ALASKA STATE LEGISLATURE  HOUSE RESOURCES STANDING COMMITTEE  February 17, 2017 1:05 p.m. MEMBERS PRESENT Representative Andy Josephson, Co-Chair Representative Geran Tarr, Co-Chair Representative Dean Westlake, Vice Chair Representative Harriet Drummond Representative Justin Parish Representative Chris Birch Representative George Rauscher Representative David Talerico MEMBERS ABSENT  Representative DeLena Johnson Representative Mike Chenault (alternate) Representative Chris Tuck (alternate) COMMITTEE CALENDAR  HOUSE BILL NO. 111 "An Act relating to the oil and gas production tax, tax payments, and credits; relating to interest applicable to delinquent oil and gas production tax; and providing for an effective date." - HEARD & HELD Presentation: Agriculture - HEARING CANCELED PREVIOUS COMMITTEE ACTION  BILL: HB 111 SHORT TITLE: OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS SPONSOR(s): RESOURCES 02/08/17 (H) READ THE FIRST TIME - REFERRALS 02/08/17 (H) RES, FIN 02/08/17 (H) TALERICO OBJECTED TO INTRODUCTION 02/08/17 (H) INTRODUCTION RULED IN ORDER 02/08/17 (H) SUSTAINED RULING OF CHAIR Y23 N15 E2 02/08/17 (H) RES AT 1:00 PM BARNES 124 02/08/17 (H) Heard & Held 02/08/17 (H) MINUTE(RES) 02/13/17 (H) RES AT 1:00 PM BARNES 124 02/13/17 (H) Heard & Held 02/13/17 (H) MINUTE(RES) 02/17/17 (H) RES AT 1:00 PM BARNES 124 WITNESS REGISTER KEN ALPER, Director Tax Division Department of Revenue Juneau, Alaska POSITION STATEMENT: Provided a PowerPoint presentation entitled, "HB 111 Oil and Gas Production Tax and Credits Responses to Questions and Bill Analysis" and dated 2/17/17, and answered questions. ACTION NARRATIVE 1:05:58 PM CO-CHAIR GERAN TARR called the House Resources Standing Committee meeting to order at 1:05 p.m. Representatives Tarr, Parish, Talerico, Rauscher, Drummond, Josephson, and Westlake were present at the call to order. Representative Birch arrived as the meeting was in progress. HB 111-OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS  1:06:36 PM CO-CHAIR TARR announced that the only order of business would be HOUSE BILL NO. 111, "An Act relating to the oil and gas production tax, tax payments, and credits; relating to interest applicable to delinquent oil and gas production tax; and providing for an effective date." 1:08:07 PM KEN ALPER, Director, Tax Division, Department of Revenue, informed the committee the presentation on HB 111 would answer previously submitted written questions and continue to specific sections of the bill, which contain elements of legislation that has been previously proposed, and is perhaps familiar to some members. He introduced the four parts of the presentation. REPRESENATIVE BIRCH asked Mr. Alper if HB 111 is the administration's proposal and whether the bill has the governor's support. CO-CHAIR TARR, in response to Representative Birch, said the co- chairs have asked the administration to respond to the bill "in the same way that they provide the fiscal note. So Mr. Alper's analysis today is relative to that." MR. ALPER, in further response to Representative Birch, said the governor does not support or oppose the bill, and does not take a position on legislation as it works through the committee process; however, he related the governor has said additional changes need to be made in "the oil and gas tax credit world." The administration did not propose the bill, and he said his capacity today was to provide information and analysis. Returning attention to part one of the presentation, Mr. Alper advised there was an error in an earlier presentation and he would point out the discrepancies. He then turned to the question of government take, and stated $141 billion in oil and gas revenue, restricted and unrestricted, is the actual total of the amount collected since the beginning of the Trans-Alaska Pipeline System (TAPS), early in 1978. Since the state's tax policy switched to a net system, in the years 2007 to 2016, Alaska has received $64 billion. Referring to previous testimony advising government take should be one-third of oil and gas revenue, he specified that 33 percent of market value is too high because the market value of all Alaska oil was $527 billion, and the state averaged 27 percent from 1978 to 2016; a 33 percent share would put all of the development costs on industry [slide 4]. Of the wellhead value, also known as gross value at the point of production (GVPP), 33 percent share is too low, and he provided the corrected totals: total wellhead value of all Alaska oil was $347 billion and the state averaged 41 percent from 1978 to 2016. Of profits, 33 percent is too low. Based on data available since 2007, the divisible profit of all Alaska oil was $111 billion, and the state averaged 57 percent from 2007 to 2016, with federal take added to that. At the time of Senate Bill 21 [passed in the 28th Alaska State Legislature] total government take was expected to be around 65 percent at a wide range of prices, which reflects a two-thirds to one-third split; however, the federal take will never approach 33 percent following federal tax reform in 1987, and he explained the effects related to federal taxes. Furthermore, with a new federal administration, there may be additional decreases in federal taxes [slide 6]. 1:16:28 PM MR. ALPER presented a graph of state the share of petroleum revenue, based on market value that was unchanged from the presentation at the hearing on 1/30/17 [slide 8]. Slide 9 was a corrected graph of the state share of GVPP [wellhead value], showing a decline from 1998 to 2005; in a higher price, higher tax timeframe, the average state share of gross was about 47 percent, and now it is about 30 percent. In response to questions, Mr. Alper adjusted GVPP for cash credits limited to those earned on the North Slope. REPRESENTATIVE RAUSCHER asked for clarification on the corrections. MR. ALPER, referring to the graph on slide 9, said the corrected percentages are 40 percent, 47 percent, and 30 percent. In further response to Representative Rauscher, he explained during the creation of a new data set "a data point got dropped," which added royalty barrels in error. Continued to slide 10, he said the payment of cash credits is shown in blue crosshatch bars subtracted from state share. He stressed in the gross period, state share remains 40 percent, however, in the net profits system during high prices, state share averages 46 percent and during low prices, state share decreases to 27 percent, illustrating that tax credits have more impact at lower prices. REPRESENTATIVE PARISH asked whether the slide represents outstanding credits that have not been repurchased by the state. MR. ALPER answered the credits illustrated are actual cash out the door; further, he said the impact of unpurchased credits relates to credits from 2017 and are not reflected in slide 10. CO-CHAIR JOSEPHSON returned to slide 10, and asked whether the blue crosshatch bar for 2016 would be larger without the governor's veto of $200 million. MR. ALPER explained the governor put a cap on the repurchased credits at $500 million. There was an estimate that credits would reach $750 million, in fact, at the end of fiscal year 2016 (FY 16), the state paid $498 million worth of credit certificates, which was an appropriate number for FY 16. CO-CHAIR JOSEPHSON has heard in FY 16 there was turmoil related to the certifications. MR. ALPER further explained the governor's veto addressed the concept of the open-ended repurchase of credits, which brought a reaction from investors and industry; in fact, industry was correct in recognizing a change. Specifically in Cook Inlet, capital and well credits are tied to spending and applied for quarterly and approved; net operating losses (NOLs) require an annual tax filing due in March. When cash became limited, the Department of Revenue (DOR) bundled the credits and the NOLs, and that pushed certain credits into the next fiscal year. CO-CHAIR TARR asked Mr. Alper to clarify fiscal year and calendar year. MR. ALPER gave an example of a company that has an operating loss from work occurring in 2014, and files its taxes in March 2015, and DOR releases the credits in July. However, by the time the appropriation and banking activities transpire, payment is made in August 2015, which is FY 16 for a state expenditure tied to a company expenditure in calendar year 2014. CO-CHAIR TARR surmised the period of lower prices is also related. In addition, slide 10 does not illustrate tax credits used against tax liability. 1:28:36 PM MR. ALPER clarified a tax credit against liability is revenue that the state did not receive; the slide shows money that was actually received, and therefore includes the credits against liability. He continued to slide 11, which illustrated profits on a barrel of oil at $54 per barrel, as forecast for FY 18. The bill would reduce producer share from 29 percent to 27 percent, and increase state and municipal share from 56 percent to 58 percent. REPRESENTATIVE PARISH, referring to slide 11, asked why the federal share is reduced. MR. ALPER explained federal taxes are calculated after state take, and so federal take is "their piece of a slightly smaller pie." Adding additional information on the percent of value, he said at $50 per barrel, each percentage point of total value is worth about $90 million, and each percentage point of wellhead value is about $75 million. A change proposed in HB 111 would impact the per barrel credit and increase the state's revenue; therefore, every dollar shift is a change, and for non-royalty oil, $1 per barrel in added tax, or reduced credit, is $160 million. A 1 percent per barrel increase to a gross tax is about $65 million. To explain how the bill affects companies operating at a breakeven level, he said every 1 percent of profit is $1.6 million to the state for every dollar above "breakeven"; for example, if the breakeven is $40 per barrel, and the price of oil is $60 per barrel, every percent of profit taken by the state in increments would be worth $32 million [slide 12]. 1:34:01 PM REPRESENTATIVE BIRCH observed the state's royalty share is 12.5 percent, "so is it fair to say that the state actually drives twelve and a half times $90 million, or almost a billion dollars in that scenario?" MR. ALPER pointed out 12.5 percent belongs to the state after transportation costs are subtracted; in fact, the state gets 12.5 percent of the wellhead value. The earlier slides indicating the state received 30 percent included the royalty percentage plus production, corporate income, and property taxes. REPRESENTATIVE BIRCH restated his point is every increase in production is reflected in an increase in royalty share realized by the state. MR. ALPER said yes. Every dollar movement in the price of oil, over the course of one year, is worth $25 million to $30 million to the state. He turned to questions related to the economic limit factor (ELF) [passed in the 10th Alaska State Legislature] multiplier decline from 1998-2006. The data on slide 13 seeks to "carve out" the North Slope portion of total production because ELF was a North Slope multiplier. Within ELF legislation, every oil field had a different multiplier; during 1995-1997 the average ELF multiplier was 11.1 percent. The last column indicated lost or forgone revenue with a sum total of nearly $3 billion over nine tax years [slide 13]. CO-CHAIR JOSEPHSON inquired as to the lesson learned from the data provided on slide 13. 1:39:02 PM MR. ALPER said the oil tax system had not changed since 1989; the ELF formula was very complex, and formulas are based on expectations and assumptions, which degrade over time, and underperform. He opined slide 13 illustrates the tax system should be revisited at the time it begins to underperform. As an aside, Mr. Alper responded to a question on the cost of a lawsuit defending an executive order in 2005 modifying ELF. The state prevailed in the lawsuit, spending $486,000 in its defense to save $500 million. Returning to questions from the committee, he stated there were three earlier tax credits in the gross tax system: 1.) exploration incentive credit against royalty for exploration, now repealed; 2.) education tax credit from 1987 for contributions to qualifying institutions; 3.) alternative credit for exploration passed in 2003, designed to be used against liability, carried forward, or transferred or sold to another taxpayer [slide 14]. MR. ALPER directed attention to the oil and gas tax credit fund, the statutory language of which has changed since FY 09. Slide 15 illustrated claimed credits, expenses, and end year fund balance from estimated appropriations for FY 09 through FY 16. Based on oil price, the percentage was either 10 percent or 15 percent, and limited by a statutory cap. Had the legislature appropriated by the formula from FY 09 through FY 15, the fund would be dry - in a manner similar to today - except for industry's expectation that the state will repurchase the credits. 1:48:57 PM CO-CHAIR TARR surmised if the state followed its statutory minimum, there would have been a balance in the fund in certain years. However, if the tax system continues to allow credits, the state must make further appropriations to the oil and gas tax credit fund. REPRESENTATIVE BIRCH said there has been anecdotal discussion that the oil and gas industry invests around $6.5 billion to generate state revenue through its royalty share and taxes. He suggested DOR provide data that indicates whether the tax credits have been successful inducing smaller independents, production, and investment. MR. ALPER offered to provide aggregated information from the DOR, Tax Division, Revenue Sources Book and Forecasts (RSB), broken out by the deductible lease expenditures of taxpayers and the non-deductible lease expenditures by explorers. REPRESENTATIVE RAUSCHER stated another byproduct of industry investment, in addition to creating jobs, is the sales that are conducted in the process of doing business. MR. ALPER agreed the oil industry is critical to the Alaska economy in terms of employment and procurement, and is estimated to generate one-third of the state's economy. CO-CHAIR TARR pointed out slide 15 illustrates the difference between following statutory guidelines versus open-ended payments. 1:54:10 PM MR. ALPER stated slides 16 and 17 are updates to previous presentations. Slide 16 was a graph of production tax before credits, production tax net of repurchased credits, production tax after credits used against tax liability, including Cook Inlet credits, and NOL credits. As prices declined, credits become a negative in FY 15; in FY 17, the vetoed credits are deferred to FY 18, and thus are not a big impact. However, the credits reappear as a $900 million expense in FY 18. Also, the graph shows a blue line which represents carried forward NOLs of the major producers. Slide 17 was the same analysis on all oil and gas revenue. 1:57:22 PM REPRESENTATIVE BIRCH asked for a slide showing just the North Slope credits, because the high investment in Cook Inlet credits influences the data. The tax credit discussion needs to be centered on good and reliable information. MR. ALPER said DOR will provide the requested information, and advised the impact from FY 13 through FY 18 on the repurchased credits will be approximately one-half. MR. ALPER began the analysis of HB 111. He informed the committee most of the provisions in the bill have been previously debated in various formats - with the exception of Section 6 - and he referenced sections of the bill and pertinent proposed legislation [slide 19]. Section 1 addresses interest rates, and he noted the interest rate of 11 percent was changed in Senate Bill 21 to 3 percent over the federal discount rate, not compounded. The administration felt this rate was too low and the governor sought a compromise; however, the compromise in House Bill 247 [passed in the 29th Alaska State Legislature] changed the interest rate to 7 percent for a period of three years, and afterward reverting to zero. A zero interest rate means a taxpayer will not pay a tax assessment or settle a dispute, because no interest would accrue, and HB 111 solves this problem. He urged for an amendment so that a single interest rate would apply to all outstanding state taxes [slide 20]. There followed a brief discussion on how to facilitate a change to the interest rate related to taxes. 2:06:41 PM CO-CHAIR JOSEPHSON inquired as to whether an interest rate that applies for any type of tax would create a problem. MR. ALPER said all of the other taxes were paying at 11 percent from the '70s until 2013, and now pay 3.5 to 4 percent. Simpler taxes get audited faster if at all; however, if there are taxes due, the state should get a reasonable return, especially in the likelihood of the state spending Alaska Permanent Fund earnings to fund the operations of government, and permanent fund earnings are about 7 percent. REPRESENTATIVE PARISH questioned whether a change in the interest rate on all outstanding taxes would inspire taxpayers to initiate litigation. MR. ALPER was unsure. He opined an aggressive audit program is the most effective deterrent to elusive taxpayers. Turning to Section 2, he provided a graph illustrating the increase in revenue resulting from a change in interest from 4 percent to 5 percent. He noted an increase in the minimum tax tends to slightly increase the range of prices at which the minimum tax is in effect [slide 21]. Further, at $55 per barrel oil, the impact of a 1 percent increase is $50 million to $60 million per year [slide 22]. In response to Co-Chair Tarr, he stated at $80 per barrel, the Senate Bill 21 calculation generally governs, and the minimum tax is not in affect. This factor is concealed as the slide shows aggregated figures. 2:13:05 PM REPRESENTATIVE BIRCH said slide 22 illustrates the proposed tax increase on the oil and gas industry: at current prices, a $50 million to $60 million increase. 2:13:22 PM MR. ALPER said yes. In further response to Representative Birch, he said at current prices, this is the largest component of the state's revenue increased by the bill. He acknowledged the change in per barrel credits has an impact at higher prices, but at current prices, [the increase in tax rate] is the largest change in revenue. Changes in Senate Bill 21 prevented sliding scale per barrel credits going below 4 percent of GVPP; however, other credits, including NOLs, gross value reduction (GVR)- eligible per barrel credits, small producer credits, and alternative credits for exploration, can be used to reduce payments below the minimum tax. Current law allows all credits other than the sliding scale credits to reduce taxes below the minimum tax - commonly referred to as "the floor"; the bill seeks to prevent all other credits in AS 43.55 from reducing taxes below the minimum tax - commonly referred to as "hardening the floor" [slides 23 and 24]. MR. ALPER continued to explain the minimum tax in Section 3 addresses three different issues pertaining only to the North Slope: 1.) small producer credits for companies producing fewer than 50,000 barrels of oil per day in Alaska fields; 2.) per barrel credits for GVR oil, now that GVR is limited from three to seven years; 3.) NOLs for producers not eligible for cash credits can be carried forward and used to pay below the minimum tax - the most prominent issue surrounding hardening the floor [slide 25]. Mr. Alper then explained how GVR-eligible per barrel credits can reduce taxes below the minimum tax for legacy and GVR-eligible oil at $60 per barrel [slide 26]. 2:20:35 PM CO-CHAIR JOSEPHSON questioned whether the terms in House Bill 247 restrict GVR oil from going beneath the floor. MR. ALPER said no. House Bill 247 made two changes to GVR, but producers can use the $5 per barrel credit to reduce the tax to zero. CO-CHAIR JOSEPHSON asked if the foregoing issue was vetted and understood in 2013. MR. ALPER opined it was recognized that GVR-eligible oil would be allowed to go to zero. The issue is not a reduction of value, but whether GVR can reduce the value to a negative. He remarked: What we learned was that the gross value reduction could be used to artificially increase the calculated size of a loss, and in doing so could increase a net operating loss credit, and we started seeing some very distorted operating loss credits that were far greater than 35 percent of the loss - 80, 90, 100 percent of the loss - because of the multiplicative factor of being able to increase your loss with the GRV. That was inadvertent, without question. There was some substantial consensus in the committee process last year, and that was a feature that found its way into the final version of [House Bill] 247. CO-CHAIR JOSEPHSON surmised the foregoing is an example of "the stacking feature": legally using every credit to maximize a loss. MR. ALPER said the stacking feature is generally applying two or more credits to the same expense, and he provided an example. In response to Co-Chair Tarr, he gave an example of a company with a $20 million loss that has earned a 35 percent credit of $7 million; if the loss is modified by GVR and becomes a $50 million loss, the credit becomes $17.5 million, which equals a 90 percent tax credit. REPRESENTATIVE RAUSCHER surmised the bill erased NOLs altogether. 2:25:08 PM MR. ALPER said no. House Bill 247 directs GVR cannot be used to further reduce to a negative production tax value; Section 3 of HB 111 proposes the calculation of tax for GVR-eligible oil - 35 percent of net as adjusted, minus the $5 credit - would not be allowed to go below 4 percent of gross, which currently happens until the price of oil increases to about $69 per barrel. Therefore, currently new oil is not paying a production tax. He reviewed the current cashable credit policy related to NOLs and major producers: companies producing over 50,000 barrels per day - the major producers and Hilcorp - are not eligible to receive cash; NOLs for explorers and developers are allowable expenditures, thus spending is a loss; NOLs for producers occur when expenses exceed revenue due to low prices and/or investment. As estimated in the RSB, at least one major producer had an operating loss in 2015, and others possibly in 2016, thus $107 million worth of aggregated NOL credits are to be carried forward and used against tax liability between FY 17 and FY 19 [slide 27]. 2:29:19 PM MR. ALPER recalled hardening the floor and letting loss credits "roll forward" was recommended by a Senate working group in 2015, but due to market conditions for the industry and other considerations, legislation did not do so. He expressed DOR's technical concern with the bill, pointing out contradictory language related to credits and the application thereof, and he made a recommendation to address credits in various individual sections [slide 28]. Mr. Alper turned to migrating credits, addressed in Section 3, subsection (q), which prevents per barrel credits from being used in a month other than the month earned. He provided a slide listing the effects of migrating credits, and advised in a period of volatile prices, the bill seeks to "keep those per barrel credits in their own month" [slide 29]. Slides 30 and 31 were graphics depicting the effect of migrating credits. In 2014, during which prices were high and then dropped, by October the per barrel tax was at $8, reducing the tax after credits to about $60 million. By December, companies could use $1 from the $8 credit, and pay the minimum tax rate. For the year, the state received $1,522 million in production tax revenue; however, in November and December, there were $112 million in "forgone" per barrel credits. In April, DOR learned taxpayers had moved their credits to January 2014, and applied them to offset a month of higher oil prices. The state then refunded $112 million to industry, resulting in a reduction of production tax revenue to $1,410 million [slide 31]. Mr. Alper advised Section 3 of HB 111 intends to prevent migrating credits. He stressed the revenue or savings gained by preventing migrating credits cannot be reflected in the fiscal note, as the impact is only seen in calendar years such as 2014, although the problem could be exacerbated, and he provided an example [slide 32]. 2:38:43 PM MR. ALPER informed the committee Section 4 contains conforming language related to migrating credits and how to administer the new minimum tax. Section 5 addresses the NOL rate and he described prior changes in the North Slope NOL credit rate from 2006 through 2016. During the time of Alaska's Clear and Equitable Share (ACES) [passed in the 25th Alaska State Legislature] tax system, the NOL rate was tied to the base tax rate, thus at high prices and with progressivity, the effective tax rate was often higher than the NOL rate. Senate Bill 21 tied the NOL rate to the base rate, but the per barrel credit reduces the effective tax rate paid by producers to less than the NOL rate to explorers, as explained and illustrated on slides 33 and 34. The effect of HB 111 will move 35 percent to 15 percent, and mimic the effective tax rate as much as possible, as a 35 percent flat tax rate is too high. Section 6 amends how companies can earn a tax credit certificate for an operating loss credit. Currently, a certificate can be earned for capital spending, well lease expenditures, and NOLs. Credit certificates can be transferred to another taxpayer to use against that company's taxes. However, HB 111 restricts NOL credits so they are not eligible for state cash repurchase, but must be sold or carried forward. Mr. Alper acknowledged this is a very substantial change regardless of the tax rate [slide 35]. 2:43:44 PM MR. ALPER continued to Section 7. He directed attention to slide 36 that illustrated the amount of per barrel credit received in 2018, based on a range of prices. The effective per barrel credit changes in dollar increments following the wellhead value, until a wellhead value of $150 and above, when the per barrel credit is zero. At $50 per barrel, per barrel credits are zero, the minimum tax becomes equal or larger than 35 percent of net, and the minimum tax would govern. In Section 7, HB 111 proposes changing the calculation at prices between $80 and $110, so that the per barrel credit cannot exceed $5. This change is illustrated by the purple line and the dotted orange line on slide 36. Slide 37 further illustrated the change in minimum tax from 4 percent to 5 percent, the tax received under Senate Bill 21 with the sliding scale credit, and the 35 percent tax less the $5 maximum per barrel credit. The change in revenue is nearly $300 million at an oil price of $75 to $85 per barrel, and he concluded the tax increase affects a particular range of moderate prices, and less so at higher and lower prices. He continued to Section 8 which prevents a company from earning a cashable certificate for an NOL credit; Section 8 limits credits that are eligible for repurchase to Middle Earth and liquefied natural gas (LNG) storage and refinery infrastructure credits [slide 38]. Section 9 addresses how much cash per company per year can be spent, reducing the current limit from $70 million to $35 million. House Bill 247 allows a company to get cash from the state at a certain discount and subject to appropriation; HB 111 reduces the per company, per year limit to $35 million, and reduces eligibility for cash to producers below 15,000 barrels per day. He explained DOR's concern is that the change only affects explorers and developers in Middle Earth [slide 39]. He provided further information related to large annual credit payments made between 2007 and 2016, and pointed out of the existing $500 million in earned certificates issued by the state, three different companies are holding certificates of over $100 million [slide 40]. 2:48:11 PM REPRESENTATIVE BIRCH asked whether the aforementioned $500 million represents the credits authorized by the legislature last year and vetoed by the governor. MR. ALPER advised the authorization by the legislature was for $460 million, and $430 million was vetoed by the governor. Had the veto not occurred, at this time the state would be holding $70 million in uncashed credits. Finally, the material section of the bill, Section 10, prohibits GVPP from being below zero. He clarified wellhead value, under certain circumstances for an individual field, can go below zero when affected by expensive transportation, such as for a remote field, combined with low oil prices. If so, the negative value can offset value from other fields owned by the same producer; however, this is relevant only in unusual circumstances [slide 41]. He provided a slide that illustrated current tariff structures and pointed out the difference in tariffs is related to the distance of the fields to feeder pipelines and the Trans-Alaska Pipeline System (TAPS); marine transport costs are added. The Point Thomson pipeline is designed to carry 70,000 barrels per day which consequently raises the cost of transporting oil, thus the tariff from Point Thomson to the Badami connection is over $17 per barrel [slide 42]. Mr. Alper gave an example of gross value potentially going below zero, and restated Section 10, originally in previous legislation proposed by the governor, protects the state from a company using a negative number from other production in the calculation of its taxes [slide 43]. 2:55:47 PM MR. ALPER directed attention to the fiscal note identified as "Provisions in HB 111\O." The line item impact of the minimum tax increase from 4 percent to 5 percent results in increases of $25 million in FY 18, $75 million in FY 19, and $60 million in FY 20, which is the main revenue impact of the bill. In addition, in FY 18 and FY 19, there are increases from changes to credits effective 1/1/18, and from FY 20 to FY 22, increases from changes to per barrel credits effective 1/1/18. Total revenue impact is $45 million in FY 18, $75 million in FY 19, and $60 million in FY 20 in new revenue from the bill. Furthermore, there is the impact of reduced spending, such as no cash repurchase of NOL credits, resulting in spending (budget) impacts of $60 million in FY 19, and $120 million in FY 20. Total fiscal impacts are $45 million in FY 18, $135 million in FY 19, and $180 million in FY 20. He cautioned the reduced demand for credits comes with a state obligation for future demand for credits to offset future taxes, as indicated on the slide, cumulating in $225 million in FY 22. All of the estimates are based on the [RSB] Fall 2016 Forecast [slide 45]. Slide 46 illustrated the net fiscal impact of HB 111 with oil prices ranging from $20 to $120 per barrel of Alaska North Slope (ANS), in years FY 18 through FY 27. He concluded the impact of HB 111 decreases as the price of oil rises. Mr. Alper offered to provide comparative analyses on any forthcoming related legislation, amendments, and committee substitutes. HB 111 was held over. 3:03:18 PM ADJOURNMENT  There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 3:03 p.m.