HOUSE BILL NO. 247 "An Act relating to confidential information status and public record status of information in the possession of the Department of Revenue; relating to interest applicable to delinquent tax; relating to disclosure of oil and gas production tax credit information; relating to refunds for the gas storage facility tax credit, the liquefied natural gas storage facility tax credit, and the qualified in-state oil refinery infrastructure expenditures tax credit; relating to the minimum tax for certain oil and gas production; relating to the minimum tax calculation for monthly installment payments of estimated tax; relating to interest on monthly installment payments of estimated tax; relating to limitations for the application of tax credits; relating to oil and gas production tax credits for certain losses and expenditures; relating to limitations for nontransferable oil and gas production tax credits based on oil production and the alternative tax credit for oil and gas exploration; relating to purchase of tax credit certificates from the oil and gas tax credit fund; relating to a minimum for gross value at the point of production; relating to lease expenditures and tax credits for municipal entities; adding a definition for "qualified capital expenditure"; adding a definition for "outstanding liability to the state"; repealing oil and gas exploration incentive credits; repealing the limitation on the application of credits against tax liability for lease expenditures incurred before January 1, 2011; repealing provisions related to the monthly installment payments for estimated tax for oil and gas produced before January 1, 2014; repealing the oil and gas production tax credit for qualified capital expenditures and certain well expenditures; repealing the calculation for certain lease expenditures applicable before January 1, 2011; making conforming amendments; and providing for an effective date." 1:36:48 PM AT EASE 1:38:33 PM RECONVENED KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE, introduced the PowerPoint presentation, "New Alaska Plan: Pulling Together to Build Our Future - Oil and Gas Tax Credit Reform - CS HB247(RES), Department of Revenue Presentation to the House Finance Committee, March 31, 2016" (copy on file). He addressed Slide 2: What We'll Be Discussing 1. History and Development of Credits 2. Credits- What Worked, What Didn't? 3. Credit Cost in Perspective 4. Overview of the Tax & Credit Calculations 5. Bill Summary- What is in the CS? 6. Changes from Governor's to Resources Version 7. Fiscal Impact of Changes 8. Summary of Scenario Analysis and Life Cycle Modeling: Economics of Changes 9. Implementation 1:41:00 PM Mr. Alper addressed Slide 4: History of Oil and Gas Production Tax Credits • First "modern" Oil and Gas credit was the Alternative Credit for Exploration (AS 43.55.025) passed in 2003 while Alaska still had the "Economic Limit Factor" (ELF) Gross Tax • Several added in 2006 with passage of the "Petroleum Production Tax" (PPT) and switch to net profits taxation. Included Cook Inlet tax caps as well as the first "state repurchase" provisions • Credits substantially modified with passage of "Alaska's Clear and Equitable Share" (ACES) in 2007; state repurchase made more open-ended • Cook Inlet Recovery Act and related legislation in 2010 • Frontier Basin credits added in 2012 • SB 21 passed in 2013, dramatically changed North Slope credits, replacing "spending" with "production" focus Mr. Alper elaborated up until 2006 Alaska's oil and gas production tax had been based on gross value and was known as the Economic Limit Factor, or ELF. During the ELF era the legislature added credits, most prominently the exploration credit, which was a percentage of a company's expenses that could be off-set from their taxes if they performed a desired activity. The credit regime was expanded in 2006, when the legislature passed the Petroleum Production Tax (PPT), which switched to net-profit taxation and added new credits as well as the Cook Inlet tax caps. The caps were a hold-harmless provision that was built into PPT that kept the Cook Inlet taxes what they were before the effective date of the tax bill. He said that the state began to cash out certain credits at that time. He said that the Alaska Clear and Equitable Share (ACES) bill in 2007 substantially increased taxes and was the moment when the repurchase of credits by the state became open-ended. Prior to that there had been a cap of $25 million, per company, per year. In 2010, the Cook Inlet Recovery Act and related legislation were passed. The act tried to encourage new exploration and development in Cook Inlet, mostly in light of supply shortfalls. Similar credits were added to the frontier areas in order to encourage people to look for and develop oil in undeveloped areas of the state, primarily the interior. He said that the North Slope oil tax rewrite, or SB 21, passed in 2013, eliminated the spending credits. All of the capital credits for the North Slope were replaced with a per barrel credit tied to production. 1:43:37 PM Mr. Alper turned to Slide 5 and continued to address the history of oil and gas production tax credits: · Credits initially added to encourage certain desired behaviors, tied to anxiety over declining production and a need for new investment · Later credits were added as core components / offsets of the net profits system · At times credits were layered on top of each other, creating unanticipated circumstances · Credits can either be used against tax liability, · sold / transferred to a taxpayer, or cashed out ("repurchased") by the state · Per AS 43.55.028(e)(4), a company producing over 50,000 bbl/day cannot have their credits repurchased by the state Mr. Alper relayed that the passage of SB 21 had been based on the desire for more exploration and putting new oil in the system. He said that the hope had been that new companies would invest in Alaska. He elaborated that eventually the new credits became "baked in" to the tax formula; higher taxes were designed to be off-set by large credits tied to capital expenditures or base production. He noted that the cashing out, or repurchasing, of the credits was the primary focus of HB 247. He noted that there were currently 4 major companies working at the 50,000 bbl/day in the state. 1:45:50 PM Mr. Alper moved to Slide 6, which listed a summary of the major credits in AS 43.55: Major Credits Available (current law): · .023(b) Net Operating Loss (25-45%) This is the main refundable credit on the North Slope and the largest statewide credit. "Stackable" · .024(i&j) Per-Taxable Barrel ($0 to $8) Only on North Slope Only can be used against tax liability · .023(a&l) Capital and Well Expend (20-40%) Only outside North Slope, usually refunded · .025(var) Exploration Credit (30-40%) Expires 7/16 in North Slope and Cook Inlet Extended in Interior / Frontier Areas until 2022 · .024(c) Small Producer Credit (up to $12 mil) Closed to new applicants in 5/16 Co-Chair Thompson asked Mr. Alper to avoid the use of acronyms, or to explain them. 1:49:39 PM Vice-Chair Saddler pointed to the spreadsheet provided by the department, "Table of Tax Credits under AS 43.55 - The Alaska Oil and Gas Production Tax and Comparison to Proposed Changes in HB 247" dated March 2016 (copy on file). He asked whether QCE was an acronym for Qualified Capital Expenditures, and WLE stood for the Well Lease Expenditure. Mr. Alper replied in the affirmative. He clarified that the .023(l) was the suite of well lease expenditure credits and the .023(a) was the QCE, or capital expenditure credits. Vice-Chair Saddler noted that consistent nomenclature would help to limit confusion while discussing the bill. Mr. Alper noted that the spreadsheet referenced the proposed changes to the bill and the credits; however, the spreadsheet had not been updated for the committee substitute currently before members. Representative Edgmon referred to Slide 6. He requested a breakdown of the 5 credit categories in terms of what the state was liable for monetarily in the FY 17 budget 1:51:37 PM Mr. Alper referred to Page 2 of the document, "Preliminary Spring 2016 Forecast Production Tax Credits Detail, FY 2007 to FY 2025" (copy on file). He explained that over the past few years the credits had been 50/50 between the North Slope and Cook Inlet. He said that the North Slope credits were comprised of approximately 90 percent operating loss credits, the rest were exploration and miscellaneous credits. The credits in Cook Inlet were split between the operating loss credits and the capital/well credits, in addition to a small amount of exploration credits. He stated that the credits used against liability in the North Slope were the per taxable barrel credit and a small amount of small producer credit. In Cook Inlet, because the underlying taxes were so low due to the statutory tax caps, there were very little actual credits used against liability. Representative Edgmon asked for a rough ball park number of the total that the state would pay in oil credits in FY 17. Mr. Alper replied that he could try to provide a number, but that the per taxable barrel credit was contingent on the price of oil. He noted that the price in FY 14 had been $600 million, but would be $28 million in FY 16. He asserted that it would be easier to "carve out" the refunded credits from credits against liability, of those, three-quarters were operating loss credits. Approximately 20 percent were the capital and well credits and less than 5 percent were exploration credits. Co-Chair Thompson welcomed Commissioner Hoffbeck to the testifier table. 1:54:20 PM Mr. Alper turned to Slides 7 and 8: Credits - What Worked, What Didn't? Some Credits have Never Been Claimed  · Middle Earth "New Areas" $6 million Credit (AS 43.55.024(a); part of HB3001/PPT, 2006) · Cook Inlet "Jack Up Rig" 100% Credit (AS 43.55.025(m); part of SB309, 2010) · Frontier Basin 80% Drilling Credit (AS 43.55.025(n); part of SB23, 2012) Companies did some of the activities incentivized by  these, but were able to get better results from  "stacking" other credits    All of these programs are sunsetting in 2016  Mr. Alper turned to Slide 9: Credits- What Worked, What Didn't?   To-date cost of Sunsetting Credits  Exploration Credits (various) 2007-sunset • North Slope Refunded: $270 million • North Slope Against Liability: $190 million • Non-North Slope Refunded: $160 million • Non-North Slope Against Liability: $0 Small Producer Credits 2007-2016  • North Slope Against Liability: $340 million • Non-North Slope Against Liability: $60 million • (these cannot be refunded) Total: slightly over $1 billion  Mr. Alper continued to Slide 10: Credits- What Worked, What Didn't? Credits Remaining if HB247 Passes  · Carried-Forward Annual Loss Credit  (also called "net operating loss") o 35% on North Slope and 25% in Cook Inlet and elsewhere (non-NS reduced to 10% by H(RES)) · Non-North Slope Drilling Credits  o "QCE" and "WLE" were repealed in governor's bill; maintained at 20% in H(RES) version · Exploration Credits outside North Slope and Cook  Inlet  ("middle earth exploration") o 30-40% depending on location o Sunset January 1, 2022 Mr. Alper addressed Slide 11: Credits- What Worked, What Didn't? · Cook Inlet Tax Caps  Oil tax of zero, gas tax averages 17 cents / mcf Sunset January 1, 2022 · Middle Earth Tax Caps  4% of gross value (first seven years of production that begins before 2027) · LNG Storage Facility Credit  Lesser of 50% of cost or $15 million · Refinery Infrastructure Credit  40% of cost up to $10 million/year per refinery, before 2020 Mr. Alper expounded that, as the state went about a new tax regime on the North Slope under PPT, it had been written in statute that the tax rates and the price of oil and gas stay as they were in the year before the effective date of PPT; the period between April 2005 and March 2006, which was what was used to establish the tax rate on oil and gas in Cook Inlet. He noted that HB 247(RES) would establish a working group that would explore a new tax regime for Cook Inlet, and other areas of the state, that will replace the sunsetting Cook Inlet tax caps. He elaborated that the LNG Storage Facility Credit would provide state assistance for major tanks for the Interior gas utility. 2:00:18 PM Vice-Chair Saddler queried the evaluation criteria that the department used to determine which credits worked and which had not. RANDALL HOFFBECK, COMMISSIONER, DEPARTMENT OF REVENUE, replied that there were three categories that had been determined: credits that had not been used at all, credits that had worked and had served their purpose, and those that had an ongoing need and were incentivizing activity; the governor had left those intact within the bill. Vice-Chair Saddler agreed that it was possible to assume that a credit that had never been claimed did not work. He asked about the second category. He wondered whether an analysis could be done to determine the effects of credits that had "served their purpose." Commissioner Hoffbeck answered that the department had not parsed out what portion of the credit's success had been due to lifting Regulatory Commission of Alaska restrictions on price, versus an increased price environment, versus the credits themselves. He said that the department had worked to determine the best places to continue to invest. 2:04:43 PM Vice-Chair Saddler lamented that the department could not provide an analysis on how they determined the areas affected by the credits and the extent of effect of the credits. Commissioner Hoffbeck replied that all of the changes in the Regulatory Commission of Alaska restrictions had occurred in a tight timeframe, and it would be hard to determine which credit drove gas exploration. He said that the $6 to $8 dollar price point for gas in Cook Inlet would be sufficient to incentivize exploration and development anywhere in the world, and would not need an underlying credit structure at that price point. Vice-Chair Saddler spoke to the goal of incentivizing without spending more than necessary. He hoped for evidence of a precise methodology that allowed the level of the credit to be set. Mr. Alper interjected that the overarching theory that the governor had hoped to maintain in the modified system moving forward was to protect the concept of the operating loss credit, which provided a level playing field between the incumbent and the new players. He said that the caveat of the fields in Cook Inlet being profitable was that there would be somewhere to sell the gas. He said that there would be no problem if enough wells could be drilled to produce the gas from the new fields correctly. But, if a well needed to be drilled every three years for lack of customers, the economics of the fields would be problematic and could result in the need for additional credit support. 2:08:09 PM Co-Chair Neuman queried the market conditions within Cook Inlet and exporting to Japan. Mr. Alper replied that the base utility consumption in Cook Inlet was approximately 80 to 90 billion cubic feet per year. He said that a trillion cubic feet was nearly enough to last 12 years for the utility market in Cook Inlet. He said that the exporting from the Conoco Phillips facility was sporadic and had no regular deliver schedule. He stated that the proven reserves held nearly a 15 year supply for that market, and those which had been claimed to be proven by producers would add several years to that. He thought that once drilling began there would be more than was initially claimed. He said that there was 1.2 to 1.6 trillion cubic feet that was known of in the ground, and much more was theorized: possibly 10 to 15 trillion cubic feet of gas. Co-Chair Neuman probed whether the state was getting a net loss or a net benefit from the credits. He hoped that the department could provide information on the measured value of the credits. Representative Gara spoke to the different types of fields that a paid profits tax, but that also got to write-off 35 percent from their taxable income. Mr. Alper answered that with the assumption that the price of oil was higher and the net profit tax was in play, the capital and operating spending would be subtracted from the price that was received from selling the oil. He relayed that the newer fields that were eligible for the gross value reduction had a further reduction from that figure on adjusted net; a 35 percent tax was taken from the adjusted figure. 2:12:11 PM Representative Gara referred to a past discussion about whether credits would work to get gas to Southcentral Alaska. He asked what portion of the credits were being paid for that had not been intended, mainly oil and gas in Cook Inlet that was being exported by Conoco Phillips. Mr. Alper answered that part of how Cook Inlet had adjusted to the supply uncertainty had been to downsize to base needs. He said that approximately one-third of the Cook Inlet credits had supported oil development, and two-thirds gas development. Representative Gara understood that the state received $.17 per million cubic feet for gas exported by Conoco Phillips. Mr. Alper replied in the affirmative. He said that all production from Cook Inlet was subject to the $.17 per million cubic feet price. He added that most producers in Cook Inlet fell into the category that qualified them for the small producer credit, which could off-set the $.17 down to zero. Representative Gara stated that one-third of the credits were paid for oil. He wondered whether year-to-year figures of the portions of the credits for gas that were exported to Asia could be provided by the department. Commissioner Hoffbeck responded that gas wells preferred to have a steady state of production. He said that the excess summer production did not have a market demand, versus something specifically developed for export. He thought that it would be difficult to attribute credits that may have been wrongly applied to summer gas and that the wells could not simply be shut off. Representative Gara contended that the intent of the credits had been to incentivize local production. He wondered how much money was being spent for producers that were exporting the gas. Mr. Alper replied that the department could study the issue. He asserted that looking at the demand in Southcentral Alaska monthly, rather than annually, showed that it could be 10 times as high in January as it was in July because people were heating their homes. 2:15:49 PM Vice-Chair Saddler felt that it was important to discuss the dynamics of natural gas production. He said it was not a zero sum game, and wondered whether the production of gas that was exported benefitted the production of gas for the state. Commissioner Hoffbeck answered in the affirmative. Vice-Chair Saddler asked whether a distinction could be made between incentives used to generate gas for consumption in-state versus what was exported. Mr. Alper replied that he was unsure that a distinction could be made other than applying the multiplier that he referenced earlier. He said that there was a successful credit that had yet to be mentioned: the Gas Storage Facility Credit. The credit had been part of the Cook Inlet Recovery Act, and had provided economic support to build underground storage that had enabled seasonal stability. Representative Pruitt spoke to credits in Cook Inlet. He asked whether any stipulations to gain the credits included listing gas as the specific resource. He believed both oil and gas would be produced in Cook Inlet, he worried that the credit might only be applied to gas. Mr. Alper answered that no stipulation had been made; oil versus gas had not been specified. He said that once drilling began the drilling credits became eligible for work-overwork, where and active well is modernized and improved. He asserted that companies understood the way that the credit worked. 2:19:18 PM Representative Gara asked whether the administration thought that the $0.17/mcf, or lower, tax on exported gas was fair to residents of the state. Mr. Alper clarified that the tax had been $0.17 since 2005, and had a 15 year lifespan written in to statute. He shared that the legislature had chosen to no change it. He said that in the development of the bill, the Governor had been careful not to change the Cook Inlet Tax Caps prematurely; although, Cook Inlet taxes on oil and gas would need to be comprehensively examined, and a long-term tax regime for Cook Inlet would need to be established. Commissioner Hoffbeck reference the discussion with Vice- Chair Saddler about credits that had not performed as well as expected. He expounded that oil was still "king" even though gas was important to the state; oil was more important than gas from the perspective of for-profit resource development. He stated that the fact that the credits could be used to incentivize oil production, in a regime where an oil tax was not being paid, was reflective of how the credits could be problematic. Representative Guttenberg reminded the committee that Alaskan's paid very high home heating prices, the most recent mild winter being an exception, and felt that the credits should be targeted towards in-state use of affordable, long-term energy. He assumed that the credits had been designed to affect the behavior of the industry. He noted that some people wondered about the effectiveness and transparency of the credits. He wondered whether the department would delineate which aggregated credits would monetarily benefit the state. 2:23:20 PM Mr. Alper responded that life-cycle modeling was included at the end of the presentation, and would speak to the question of what the state would receive, even without the production, and what would be the net benefit to the state over time. He opined that as prices fell the possibility that the state might never recoup money became an issue. He felt that the state could benefit in areas other than the treasury, such as employment and energy security. He added that the department faced challenges when addressing the nuances of the credits using the normally employed methods of analysis. Representative Guttenberg requested that the range of costs used in price models be included in future tax credit related presentations. Mr. Alper replied that the numbers would be provided. He asserted that the administration had worked to avoid the politics that usually surrounded the issue of oil taxes. He stated that part of the reason the state found itself in the current fiscal climate was because prices were very low, and past participants had not adequately considered what might happen with the tax structure when prices plunged for a prolonged period of time. He shared that there were oddities to the system at very low prices; when ACES had been before the body in 2007, people failed to examine what would happen when the price reached over $70 - $80 per/bbl. He stressed that what the administration was attempting to do was to put in place a system that worked at all plausible rage of prices. 2:25:41 PM Representative Pruitt understood that the administration was endorsing Section 31, which would establish a working group that would evaluate whether or not adjustments should be made with Cook Inlet credits. He wondered whether discussing those credits now was necessary since they would be analyzed by the working group in summer 2016. Mr. Alper responded that right now, state support for ongoing development work in Cook Inlet was at 50 to 60 percent. The state had spent $404 million on credits for the inlet in 2015. He said that gaining the support for the short-term desire of ramping down the Cook Inlet credits was necessary and important. However, even with the change it would still be important to discover what the tax would be in 2022, when the caps went away. He concluded that the primary purpose for the working group was for future planning and not for immediate gratification. Representative Pruitt asked whether the working group had been included in the legislation by the House Resources Committee. Commissioner Hoffbeck replied in the affirmative. He thought that the language had been included in response to credits being put back into the system. He felt that reviewing the credits was urgent. He pointed out that there had already been several working groups that had met on the subject, and felt that the issues had been fairly established. He hoped that all action would not be delayed until 2017 simply to accommodate another working group. Representative Pruitt asked whether the House Resources Committee would concur with the administration's summarization of the working group established in Section 31. Commissioner Hoffbeck interpreted that the House Resources Committee had felt that a working group would be necessary in order to further understand how to proceed with the credits in the future. 2:29:18 PM Vice-Chair Saddler stated that the legislature had been criticized for not forecasting a drop in oil prices when establishing the credits. He thought that it would be beneficial to research the credits thoroughly. 2:29:53 PM Mr. Alper spoke to Slide 13: Credit Cost in Perspective FY 2007 thru 2016, $8.0 Billion in Credits  North Slope · $4.4 billion credits against tax liability o Major producers; mostly 20% capital credit in ACES and per-taxable-barrel credit in SB21 · $2.3 billion refunded credits o New producers and explorers developing new fields Non-North Slope (Cook Inlet & Middle Earth) · $0.1 billion credits against tax liability o Another $500 to $800 million Cook Inlet tax reductions (through 2013) due to the tax cap still tied to ELF · $1.2 billion refunded credits (most since 2013) Mr. Alper continued to Slide 14: Credit Cost in Perspective Of the $3.0 billion in state-refunded credits through  the end of FY15:  • $1.45 billion went to six North Slope projects that now have production • $650 million went to 13 North Slope projects that do not have any production. Some of these are abandoned, and some are in process • $450 million went to six non-North Slope projects that have production • $450 million went to eight non-North Slope projects that do not have any production 2:32:47 PM Mr. Alper advanced to Slide 15: Credit Cost in Perspective   North Slope Refundable Credits  Of the $1.45 billion that was spent between FY07- FY15 supporting six producing projects: · Total production through end of FY15 is 38.5 million barrels · Total credits = $37.30 / barrel o This number will decrease over time due to additional production from these fields · Lease expenditures for these projects, through FY15, were $4.94 billion o Credit support was 29% of lease expenditures Mr. Alper turned to Slide 16: Credit Cost in Perspective Cook Inlet Refundable Credits  Of the $450 million that was spent between FY07- FY15 supporting six producing projects: · Total production through end of FY15 is 55.9 million BOE (much of this was gas) · Total credits = $7.80 / BOE or about $1.30 / mcf o This number will decrease over time due to additional production from these fields · Lease expenditures for these projects, through FY15, were $1.09 billion o Credit support was 40% of lease expenditures 2:34:42 PM Mr. Alper explained Slide 17: Credit Cost in Perspective Cook Inlet Tax Caps  · Estimated value to industry $550-$850 over the years 2007-2013 · Total Production Estimate o Gas: ~ 250 million cubic feet / day for seven years = 640 BCF of gas or 106 million BOE o Oil: ~ 10,000 barrels / day for seven years = 26 million BOE o Total Production = 132 million BOE · Using midpoint $700 million estimate, value of caps = $5.30 / barrel or $0.88 / mcf Mr. Alper stated that adding up the Cook Inlet tax caps and the direct credits reflected a $2.18 total for state support of gas development in Cook Inlet over the past 8 years. 2:35:47 PM Vice-Chair Saddler queried the total value of the oil produced for which the credits were earned from 2007 to 2015. He wondered whether the ratios of the total values to the value of the tax credits could be provided to the committee. Mr. Alper replied in the affirmative. He understood that Vice-Chair Saddler was requesting the specific resource that was incentivized thorough the credits; the oil and gas produced by the companies that received the tax credits. Vice-Chair Saddler asked for both options. Mr. Alper replied that he would provide numbers for all production; the $4.4 billion would be a function of a great bulk of the oil that was sold for Alaskans livelihood, the refunded credits would consist of the targeted, smaller numbers referred to in subsequent slides. Vice-Chair Saddler asked whether the state retained seismic 3-D and 2-D work and well data from wells that had been drilled using credits. Mr. Alper replied in the affirmative; if the work was incentivized with an exploration credit the data was made public after 10 years, which the Department of Natural Resources (DNR) used for marketing of state lands to entice future new investment. Vice-Chair Saddler understood that the information was retained in the Geologic Material Center, and was available to help the state in marketing for future lease sales and drilling programs. Mr. Alper understood that DNR had the data and could use it immediately for modeling and internal confidential purposes. He reiterated that the information would become available to the public after 10 years. Vice-Chair Saddler believed that explorers who were interested in doing business in Alaska would sign confidentiality agreements and visit the center to examine well logs and other data before making a bid. Mr. Alper said that the commissioner of DNR had tried to value the seismic and other data that the state had received. He said that the issue of seismic data was somewhat tied up in the impending sunset of the exploration credits. He said that depending on what the legislature did with the credits, the hope was to write into statute a continuing mechanism to ensure that the state could get the data should the exploration credits eventually end. 2:39:29 PM Representative Pruitt noted that the tax regime under SB 21 was in its infancy. He reference Slide 13, and probed the credit amount under ACES, versus SB 21. Mr. Alper responded that the type of company that had been eligible for refunded credits during the final years of ACES, was receiving approximately 45 percent of their expenses repurchased. He said that SB 21 had eliminated the capital credit and replaced it with the 35 percent operating loss credit and the sliding scale. He relayed that concern that a reduction from 45 percent to 35 percent could harm projects, a two-year hold harmless had been built into SB 21, which increased the net operating loss credit to 45 percent for calendar years 2014 and 2015. All of the credits that had been repurchased, to-date, from the North Slope had been at the 45 percent rate. He added that the credits against liability was the 20 percent capital credit under ACES, which was $3-4 million on a typical year, and allowed companies between $1.5 billion and $2 billion, per year, in allowable capital expenditures. He said that a comparable credit since the passage of SB 21 was the per barrel credit, which was over $500 million in FY 14 and 15 the two years it was in effect. The credit had dropped with oil prices; the per barrel credit was estimated at $28 million in 2016, and $16 million in 2017. Representative Pruitt asked whether the state could expect the refundable credits to decrease in the future. Mr. Alper replied that the department had expected the credits to remain the same; most companies that were receiving the loss credit were also getting the capital credit, holding the credits at the 45 percent level. He said that the credits were expected to decline to 35 percent and that the department's forecasted a decline in repurchase credit numbers. Representative Pruitt spoke of the hold harmless carry-over from ACES to the current structure under SB 21. He asked whether credits would be further reduced under SB 21. 2:43:31 PM Mr. Alper responded that the numbers had been rising. He said that $628 million had been paid in FY 15, which was the largest number of refunded credits the state had ever paid. He believed it was fair to say that the North Slope credits had been on a downward trend the last 3 to 4 years. Representative Pruitt pointed to Slide 14 and the $1.45 billion that had gone into the six producing projects. He queried the total amount that was spent on the projects. Mr. Alper responded $4.94 billion. Representative Pruitt asked how much the state could expect to receive for the $4.94 billion investment. Mr. Alper replied that it was highly contingent on the price of oil. He said that low prices were forecasted over the next 8 to 10 years, with very little revenue coming to the state from those smaller fields that had the tax reductions. Commissioner Hoffbeck thought that it was difficult to separate the credit related oil from the non-credit. Representative Pruitt whether the credit related oil included production tax, royalties, and property tax. 2:46:51 PM Mr. Alper replied in the affirmative. He explained that the modeling explored 3 different analysis: the production tax credits, the total state take of royalties, corporate income tax, and property tax, and the producer's economics. Representative Pruitt pointed to Slide 16. He understood that there had been no qualifying capital expenses from 2007 to 2010. He wondered why there had still been a fear of brown-outs in areas of the state when a boom had been going on in Cook Inlet. Mr. Alper answered that at the time PPT was being debated in the legislature, the Cook Inlet "Gas Wars" were underway. He understood that much of the conflict had been with the RCA; at the time the Southcentral facilities had been used to a long history of very low prices, but there had been a boom in prices in the Lower 48. He continued that proposals for gas sales contracts had been brought to the RCA, in order to try to match Cook Inlet to the Henry Hub price. He said that the RCA had rejected some of the contracts, which had led to disinvestment. He stated that the stage had been set for pricing issues of the gas supply. He said that brown out conversations made a storage facility essential in order to solve the seasonality issues in Southcentral Alaska. Co-Chair Thompson asked members to hold their questions until the end of the presentation. 2:50:44 PM Mr. Alper addressed Slide 19: Overview of Tax and Credit Calculations   How the Production Tax Works at $100 oil  Tax on a single barrel of taxable North Slope oil. We currently have about 160 million taxable barrels / year Market Price $100 Transport Cost $10 Gross Value $90 Lease Expenditures $35 Production Tax Value $55 Tax @ 35% $19.25 Per-Barrel Credit $6.00 Net Payment $13.25 Minimum Tax Gross x 4% $3.60 Higher Of (Actual Tax) $13.25  Approx. Annual Revenue $2.1 billion  Mr. Alper turned to Slide 20: Overview of Tax and Credit Calculations   At $70 Oil, the "minimum tax" takes over  Market Price $70 Transport Cost $10 Gross Value $60 Lease Expenditures $35 Production Tax Value $25 Tax @ 35% $8.75 Per-Barrel Credit $8.00 Net Payment $0.75 Minimum Tax Gross x 4% $2.40 Higher Of (Actual Tax) $2.40  Approx. Annual Revenue $380 million  Mr. Alper continued to Slide 21: Overview of Tax and Credit Calculations At $40 Oil, producers have operating losses  Market Price $40 Transport Cost $10 Gross Value $30 Lease Expenditures $35 Production Tax Value ($5) Approx. Operating Loss $800 million Tax @ 35% ($1.75) Per-Barrel Credit $8.00 Net Payment ($9.75) Minimum Tax Gross x 4% $1.20 Higher Of (Actual Tax) $1.20  Approx. Annual Revenue $190 million  Carried Forward Loss Credit 35% $280 million 2:55:15 PM Mr. Alper spoke to Slide 22: Overview of Tax and Credit Calculations $40 for second year means Operating Loss credits can  be used to reduce payments below the minimum tax  Year 1 Year 2 Market Price $40 $40 Transport Cost $10 $10 Gross Value $30 $30 Lease Expenditures $35 $35 Production Tax Value ($5) ($5) Approx. Operating Loss $800 million $800 million Tax @ 35% ($1.75) ($1.75) Per-Barrel Credit $8.00 $8.00 Net Payment ($9.75) ($9.75) Minimum Tax Gross x 4% $1.20 $1.20 Higher Of (Actual Tax) $1.20 $1.20 Approx. Annual Revenue $190 million $190 million Less Carried-Forward Loss Credit ($190 million) Actual Tax Payment $190 million $0 Carried-Forward Loss Credit 35% $280 million $370 million Mr. Alper relayed that the slide reflected the calculation of the high operating loss credit carry forward due to many years of expected low prices, which had been forecasted in the department's 2016 spring forecast. He qualified that this was the baseline scenario for legacy oil from the North Slope. He spoke to slide 23: · This is just the "baseline" scenario, for legacy oil from the North Slope. · Does not account for the fact that roughly 9% of production qualifies for the "Gross Value Reduction" new oil tax break · Can also provide example calculations for North Slope GVR Eligible Production as well as Cook Inlet scenarios Mr. Alper explained that 91 percent of the oil from the North Slope used the above calculation, the other 9 percent was new oil that qualified for the Gross Value Reduction (GVR), the difference being that at higher prices the tax would be lower. The new oil would not be subject to the minimum tax and could pay zero under current law. Mr. Alper addressed Slide 25: Bill Summary - What is in the H(RES) CS?: Exploration Credits    HB247 Proposed / Kept in CS  · Allowing the .025(a) "alt. credit for exploration" to expire on 7/1/16, for North Slope and Cook Inlet o 025(a) credits remain for "Middle Earth" until 2022 · Also allowing the "Jack up Rig" and "Frontier Basin" credits to expire at the same time · Preemptively repeal other exploration credit programs that are not currently being used, in AS 38.05.180(i) and AS 41.09. 2:58:53 PM Mr. Alper addressed Cook Inlet credits on Slides 26 and 27: Bill Summary- What is in the H(RES) CS? Cook Inlet Credits, Current Conditions  New Field Developer · Currently receives a 25% Net Operating Loss (NOL) credit stacked with either the 20% Capital (QCE) or 40% Well (WLE) credit. Generally a weighted average of the two "spending / drilling" credits · State typically refunds 50-60% of costs Existing Producer  · Currently pays low to zero taxes due to Cook Inlet tax caps, yet is eligible for 20% Capital or 40% Well Lease Expenditure credits · State typically refunds 25%-35% of costs Bill Summary- What is in the H(RES) CS?   Cook Inlet Credits, Changes in CS  New Field Developer  · NOL (Loss) credit reduced from 25% to 10% in 2017 · WLE (Well) credit reduced to 30% in 2017 and 20% in · 2018 (effectively repealing it) · QCE (Capital) credit remains until 2022 (anticipating sunset of Cook Inlet tax caps) · State will typically refund 35% of costs in 2017 and 30% in 2018 and beyond Existing Producer  · Tax caps remain until 2022. Continuation of 20% QCE credit means state will continue to refund 20% of capital spending CS sets path for broader Cook Inlet tax reform by 2022  3:01:49 PM Mr. Alper addressed repurchase limits on Slide 28: Bill Summary- What is in the H(RES) CS?   Repurchase Limits    Changes in Committee Substitute  · Adds an annual "cap" on per-company credit repurchases of $200 million · Multiple partners in the same project can each claim · $200 million. However, a single company cannot artificially split themselves to multiply the benefit · Cash flow protection in the case of a large "outlier" project such as proposed by Armstrong o Modeling showed annual credits from a similar project of up to $800 million Mr. Alper continued to Slide 29: Bill Summary- What is in the H(RES) CS? Repurchase Limits (cont'd)  Historic Notes on large annual credits:  Over the 2007-2016 history of the tax credit program: · There has only been one instance of a company who ever received > $200 million in a single year · Five times ever when one company received between $100 -$200 million in one year · 11 times ever when one company received between $50 - $100 million in one year Mr. Alper turned to Slide 30: Bill Summary- What is in the H(RES) CS? Remove Exceptions / Loopholes  CS retains two proposed changes to prevent  artificially inflated net operating losses  · Can't use GVR (new oil value reduction) to increase the size of a Net Operating Loss (has led to credits greater than 100% of loss) · If a municipal entity owns production and sells only a portion of that production to an outside party, only the pro-rata share of expenses can be deducted against revenue 3:05:49 PM Mr. Alper addressed slide 31: Bill Summary- What is in the H(RES) CS? Brief explanation of GVR / NOL Problem  (Sec. 12; AS 43.55.23(b)(2))  · CSHB 247 would prohibit the gross value reduction (GVR) from being used to increase size of net operating loss and by extension, the NOL credit · In the low oil price / low cost example shown on the next page, the net operating loss would be limited to the net value before GVR, which is $6 per barrel instead of $12 per barrel · The resulting credit is 35% of the actual net operating loss, reducing the credit liability to the State by 50%. For a GVR-field producing 10,000 taxable barrels per day, the difference is $7.6 million Mr. Alper elaborated on the topic of current law allowing the gross value reduction to increase a net operating loss credit (Slide 32). 3:08:18 PM Mr. Alper turned to Slide 33 and provided a brief explanation of municipal utility problem. If a municipal utility owned a portion of a gas field and used all of the gas to generate its own power, the gas would not be taxable. However, if a portion of that gas was sold to a third party, those sales would be taxable. Current law allowed all lease expenditures to be used to offset the comparably small amount of sales, which could potentially generate late credits. HB 247 proposed to limit the lease expenditure calculation to just the pro-rate share of the expenditures equal to the proportion of the gas that had been sold. Mr. Alper turned to Slide 34 and addressed other provisions: Bill Summary- What is in the H(RES) CS? Other Provisions  Interest Rate Reform  · Fixes a technical error in SB21 that prevents compound interest on underpayments and assessments. Since 2014 we have collected only simple interest · Interest rate remains 3% above federal discount rate Bankruptcy & Debt Protection  · Credit certificates can be used to satisfy obligations to the state for the company's oil and gas business before repurchase · Surety bond of $250,000 for developers, to protect unsecured creditors in event of default Mr. Alper 3:12:07 PM Mr. Alper addressed the changes made from the Governor's to the House Resource Committee version of the bill to the bill beginning on Slides 36: Changes made in House Resources · Kept and improved many of the technical fixes, including inadvertent "double dip" credit for new oil on the North Slope · Reduced Cook Inlet credits, with different emphasis and delayed phase-out · Increased repurchase "cap," limiting its impact to just very large 'outlier' projects · Removed all changes to minimum tax "floor," transparency provisions, interest rate increase, and several smaller provisions · New legislative working group to review tax regimes outside the North Slope Mr. Alper moved to slide 37, which addressed Cook Inlet credits: Changes made in House Resources Cook Inlet Credits  Original proposal was to repeal 20% Capital (QCE) and  40% Well (WLE) credits on 7/1/16, while maintaining  the 25% Operating Loss (NOL)  · Effectively, three substantial changes: 1. Timing: CS phased in the changes over 18 months, taking full effect on 1/1/18 2. Total: CS retained a 30% level of development support vs. 25% in original bill 3. Applicability: CS maintained 20% credit support for producers who earn a profit, vs. no support in original version. Means additional companies will still qualify for cash credits Mr. Alper continued to Slide 38: Changes made in House Resources Repurchase Limits  Original proposal added four limits to repurchase:  · Per-company / per-year cap of $25 million · Large companies, with annual revenue over $10 billion, are ineligible for credit repurchase · Percentage of repurchase tied to percentage of Alaska resident hire · 10-year carry forward sunset Impact of Changes  · A large percentage of projected savings were in these provisions, although tighter repurchase limits would increase the total amount of "carried forward" credits that could offset future production 3:16:38 PM Mr. Alper turned to Slide 39 and continued to address changes made to the bill in the prior committee: Changes made in House Resources Strengthen Minimum Tax  CS eliminated- items that impact legacy producers:  · Can't use an operating loss credit, to reduce payments below the 4% floor · This was the largest "added revenue" component · Prevent per-taxable-barrel credits earned in one month from being used against another month's taxes at true-up · Increase in minimum tax from 4% to 5% CS eliminated- items that impact new oil producers:  · Extend minimum tax to GVR-eligible "new" oil · Not allow small producer credit to reduce tax payments below the floor Co-Chair Thompson Mr. Alper addressed the fiscal impact of the bill beginning on Slides 40. He noted that the fiscal note for the bill was 5 pages. He said that the provisions of the bill could be broken out into three main sections: two related to spending, and one to increased revenue. He relayed that when originally proposed the bill would have had a total fiscal impact of $500 million, but the number had increased to $785 million after the spring forecast. He said that the bill would have little impact in FY 17 because it would not take effect until January 1, 2017, which would be halfway through the fiscal year. He stated that the provisions that deferred credits and hardened the floor had been removed. He said that the $200 million cap was the remaining credit deferring provision in the current bill, and did show as fiscal impact in the fiscal note because the department had not predict any companies would earn $200 million, or more, in the 6 year period covered by the note. He noted that FY 18 offered a more appropriate comparison because the bill would be more fully implemented. He concluded that the numbers on the slide reflected larger and more detailed fiscal note, with all of the associated narrative that had been previously provided to the committee. 3:22:27 PM Mr. Alper spoke to the spring forecast and the reason the numbers differed from fall 2015 to spring 2016 (Slide 42): Fiscal Impact Impact of Changes from Fall 15 to  Preliminary Spring 16 Forecast · Much lower prices for longer period means: o Larger company operating losses o Status quo, production tax goes to near zero as all of it is offset by NOL credits o Large carried-forward NOL's, $630 million after FY17 · Refundable credit estimate for FY17 increases by $200 mil o Larger company operating losses o Higher than expected work on exploration projects, before expected sunset this year (up to 85% on NS) Mr. Alper turned to Slide 43: In future years, our "status quo" credit forecast  appears to decrease.  This can't really be built into future budgets.  · Our credit forecast only includes "known" projects · Most "new" projects would add to the amount of projected credits · Credit projections use the same conservative methodology as DOR's production forecast Mr. Alper noted that the numbers would need to be recalculated if Armstrong continued forward with their project. He suggested continuing the next section of the presentation when more time could be made available. Co-Chair Thompson discussed housekeeping.