 significant steps forward in making Alaska more competitive; the first step was the elimination of progressivity, which was fundamental as an obstacle to making Alaska competitive for investment. The second positive change that CSSB 21(FIN) made was to the GRE, which would be applicable to legacy field opportunities as the bill was currently written. Mr. Bilbao stated that BP had always testified that the base rate of 25 percent under ACES was too high and offered that consultants had shown that ACES had made Alaska not competitive; over the last 7 years, investment had gone elsewhere and production had continued to decline. He concluded that Alaska currently failed to compete globally for investment and that BP welcomed that positive shift in the conversation to a policy focused on Alaska's future. He offered that CSSB 21(FIN) could work and that it addressed 1 concern regarding the GRE; however, the base tax rate remained too high in the legislation. 6:35:12 PM Senator Dunleavy requested an explanation of the comment that the base tax was still too high. Mr. Bilbao replied that the base tax rate would be too high to compete for investment and that the legislature's consultants had stated that Alaska did not currently compete. He offered that under the 25 percent base tax rate of ACES, Alaska trailed other global alternatives for investment and reiterated his prior comments regarding PFC Energy's testimony; furthermore, CSSB 21(FIN) took the base rate from 30 percent back up to 35 percent or 33 percent, which was less than average relative to alternatives for investment. Senator Dunleavy asked if the base rate was too high to compete and thus too high for BP to invest in Alaska. Mr. Bilbao responded that CSSB 21(FIN) did provide some good steps forward to making Alaska more competitive, but that BP felt that it did not go far enough to attract the type of meaningful investment that was required to make the future look different than the last 7 years or the current decline. Senator Bishop asked what the appropriate number on the base tax rate should be. Mr. Bilbao answered the legislature's consultants had shown what a 30 percent base tax rate would look like and had shown that at 30 percent, Alaska would be in the middle of the pack. He stated that Alaska had 2 fundamental challenges: the 1st was the fiscal policy that was not competitive and the 2nd was the high cost environment; therefore, if Alaska was simply average on fiscal policy, the high cost of operating in the state made it less than competitive globally. He concluded that Alaska would have to move beyond the middle of the pack in order to compete for investment and opined that this had also been asserted by PFC Energy, Roger Marks, and Econ One. Senator Bishop observed that consultants were not producing the oil in Alaska and inquired what BP's preferred number was. Mr. Bilbao replied that the consultants had done a good job analyzing how an average industry player would look at "this" and offered that the issue involved all of the players, not just the large producers. He furthered that the numbers that the consultants were presenting were showing a very good picture of what it would take to attract an investment and explained that the most recent analysis by PFC Energy reflected how BP would view the investment opportunities; a 30 percent base tax rate with a $5 per bbl credit still failed to move the needle for significant new investment. Senator Hoffman asked for verification that Mr. Bilbao had stated that a 25 percent base tax rate was too high to compete for investment. Mr. Bilbao replied that under an ACES structure, the 25 percent rate was too high, which is why Alaska did not currently compete globally for investment. 6:39:40 PM DAN SECKERS, TAX COUNSEL, EXXON MOBIL (via teleconference), spoke in support of CSSB 21(FIN), but offered that the bill's base tax rate was still too high. He spoke to the need for Alaska to create a stable fiscal regime that attracted the needed and desired investments and offered that it was most critical issue facing the state. He opined that while CSSB 21(FIN) made Alaska more attractive than ACES, the state needed to make itself as attractive as possible; being in the middle of the pack was desirable, but Exxon Mobile thought that being attractive should be the target. He reported that Alaska faced challenges and obstacles that other states did not and that the more attractive the state could make itself, the more investments would flow. He believed that CSSB 21(FIN) was a remarkable improvement over ACES and made Alaska more competitive and that the removal of progressivity, by itself, was a significant improvement over ACES; however, Exxon Mobile was concerned that the base tax rate in CSSB 21(FIN) remained too high. He offered that consultants had shown that Alaska was not competitive and that the fiscal regime was broken and needed to be fixed. He pointed out that imitation was the sincerest form of flattery and that he was not aware of any regime that had copied the ACES structure or any part of it. He expressed that Exxon Mobile was concerned that while CSSB 21(FIN) was encouraging, it might also be a regime that others would not duplicate because the base rate was still too high. He supported efforts of the committee and hoped that it would continue working to make Alaska as attractive as possible. Vice-Chair Fairclough remarked for the record that a major producer would not pay 35 percent and that the $5 per bbl of oil exclusion produced a reverse progressivity factor; the effective tax rate was much lower than the 35 percent base tax rate. She stated that the committee was doing the math and understood that the industry wanted projects to be competitive; however, she wanted the public to be aware that even though the base tax rate was 35 percent, a company that was producing oil would have a reduced effective tax rate. 6:44:47 PM Co-Chair Meyer noted that the committee had heard from industry that it was uncertain if CSSB 21(FIN) was significant enough to increase investment in Alaska. He pointed to a PFC Energy PowerPoint presentation titled "Senate Finance CS SB21 Analysis" dated March 14, 2013 (copy on file). He turned to slide 13 titled "Government Take Competitiveness - $100/bbl" and noted that it showed Alaska's government take competitiveness under the bill at approximately 65 percent for existing producers at the 35 percent base tax rate with the $5 per bbl allowance. He offered that the slide's chart appeared to show Alaska as being pretty competitive. He acknowledged that Alaska had disadvantages related to high costs, permitting, and weather conditions, but thought that it appeared that the current version of the bill put Alaska in the ballpark; he requested Mr. Pulliam and Mr. Marks to comment on whether CSSB 21(FIN) put Alaska in the "ballgame." BARRY PULLIAM, MANAGING DIRECTOR, ECON ONE RESEARCH, INC., referenced a slide that he had presented the prior day that had contained a series of investment metrics, such as the net present value, the internal rate of return, the government take, as well as the margin and depicted them across SB 21, CSSB 21(RES), and CSSB 21(FIN); the conclusion he had drawn was that CSSB 21(FIN) put Alaska in the ballgame. He explained that CSSB 21(FIN) represented a very positive change that should cause quite a bit of excitement regarding Alaska's fiscal system, particularly if it was viewed in conjunction with a commitment to stability. He opined that CSSB 21(FIN)'s changes did put Alaska in the ballgame and in a very attractive position. He pointed out that Alaska had a lot of resources left to offer and had billions of bbl of oil. He acknowledged that Alaska had some cost challenges, but offered that many of the areas that it was competing against globally had the same cost issues. He concluded one could not find very low- cost oil these days, but that it was all high-cost oil and involved challenges; the easy oil, for most part, had already been taken. He pointed out that the North Sea, the Lower-48, and Alaska struggled with the same issues and believed that when everything was put in context, CSSB 21 (FIN) would put Alaska in a good position to attract the capital it was looking for. Senator Dunleavy inquired what Mr. Pulliam had stated regarding excitement. Mr. Pulliam responded that there should be excitement over CSSB 21(FIN)'s changes from the standpoint of the investors, which would be ultimately measured in what investors actually did. He offered that the last 3 speakers had expressed a combination of excitement and a desire for a better deal, which he understood as a tax payer. He opined that it would be nice to hear from other entities pursuing projects in Alaska and thought that Armstrong Oil and Gas would be a good company to talk to. He offered that Armstrong Oil and Gas's testimony in both the Senate Resources and Senate Finance Committees had been very positive about the changes in CSSB 21(RES) and CSSB 21(FIN). He referenced changes in the United Kingdom and the excitement it had generating for the industry and opined that they were similar to the changes in SB 21. He reiterated that the success of the bill would ultimately be measured in what actually happened as a result. ROGER MARKS, LEGISLATIVE CONSULTANT, LEGISLATIVE BUDGET AND AUDIT COMMITTEE, referenced the first presentation he had provided to the committee (copy on file) related to getting Alaska's fair share; he had defined "fair share" as what one could get in a competitive environment. He stated that he had used the government take metric for his paradigm as the best apples to apples comparison. He reported that government take reflected the percentage of one's net income that went to government and that it automatically adjusted. He explained that government take reflected high costs or low costs and expounded that if there were high costs, there would be a lower net income. He pointed to a PFC Energy PowerPoint presentation titled "Senate Finance CSSB 21 Analysis" dated March 14, 2013 (copy on file) and slide 16 titled "Government Take Competitiveness." He thought that the slide's peer group was appropriate and represented the jurisdictions that Alaska was competing with on a number of parameters. He reported that his initial thought when looking across the competing jurisdictions was that Alaska wanted to be at about 62 percent government take and pointed out that the slide showed that under CSSB 21(FIN), low cost fields in Alaska were at about 60 percent government take, while the high cost fields were at about 64 percent. He thought that you would get more investment at a lower tax rate and less investment at a high tax rate; furthermore, he thought that the tax rates under CSSB 21(FIN) would lead to more investment and production than under ACES. He estimated that each percentage point of government take was worth about $140 million to the producers as whole annually and pointed out that each percentage was important; however, there was a lot variability in these numbers and it was impossible to be pinpoint exact. He stated that CSSB 21(FIN) would result in more investment than the current regime and it may result in more investment in new development in the legacy fields because of the 4 percent difference. He concluded that he judged that CSSB 21(FIN) was in the competitive ballpark of where Alaska needed to be. 6:54:31 PM Co-Chair Meyer pointed to Mr. Marks' breakeven analysis from the prior day and offered that it asserted that Alaska needed about 70,000 bbl/d of new oil. He asked if the bill would get the state another 70,000 bbl/d. Mr. Marks replied that the analysis had covered how much increased production the state would need over a 20-year period to breakeven with ACES on total petroleum revenues, including royalties, production tax, property tax, and income tax; however, that analysis had been predicated on the CS that had been before the committee the prior morning, which had 30 percent rate. He expounded that the breakeven point had changed to 50,000 bbl in CSSB 21(FIN) because of its 33 percent base tax rate; furthermore, he had made no representation in the analysis that the state would get the additional bbl. He pointed out that 70,000 bbl/d was really not that much given the resource base of 10 billion bbl on the North Slope. He could not guarantee that the per-bbl target would happen, but that it was a very reasonable target that could be exceeded, which would result in the state making more money than under ACES. Mr. Pulliam pointed to slide 2 of a PowerPoint presentation titled "Comments on Senate Finance CS SB21" dated March 14, 2013 (copy on file). He spoke to slide 2 titled "Average Government Take and Effective Tax Rate ACES v. SFIN CS SB21 for all existing producers (FY2015-FY2019)" and referenced comments by Vice-Chair Fairclough regarding the effective tax rate being lower than the base tax. He pointed to the bottom chart on the slide and stated that at the current price of about $110 per bbl of oil, CSSB 21(FIN), which was depicted by the green line, had an effective tax rate of about 28 percent when the per-bbl allowance was factored in. He reported that at a price of about $150 per bbl, the effective tax rate under the CSSB 21(FIN) would top out at about a 30 percent; these numbers were important to think about because one could not divorce the nominal rate from the allowance, but the 2 were designed to work in tandem to create the flat to slightly regressive curve on government take that was depicted in the slide's top chart. He offered that CSSB 21(FIN) was right about where ACES was in terms of government take at $80 per bbl, but had significant lower government take than ACES at the higher prices; he offered that these kind of numbers put Alaska in a good position. 6:59:42 PM Mr. Pulliam discussed slide 3 titled "Projected Fiscal Impact of SFIN CS SB21 Assuming No Production Change (FY2014 - FY2043)." He related that the slide's analysis examined the question of what it would take in terms of additional production to make up for the fiscal impact that was projected by DOR if a tax system was instituted based on CSSB 21(FIN); furthermore, the slide showed the fiscal impact for the 6 years that DOR calculated and then extended that out in time for another 30 years. He reported that DOR was projecting a fiscal impact of about $5.7 billion total, which was represented by the years that were above the line on the slide's table; he noted that the department's fiscal impact assumed no production change and offered that there should be a production change with lower taxes. He opined that if you carried that $5.7 billion total over 30 years, the total impact was about $20 billion. He stated that because the impacts were happening over time, the slide depicted money in current or real dollars, as well as nominal dollars and reported that the second column showed what the future dollars were worth in today's dollars; the $19.9 billion projection over the 30- year period actually reflected about $14.8 billion in today's money. Mr. Pulliam spoke to slide 4 titled "Additional Volumes Need to Offset Projected Fiscal Impact of SFIN CS SB21 (FY 2014 - FY 2043)." He related that the slide used the 50 million bbl field development model that Econ One had development and looked at the revenues that the state could expect at DOR's forecasted prices, which worked out to be about $105 per bbl over time in 2012 dollars. He pointed out that most of the expected new production would fall under the 1/6 royalty range, which was 16.67 percent; the older fields would have a 12.5 percent royalty. he had run the slide's analysis for both rates. He offered that all of the production for the 16.67 percent would probably qualify for the 20 percent GRE and pointed out that the slide assumed that the 33 percent base tax rate, the $5 per bbl allowance, and the 20 percent GRE would apply; it also assumed development costs of about $20 per bbl. Under the slide's assumptions, every bbl that was developed was worth about $35 to the state, which was about $25 in 2012 dollars. He reiterated that the fiscal impact in 2012 dollars was just under $15 billion, which would translate to about 590 million bbl that would need to be developed over the next 30 years in order for the state to breakeven on a revenue basis with ACES; this meant that the state would need about 20 million bbl per year in additional oil to bridge the revenue gap between CSSB 21(FIN) and ACES. 7:04:48 PM Co-Chair Meyer inquired what the daily equivalent of 20 million bbl per year was. Mr. Pulliam responded that adding 20 million bbl of oil per year equated to about 55,000 bbl/d. He offered that when thinking about whether 55,000 bbl of additional oil per day was realistic, it was important to think about the remaining resource base and observed that there were about 3 billion bbl of undiscovered conventional oil on state lands in Alaska; 20 million bbl represented a little less than 1 percent per year of the undiscovered resource. He concluded that over a 30-year period, the 1 percent still represented less than 30 percent of the remaining resources and that from a technical standpoint, 55,000 bbl/d in new oil should be a reasonable thing to accomplish. Senator Dunleavy inquired if Mr. Pulliam would be surprised to learn that in 3 years, there was little additional investment in Alaska above maintenance or routine investment. Mr. Pulliam replied that he would be surprised if CSSB 21(FIN)'s changes did not have an impact on attracting new investment. Senator Dunleavy inquired what Mr. Pulliam's advice would be to the committee if CSSB 21(FIN) passing did not lead to noticeable new investment. Mr. Pulliam answered that if increased investment didn't occur, he would look hard at what was still standing in the way of increased investment in Alaska. He pointed out that there were some things that were not under the state's control such as federal permitting issues and that those types of issues could potentially get in the way. He noted that the state was looking within itself to examine all of the things that it had control over and opined that the state did well on the permitting process. He thought that Alaska was pretty responsive in the areas that it had the ability to influence. Senator Dunleavy pointed out that the discussion on the bill the last several weeks had been centered on tax policy and how it would dictate investment. Mr. Pulliam responded that at the current price of oil, CSSB 21(FIN) represented a change in government take of about 10 percentage points, which was a significant shift and stated that he expected that the bill would attract interest and additional investment; if this did not occur in Alaska, it would be a "head scratcher." 7:09:44 PM Senator Dunleavy inquired if it would be a head scratcher, a surprise, or a shock if nothing happened in 3 years as a result of the bill. Mr. Pulliam responded that he would be a little of all of those and that he might be shocked; furthermore, if this occurred, he would want to take a look at why additional investment had not result from the bill passing. He added that other variables might be standing in the way of investment and that permitting issues would be applicable to both the ACES and the CSSB 21(FIN) systems; these other variables needed to be taken into account. He concluded that, outside of other variables, there was no reason to believe that the kind of changes in CSSB 21(FIN) would not increase investment. Senator Hoffman remarked that the committee had just heard from 3 of the major Prudhoe Bay investors and recalled that the commissioner of DNR had been very excited when the dialogue for the bill had started; he recalled making the statement that if the majors were not as excited, it would be very difficult for the committee to pass a bill that had close to a $10 billion revenue impact at the high end over a 6-year period. He pointed out that it had been stated that the major producers "wanted more" and wondered when these companies would stop saying they wanted more. Mr. Pulliam replied that he was unsure if they would stop saying that they wanted more and acknowledged the situations that the oil companies were in; they wanted the best possible rates that they could get and at the same time, were reluctant to offer a hard number. Senator Hoffman pointed out that he had been present when the Economic Limit Factor (ELF) had been discussed, as well as the other tax structures since; furthermore, the committee had heard from the majors during the discussion of ACES that the rates were too high and that they would not come and invest in Alaska. He continued that the rates were substantially lower in CSSB 21(FIN) and that the majors were still stating that they would not conduct additional investment in Alaska; furthermore, the majors "had kept their word at the other end" and he found it hard to believe that they would say anything else other than what they believed. He pointed out that Mr. Pulliam had his opinion, but that there were billions of dollars at stake. He pondered whether the committee should listen to the majors, "that told us the truth" during the discussions on ACES, or if it should "ignore them" today and pass the money across the table because Mr. Pulliam believed that being "south of the middle of the pack" would prompt the majors to come forward; he opined that this seemed to be a very high-stakes gamble and inquired if Mr. Pulliam would have the same opinion if he were representing the people of Alaska. 7:15:15 PM Mr. Pulliam responded that he appreciated the position that the committee was in and noted that it had to do the best it could by the citizens of Alaska in developing resources and maximizing them for the benefit of the citizens. He pointed out that he had been working with Alaska for several decades and that although he did not live in the state, he felt a strong connection with it; the health of Alaska was extremely important to him and he had approached the issue as an economist. He pointed out that the tools of economics dealt with motivations, financial motivations, and what drove investment and noted that the companies in Alaska were trying to make money. He asserted that it would be economically irrational to think that the kinds of changes in CSSB 21(FIN) would not improve and attract more investment that in turn would lead to higher production. He reiterated that he approached the issue an economist and examined markets and economic motivation. He offered that he had heard 2 things from major's testimony and opined that each of the 3 majors had said something a little different; he felt that it would be good to hear from "some of the other folks, such as the Armstrong Oil and Gas and Repsol; these companies had been very active over a number of years in acquiring leases in Alaska and moving towards development. He offered that Armstrong Oil and Gas, Brooks Range Petroleum, and Repsol viewed the bill's changes as very positive. He concluded that he could not offer the committee any guarantees, but could only provide economic a sound analysis; in conclusion, CSSB 21(FIN) would put Alaska in a good competitive position and ought to generate a response. 7:20:01 PM Senator Hoffman noted that if the bill passed, it was a guarantee that billions of dollars would move across the table and that the 3 major corporations had been truthful during discussions over ACES. He was unsure if those majors were not being truthful during the current proceeding, but knew for a fact that billions of dollars would cross the table. Senator Dunleavy inquired if it would be an anomaly if the investment that Econ One's models predicted did not occur and further queried if there were instances where the modeling had failed. Mr. Pulliam replied in the affirmative and expounded that there were instances where modeling had not predicted exactly what would happen; furthermore, modeling did not typically get the direction wrong, but sometimes got the magnitude incorrect. He explained that Econ One put its best efforts in and applied its experience to the modeling; however, he admitted that there could be a different outcome than what was predicted. He pointed out that DOR tried to be very diligent regarding its forecasts, but that numbers were different from what was forecasted, which was part of the process of forecasting. He stated that Econ One would be extremely "shocked" if the direction of its modeling regarding CSSB 21(FIN) was incorrect. He expounded that the bill made investment more attractive and that if investment either stayed flat or went the other way, it would be like "turning the laws of economics on their head." Mr. Pulliam discussed slide 5 titled "Additional Volumes Need to Offset Projected Fiscal Impact of SFIN CS SB21 (FY 2014 - FY 2019)" and related that it looked at the dollar amount that was in the fiscal note rather than the full 30- year period; the amount was $5.7 billion and would represent about a 200 million bbl need in additional production, which was a little bit bigger than the Nikaitchuq field. Co-Chair Kelly inquired how many bbl/d the 200 million bbl equated to. Mr. Pulliam replied that it worked out to be about 90,000 bbl/d for a 6-year window. Co-Chair Meyer expressed confusion and thought that the target was 50,000 bbl/d. Mr. Pulliam replied that he was trying to compress the previous slide into a 5-year window and examine how much production was needed to recover the fiscal note's cost in 5-years. He stated that 4 Mustang developments or little bit more than 1 Nikaitchuq field would be what the state needed. 7:24:18 PM Co-Chair Meyer handed the gavel to Vice-Chair Fairclough. BRUCE TANGEMAN, DEPUTY COMMISSIONER, TAX DIVISION, DEPARTMENT OF REVENUE, indicated that he would be addressing some the prior questions that were asked in committee. He provided a PowerPoint presentation titled "DOR Additional Information Requested: Prepared for Senate Finance: March 14, 2013" and shared that first several slides addressed questions that were raised regarding lease expenditures and how DOR forecast and listed them in the Revenue Sources Book. Mr. Tangeman discussed slide 3 titled "Lease Expenditure Forecast Methodology." · Request capital and operating lease expenditure projections from North Slope unit operators in the fall and the spring of each year in writing for the next five years from the current year · Meet with and request spending projections from companies that are not currently producing but have announced drilling and/or development plans · Review and coordinate with production forecast regarding anticipated developments outside the five- year time horizon received from operators · Update long-term capital and operating expenditure projections based on new information Mr. Tangeman spoke to slide 3 and related that the second bullet point was critical under the net tax system because there were companies in Alaska that were not producing, did not have a tax liability, but were spending in the state. Mr. Tangeman spoke to slide 4 titled "North Slope Projects Included in Fall 2012 Lease Expenditures Forecast." · Currently producing legacy fields · Includes ongoing cost of operating fields & maintenance capital · Includes facility upgrades and debottlenecking · Includes new wells and projects in legacy fields · Targeting new oil not in reach of production wells · Work-overs of existing wells · Advanced EOR projects · Four new fields in Fall 2012 production forecast · Point Thomson · CD-5 (Alpine West) · Mustang · Umiat · Exploration work at other prospects · Includes primarily announced exploration work only · Includes spending plans announced by companies like Repsol, Great Bear, and others · Does not include costs for development of possible discoveries Mr. Tangeman spoke to slide 4 and pointed out that it directly related to page 35 of the Revenue Sources Book where FY13 and FY14 were depicted. 7:27:55 PM AT EASE 7:38:40 PM RECONVENED Co-Chair Meyer resumed chairing the meeting. Mr. Tangeman continued to discuss slide 4. Co-Chair Meyer welcomed Senators McGuire and Micciche to the committee room. Mr. Tangeman discussed slide 5 titled "North Slope Operating Expenditures" and stated that it used the operating expenditures for FY12, and forecasted for FY13 through FY19; additionally, the numbers themselves were included on the slide of the packet. He pointed out that there were 2 lines on the slide; 1 line showed the total operating expenditures while the other showed only the operating expenditures that were associated with companies that had a tax liability. Mr. Tangeman discussed slide 6 titled "North Slope Capital Expenditures" and reported that it showed the capital expenditures in the same format at the previous slide from FY12, as well FY13 through FY19; additionally, on both slide 5 and 6, FY12 had been prepared using unaudited company-reported estimates. Mr. Pawlowski looked at slide 8 titled "Additional Oil Production Amounts." He related that there had been a previous question regarding the production scenarios and asking to expand the price ranges and the data points at which they were run; what was included in slide 8 was the actual numbers that went along with the production built into the scenarios. He reminded the committee that scenario A was the addition of one 50 million bbl field and related that the development took some time; the ramp up began at 2017 and peaked at 10,000 bbl/d in 2019. He shared that scenario B showed the addition of the 4 new rigs drilling within the legacy fields; each rig was drilling 4 wells per year, was producing 1,000 bbl/d, and had a decline rate of 15 percent. He continued to address scenario B and related that the production decline was why the production was not 32,000 bbl/d even though the initial production in FY14 was 16,000 bbl/d; "that" work continued in that scenario through till the end, and what was depicted was the incremental production added above the forecast by that scenario. Mr. Pawlowski continued to speak to slide 8. He stated that scenario C was the addition of 4 rigs working in the legacy fields and the expansion of the large development opportunity; what was depicted was "that" layered on top of the activity of the 4 rigs. He pointed out that the top chart showed the Fall 2012 Production Forecast numbers; it showed 538,400 bbl/d in FY12 for scenario C, declining to 421,600 bbl/d in FY19. He relayed that Scenario B, on the other hand, would go from 554,400 bbl/d to 472,000 bbl/d by FY19 and explained that DOR had wanted to provide the production data behind the fiscal analysis in order to allow members to see that there was built-in time and ramp up in decline in the additional and increased production that was used to build the slide's scenarios. Mr. Pawlowski discussed slide 9 titled "Scenarios: At forecasted production" and related that "these" would match page 5 of the fiscal note and the scenarios; at the earlier hearing, DOR was asked to run the numbers at $110 and $130 per bbl and provide the fiscal impact. He reported that slide 9 included no increased production. Mr. Pawlowski spoke to slide 10 titled "Scenarios: Scenario A" and pointed out that the scenario only added 3,300 bbl/d in 2017, 6,700 bbl/d in 2018, and 10,000 bbl/d by 2019; there was relatively little fiscal impact from that additional production because it was minor in scale. Mr. Pawlowski discussed slide 11 titled "Scenarios: Scenario B." He relayed that scenario B represented opportunities in the legacy fields and that the slide showed the different impacts of that at $110 per bbl, $120 per bbl, and $130 per barrel. He reported that at a price of $110 per bbl and with the additional activity in scenario B, the spread would go from $275 million less in revenue in FY14 and would maintain roughly that amount throughout the period of the projection; furthermore, it was important to note that these scenarios did not include some of the other items that were in the fiscal note such as the reduced operating expenditures associated with the capital credits that the state would not be paying, which would reduce any of those lines by about $110 million per year. Mr. Pawlowski addressed slide 12 "Scenarios: Scenario C." He shared that scenario C was the additional production scenario plus the additional pad. He added that it was important when viewing the scenarios, to keep in mind that they represented discrete production models that did not take into account additional work beyond those things and that they were intended to show committee members how production flowed through at the different price levels and the different analyses. Senator Hoffman directed the committee attention back to slide 9. He acknowledged that the slide did not include any new production, but that FY17, FY18, and FY19 were when the state would slide back to a 33 percent base tax rate. He thought that when ACES had been discussed, the range "back then" had looked at $70 per bbl to $100 per bbl of oil and that there had not been any real contemplation of anything north of that; however, the price had gone as high as $140 per bbl. He observed that the slide's formula showed a cost to the treasury in the neighborhood of $2 billion, or "a little south of that," in FY17, FY18, FY19 at $130 per bbl; even at $90 per barrel "that's substantially less." He offered that the price of oil was always an unknown factor, which had been the problem during the discussions on ACES and pointed out for the record that the fiscal ramifications of any formula, as well the amount of revenue the state would receive, was probably more dependent on the price of oil than on oil production. 7:48:10 PM Mr. Tangeman turned to slide 14 titled "Forecasted Oil Production on the North Slope" and related that the final question DOR would be addressing related to the production forecast. He thought that Senator Hoffman had requested the administration to extend the fiscal note a number of years farther, but pointed out that note included a forecast for the current budgeted year, which was FY14 and 5 additional years; furthermore, this was the standard operating procedure with fiscal notes. He shared that the reason DOR did not include the forecast farther out was because oil production forecasting was speculative and became more so the further out one tried to forecast. He pointed out for example that when ACES was being debated, the price forecast was projected to be around $60 per bbl for the following 5 years through FY12 and production was forecasted to be 675,000 bbl in FY12, which was a "miss" of 100,000 bbl. He pointed out that DOR and DNR's Division of Oil and Gas had taken great strides to tighten up the production forecasts going forward; his example showed how far off a production forecast could be with a just a 5-year outlook. Furthermore, the 5-year outlooks were developed with the best information that the state had available through discussions with the producers. He believed that a 5-year extension of the fiscal note itself, particularly relating to the scenarios on page 5 of the note, would be incredibly speculative; the scenarios were included as good examples of possible developments that were realistic in Alaska's future. Mr. Tangeman continued to speak to slide 14 and related that the information came directly from page 43 of Revenue Sources Book. The slide showed the different types of production that were included in DOR's 10-year production forecast; currently producing was the first column and was the category that DOR had the most confidence in forecasting. The decline rates were depicted and ranged from 10 percent to 7 percent. He relayed that the next column represented the risk adjusted new oil, which was the under development and under evaluation pools that were much more speculative; furthermore, in order to account for the speculative nature of this type of oil, DOR had risk adjusted it in its current forecast, which would hopefully steer the forecast away from "100,000 bbl misses." Mr. Tangeman spoke to slide 15 titled "Crude Oil Production -Forecast" and related that it came directly from page 105 of the Revenue Sources Book; the slide gave a little more detail of field levels over a 10-yuear period and was good information regarding where the bulk of the oil on the North Slope was coming from. Mr. Pawlowski discussed slide 16 titled "North Slope Lease Expenditures Fall 2012 Revenue Forecast" and stated that it gave the data behind the actual operating and capital expenditures that had been given earlier in the presentation. He reiterated the comments of Mr. Tangeman that given the timing of the request, that running the forecast for the scenarios an additional several years would require DOR to work with the committee to design a consensus around what levels or additional projects would be put in that type of scenario analysis; in other words, DOR was not going to put that information on the table without first coming to an agreement with the committee regarding the details. He concluded that given that time was a factor, DOR had attempted to be as responsive to the committee as it could. 7:52:43 PM Co-Chair Meyer thought that Mr. Pawlowski and Mr. Tangeman had both done an excellent job preparing the presentation in the short period of time that they had been given. He reiterated that if "this" had been known earlier as a concern, the committee would have requested the information several weeks prior. Senator Hoffman pointed to slide 16 [He most likely meant to say slide 15.] and noted that it showed Point Thomson kicking in some bbl of oil in 2016. He inquired if there was no anticipation in the production forecast during this time for CD-5 or Mustang to produce any oil through 2022. Mr. Pawlowski believed that the categories were aggregated to protect confidential tax payer information regarding specific projects and project related production; however, DOR had additional support online that could answer which one of the buckets that might or might not fall into. Senator Bishop thanked DOR for its time and work. Mr. Pawlowski responded to Senator Hoffman's question and related that CD-5 was in the Alpine section because it was part of the Colville River Unit. 7:55:15 PM AT EASE 8:02:56 PM RECONVENED Co-Chair Meyer addressed the CS and pointed to Amendment 1. Co-Chair Kelly MOVED to ADOPT Amendment 1, 28-GS1647\Y.7, Nauman/Bullock, 3/14/13 (copy on file). Vice-Chair Fairclough OBJECTED for the purpose of discussion. SENATOR LESIL MCGUIRE, related that the amendment represented a concept that was in CSSB 21(RES) that had been a part of many conversations in the building for several years as the legislature was trying to gauge Alaska's competitive with respect to other jurisdictions globally; the amendment created a competitiveness review board in Alaska that would provide an opportunity for Alaska to continually reflect on its position globally with respect to its competiveness in oil and gas. She shared that the idea for the amendment had occurred to her when she had been president of the Pacific Northwest Economic Region, which was a collection of western states, as well as provinces and territories in Canada and U.S. that worked collectively to develop their natural resources and improve their economies; furthermore, the province of Alberta, which shared many similarities with Alaska and was almost exclusively dependent on its natural resources for its budget, had undergone a very similar lifecycle to Alaska. She reported that when Alberta had instituted what they referred to as a "windfall profit tax," which was ACES in Alaska's case, it had seen the bottom fall out of its economy; this was similar to what many believed happened to Alaska, at least in part, as a result of adopting ACES. She explained that as a result of the windfall profit tax, Alberta had seen the investors that had been major supporters of its economy leave the jurisdiction to Saskatchewan, British Columbia, and other parts of the globe. In response to investment leaving, Alberta had established the Alberta Competiveness Council; she pointed to a report that was in members packets from May of 2011 from that council. She concluded that the model of the Alberta Competiveness Council gave her the idea that Alaska could benefit from something similar. Senator McGuire continued to address Amendment 1. She discussed a report from May of 2011 from the Alberta Competiveness Council and shared that it was important because Alaska had changed its fiscal regime 3 times in the last 6 years. She pointed out that in in every case of a fiscal regime change, the impetus had been politically motivated and had been a source of stress; furthermore, the changes were made in a compressed time period, in which law makers were working under accelerated timelines. She expounded that law makers did not often have a chance to examine all of the factors that may go into what made an economy competitive. She referenced earlier comments made by Mr. Pulliam in response to questions by Senator Hoffman and Senator Dunleavy regarding what would happens if Alaska did not see investment responses in 3 years after the passage of the bill. She offered that Mr. Pulliam's response that been that he would be shocked from an economic point of view, but that if nothing occurred, it would be up to the state to look at other factors, such as permitting and regulation; furthermore, this is exactly what had happened with the Alberta Competiveness Council. She expounded that with its review status, the Alberta Competitiveness Council had been able to provide recommendations to its jurisdictions that went far deeper than fiscal regime recommendations, which was what the legislature was tasked with; rather than examining taxes, the competitiveness review board would be looking at structural things, such as regulations, permitting, and infrastructure in order to identify how to stay competitive. She read an excerpt from the May, 2011 report from the Alberta Competitiveness Council: A competitive economy attracts industries and investment to the province, which create jobs and opportunities for Albertans. A competitive Alberta also leads to healthy and strong communities. Businesses that call Alberta home make important contributions to their communities and they help finance public services, like education, health, infrastructure, and environmental protection. Our province's competitive position, anchored by our abundant natural resources has fueled our growth and prosperity over the last decade; however, our continued prosperity is not assured. Alberta faces a growing number of competitors and shifting economic forces stand to impact our future success. We cannot rest on our past success and passively except opportunities to keep coming to our province. Senator McGuire offered that Alaska could be inserted instead of Alberta everywhere it appeared in the above excerpt. She pointed out that Amendment 1's competitive review board setup would consist of 9 members that included the commissioners of DNR, DOR, the Department of Environmental Conservation, as well as the Alaska Oil and Gas Conservation Commission; the other 5 members would be from the public and would be appointed by the governor. She explained the experience preferences of the public members of the competitiveness review board and related the board's members would serve without compensation, but would be eligible for per diem and travel expenses; the board's duties would be to review historical, current, and potential levels on investment in Alaska to identify factors that affect investment in oil and gas, as well to make recommendations annually to the legislature that would potentially increase Alaska's competitiveness; she reminded the committee that any action would be up to the legislature as lawmakers. She opined that the competitiveness review board would spark an interesting, reasonable, and thorough dialogue that would be ongoing and force the conversation each year, hopefully in a way that was non-political and less emotionally charged than the tax debates in recent years. 8:10:39 PM Co-Chair Meyer apologized and acknowledged that the concept for Amendment 1 had been CSSB 21(RES). He had originally thought that the competitiveness review board was a great idea, but had thought that it might be better served outside of SB 21; however, he understood the linkage between the Amendment 1 and SB 21 now and was fine with it. Vice-Chair Fairclough recalled that one of the considerations when the committee had fist received the bill was that the competitiveness review board had to a $1.8 million fiscal note attached to it; however, Amendment 1 was much less intrusive financially. She hoped the committee would consider adding the amendment the bill. Co-Chair Meyer thought that Amendment 1 had now had a fiscal impact of $34,000 for the first year, which was better than the previous request. Senator Olson asked what the results of the Alberta Competitiveness Council had been. Senator McGuire replied that the results had been positive and that if you looked at when Alberta's decline rate had started in 2009 on Econ One's and PFC Energy's presentations, you could see the that the curve had been redirected. She related that the parliament in Alberta acting on the recommendations of the Alberta Competitive Council had been directly responsible for redirected the decline curve; besides the tax policy, Alberta had established measures to regulate and access Alberta's regulatory performance in the areas of oil and gas and had increased weight limits to provide the safe transportation of higher density modules. Alberta had also identified new economic opportunities to commercialize innovative technologies in the area of the oil and gas industry and workforce development. She concluded that the Alberta Competitiveness Council had been very effective. 8:13:30 PM Senator Olson noted that initially, the competitiveness review board had been slated to meet 4 times per year and inquired how often it would meet under Amendment 1. Senator McGuire replied that the board would meet once annually and would issue 1 annual report, which was in fact consistent with the Alberta Competitiveness Council; this reduction had affected the fiscal impact. She noted that she had been delighted to work on that compromise with the co-chairs. 8:14:13 PM AT EASE 8:15:18 PM RECONVENED Co-Chair Meyer asked for additional comments related to Amendment 1. Vice-Chair Fairclough WITHDREW her OBJECTION. There being NO further OBJECTION, Amendment 1 was ADOPTED. Co-Chair Meyer pointed to the 3 fiscal notes attached to the bill. Co-Chair Kelly MOVED to REPORT CSSB 21(FIN) out of committee as amended with individual recommendations and the accompanying fiscal notes. CSSB 21(FIN) was REPORTED out of committee as "amended" with a "do pass" recommendation and with two new fiscal impact notes from the Department of Revenue and one new indeterminate fiscal note from the Department of Natural Resources. Co-Chair Meyer discussed the schedule for the following meeting.