ALASKA STATE LEGISLATURE  HOUSE RESOURCES STANDING COMMITTEE  February 13, 2017 1:00 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 DeLena Johnson Representative George Rauscher Representative David Talerico MEMBERS ABSENT  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 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 WITNESS REGISTER LISA WEISSLER, Staff Representative Andy Josephson Alaska State Legislature Juneau, Alaska POSITION STATEMENT: On behalf of Representatives Josephson and Tarr, co-chairs of the House Resources Standing Committee, sponsor, provided a presentation related to HB 111. ACTION NARRATIVE 1:00:46 PM CO-CHAIR GERAN TARR called the House Resources Standing Committee meeting to order at 1:00 p.m. Representatives Tarr, Birch, Drummond, Parish, Rauscher, Talerico, Westlake, and Josephson were present at the call to order. Representative Johnson arrived as the meeting was in progress. HB 111-OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS  1:02:09 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." 1:03:04 PM LISA WEISSLER, Staff, Representative Andy Josephson, Alaska State Legislature, on behalf of Representatives Josephson and Tarr, co-chairs of the House Resources Standing Committee, sponsor of HB 111, provided a brief personal background related to her involvement with Alaska's oil and gas resource law for the past 36 years, beginning with her participation during debate on the Petroleum Production Tax (PPT) [passed in the 24th Alaska State Legislature], and instituted in 2006. In the context of HB 111, she said she compiled a history of tax credits in order to aid the committee's understanding of the bill. Ms. Weissler paraphrased from a document entitled, "Alaska's Oil and Gas Production Tax [ - ] Tax Credits History," and dated 2/13/17, provided in the committee packet as follows [original punctuation provided]: The Petroleum Production Tax (PPT) In 2006, after fifty-one years of a gross value oil and gas production tax, Alaska switched to a net profit tax system known as the Petroleum Production Tax or "PPT." Reasons for the change included that the existing gross tax system resulted in almost no production tax revenue from even very productive fields; the system was unable to adjust for increasing oil prices and differences in field conditions between the North Slope and Cook Inlet; and it provided insufficient incentives for investment in Alaska's oil and gas fields. The PPT was intended to increase Alaska's share of oil production revenue and provide incentives for oil and gas companies to invest in the state. Major Producers' Incentives. It was believed that the tax advantages of the net profit system would increase the major producers' (ExxonMobil, BP, ConocoPhillips) investment in enhanced production from the large legacy Prudhoe Bay and Kuparuk oil fields. A taxpayer could deduct certain operating and capital lease expenditures as part of the calculation for determining their tax liability. In addition, the PPT offered a 20 percent tax credit for qualified capital expenditures. In effect, the more a producer spent in Alaska's oil fields, the lower their tax. Independent Companies' Incentives. The PPT offered several tax credits to encourage independent companies to explore for and develop smaller oil fields. Companies could accrue the 20 percent credit for qualified capital expenditures, including exploration costs. In addition, a producer with less than 100,000 barrels production per day could qualify for up to a $12 million tax credit provided the producer had a positive tax liability. The PPT also provided a credit of up to $6 million annually for oil or gas produced from leases outside Cook Inlet and the North Slope (known as "Middle Earth"). Net Operating Loss. The PPT provided for a carried- forward annual loss credit, referred to as net operating loss (NOL). Net operating losses are lease expenditures that would be deductible except when the deduction would cause the net value of taxable oil and gas to be less than zero. A percentage of the lost deductions are converted to tax credits that can be applied against future tax obligations. The PPT provided for a 20 percent net operating loss credit. The NOL credit was introduced primarily as a benefit to independent companies who would not have enough oil production to generate a tax liability against which to apply their lease expenditure deductions. The major producers were expected to have enough production tax liability to realize the full benefit of their deductions in the year the expenditure occurred. Tax Credit Purchase. Because explorers and new producers would not produce enough oil or gas to have much of a tax liability against which to apply tax credits, independent companies doing business in the state asked the legislature to establish a credit purchase program. As originally introduced, the PPT legislation allowed certain tax credits to be transferred and traded on the open market. Since the market was limited to the three major producers, independent companies were concerned they would not receive full value for their credits, while the buyer could apply 100 percent of the credit against the buyer's tax liability. The final PPT included a provision for the state to provide for the purchase of certain tax credits. Because legislators and administration officials worried about the potential impact to state revenue should oil prices drop, purchases were limited to companies producing not more than 50,000 barrels of oil per day and there was a $25 million cap per company. In addition, an applicant was required to incur a qualified capital expenditure or be the successful bidder for a state oil and gas lease within 24 months after applying for a transferable tax credit certificate. The purchase payment could not exceed the total of the expenditures or bid. Tax credits that qualified for purchase were the net operating loss credits, qualified capital expenditure credits and credits offered under a 2003 exploration credit program. 2007 Alaska's Clear and Equitable Share (ACES) In 2007, changes were made to the PPT under the Alaska's Clear and Equitable Share Act or"ACES." The changes were made because of lower tax revenue from higher than anticipated lease expenditure deductions. A corruption scandal that tainted the vote of several legislators during the PPT debate led legislators to be more receptive to making changes. Though the administration considered switching the tax system to a gross value tax, they concluded that a gross tax was not flexible enough to address the differences between oil and gas fields, and didn't account for expensive resource development such as heavy oil. Among other things, ACES retained the PPT tax credits and cash purchase program; and established an oil and gas tax credit fund to pay for the credits. The Oil and Gas Tax Credit Fund and Credit Purchases ACES established the oil and gas tax credit fund as a way to purchase qualifying credits more efficiently. The amount of money available to the fund was based on a set percentage of production tax revenue; 10 percent when oil prices were $60 or more, 15 percent when oil prices were less than $60. The $25 million cap established under the PPT was repealed. The $25 million per company cap was lifted because small producers found the cap too low to be useful. In response to legislators' questions regarding what would happen to the fund if oil prices dropped, an administration official explained that regulations would determine how to allocate payments when there was an insufficient fund balance. He said, "a long period of low prices could lead to insufficient money in the fund after lots of credits have been paid out, and the legislature might choose to not spend the money on credits." He stated that remaining credits not purchased by the state could either be carried forward or transferred to another taxpayer who had sufficient tax liability. Appropriations to the Oil and Gas Credit Fund. In 2008, the first year after the oil and gas tax credit fund was created, the legislature followed the prescribed formula in appropriating money to the fund. Starting in 2009, the legislature provided an open- ended appropriation to cover all tax credit purchase applications. During the following years the legislature continued this practice, creating an expectation among oil and gas companies that all qualifying credits would be purchased. Easing Restrictions. In 2010, the requirement that an applicant incur a qualified capital expenditure or buy a state oil and gas lease to qualify for a purchase payment was repealed. This was done to help companies get project financing companies looking to invest wanted to know they would get full value for the credit without worrying about whether the credit would meet the investment requirement. The legislature also added a new tax well lease expenditure credit program targeted at Cook Inlet gas exploration and production. The new credits could be purchased by the state. Tax Credit Purchases and Private Financing. In 2013, the legislature passed an amendment to the production tax that specifically allowed for the assignment of production tax credits to a third-party assignee without the state's consent. This meant companies could use their tax credits as collateral for loans or sell credits to a bank or investment institution. There is evidence the provision went farther than intended. The provision was offered as an amendment in House Finance to a Senate bill dealing with fish taxes. An administration official testified that the amendment would help open private equity markets to smaller investors in the state. When asked about whether the provision applied to North Slope producers, the maker of the amendment said she "believed that the amendment applied only to Cook Inlet and Middle Earth" and to gas. The senator whose bill was being amended stated "The goal was to bring additional gas to Cook Inlet consumers." As it turned out, the amendment applied to both oil and gas and to all net operating loss, qualified capital expenditure and well lease expenditure credits. The Sure Thing. In 2015, a Wall Street Journal article titled "How Wall Street Makes Money on Alaska's Oil Tax Breaks" described how Alaska oil and gas companies would sell their rights to a credit or use the rights as collateral for a loan. The companies would give up between five to twenty percent to a lender or buyer, who would get the right to collect the entire state payment. It has become apparent that lenders saw little risk given the state's track record in fully funding tax credit cash purchase applications. Not Such a Sure Thing After All. The estimated amount of purchasable credits grew from $180 million in 2009 to $700 million in 2015. In 2015, the legislature passed an open-ended appropriation to cover all purchase applications. Had the statutory formula been followed, approximately $91 million would have been available for appropriation. With oil prices plummeting and a $3 billion deficit, the governor vetoed $200 million of the appropriation. In 2016, facing a $4 billion deficit, he vetoed $430 million, leaving the $30 million required by the statutory formula. The question remains how to deal with the remaining tax credit purchase applications. 2013 - Senate Bill 21 In 2013, oil and gas companies' discontent with some ACES provisions and concerns about declining North Slope oil production and the fracking boom in the Lower 48 led the Parnell administration to introduce Senate Bill 21. Administration officials also expressed concern that their analysis of $6 billion in tax credits found no direct connection to future production. They worried that if oil prices dropped and company investments increased, the state budget would have a deficit of billions of dollars and the state would "still be on the hook for the credits." Tax Credit Policy Change. For North Slope companies, SB 21 changed the state's oil tax policy from tax credits based on investment to credits based on production; the more production from a field, the lower the tax. The theory was that companies would be more inclined to invest in the state and increase their production. SB 21 Tax Credit Changes. SB 21 repealed the qualified capital expenditure credit for North Slope oil and gas activities. The credit remained in place for other areas of the state. SB 21 included a gross value reduction (GVR) where a certain percentage of "new oil" on the North Slope would be tax-free. The bill added a $5 per barrel credit for production that qualified as new oil subject to the gross value reduction. The GVR and new oil credit applied for the life of the field. For production that did not qualify as new oil, such as oil from the Prudhoe Bay oil field, a sliding-scale production based tax credit was added; from $8 per barrel when the gross value of oil was $80 or less, to $1 per barrel between $140 and $149 gross value, and zero after that. The credit is not available for purchase by the state. For the North Slope, SB 21 increased the net operating loss credit to 45 percent until 2016 to ease the transition away from qualified capital expenditure credits. After 2016, the percentage was set at 35 percent the same as the new production tax rate of 35 percent. For other areas, the rate was set at 25 percent. 2014 Repeal Referendum. In 2014, public dissatisfaction over the new oil and gas production tax system prompted a citizens' referendum to repeal SB 21. The repeal would have reinstituted ACES in its entirety. Among other issues, supporters of the repeal argued that over time an increasing percentage of oil would qualify for the new oil tax breaks and the state's percentage of profit would decrease indefinitely into the future. There were also concerns that tax credits on production would not encourage Alaska investment since the credits did not require instate investment. The opposition argued SB 21 was working to attract Alaska investment and would increase state revenue over the long-term by increasing production. The referendum failed by a vote of 99,855 (52.7 percent) to 89,608 (47.3 percent). 2016 HB 247 Starting in 2015, oil prices dropped from over $100 per barrel to below $40 per barrel. With a $4 billion deficit, the state could no longer afford all the tax credit incentives offered as part of Alaska's oil and gas production tax. To ease the pressure on future state budgets, the administration introduced and the legislature passed HB 247 making changes to several tax credits. ? HB 247 amended Cook Inlet tax credits to phase out by 2018, including the net operating loss credit. For Middle Earth, credits were approximately halved. The bill also placed a cap on cash purchases to individual companies; $35 million would be purchased at full value, and another $35 million discounted by 25 percent. Any additional credits would have to be carried into a future year for either a cash purchase or use against a tax liability. ? For North Slope activities, HB 247 added a provision to the gross value reduction setting a time limit on how long the oil would be considered "new" oil excluded from taxation. The reduction expires after seven years of production or three years if the price of oil is greater than $70 per barrel. 2017 What's Next Most of the changes in HB 247 took effect on January 1, 2017. There are still credit programs and other provisions that could cost the state millions, possibly billions, in the coming years. Net Operating Loss. The North Slope net operating loss credit remains at 35 percent. Without changes, there is the risk the credits could take the production tax to zero and increase the amount of credits available for purchase. The risk increases with continuing low oil prices and increasing North Slope activities. Minimum Floor. Starting with the PPT, the production tax included a tax floor of not less than four percent of the gross value when oil prices were more than $25 per barrel. While the sliding-scale per barrel tax credit cannot reduce a North Slope producer's tax liability below the floor, net operating loss credits can take the tax to zero. Purchasable credits can take the tax below zero. Migrating Credits. Currently, a taxpayer can apply sliding-scale per barrel tax credits that cannot be used in one month to offset a tax liability from a different month in that calendar year. This occurs in a year where the minimum tax is in effect in some months and not in others in a year. Outstanding Credit Purchase Applications. The Department of Revenue's Fall 2016 Forecast estimates there will be over $887 million in outstanding credits available to purchase at the end of fiscal year 2018, assuming around $74 million is appropriated under the credit fund statutory formula. If cash purchases continue to be permitted and appropriations are limited to the statutory formula over the next decade, this balance is expected to grow to $1.6 billion by the end of fiscal year 2026. [During the presentation the following questions were asked and answered.] 1:14:53 PM REPRESENTATIVE BIRCH asked whether net operating loss credits (NOLs) were broadly supported by the legislature. MS. WEISSLER was unsure, and opined the bigger concern at the time was the cash payout, and how to "level the playing field" for the independent companies. She offered to research this question. 1:25:27 PM CO-CHAIR JOSEPHSON questioned why the legislature would have made a change in policy allowing a cashable credit to be spent outside the state on an outside development or exploration project. 1:25:59 PM MS. WEISSLER explained that was not the intent of the change; the intent was that the money would be invested in the state, however, there were no "sidebars" limiting the law. She referred to a Linc Energy 2013 annual report that described how the company sold credits to an investment company and applied the cash to Alaska and Gulf Coast costs. She said this was not a policy decision but "trusting that they would invest in the state - that was the intent." 1:27:02 PM REPRESENTATIVE PARISH, noting there could again be insufficient money allocated to meet the amount recommended in statute, asked how the state determines which tax credits get paid. MS. WEISSLER expressed her understanding allocating to "first in, first out" is how the pertinent regulations work. 1:33:35 PM REPRESENTATIVE BIRCH inquired as to how a former governor and legislature could have differed by a significant multiplier on what was clear and equitable about Alaska's Clear and Equitable Share (ACES) [passed in the 25th Alaska State Legislature]. MS. WEISSLER pointed out oil prices were high and there "was an atmosphere ... that was different from prior years." 1:34:40 PM REPRESENTATIVE BIRCH questioned when tax credits first became an inducement to investment and development in Alaska's tax policy. MS. WEISSLER recalled in 1978, there was a tax credit tied to leases and with certain requirements. The Economic Limit Factor (ELF) [passed in the 10th Alaska State Legislature] was its own incentive in 1977. The administration at that time determined as operating costs go up and field production goes down, an economic limit is reached, thus the field will not produce enough to balance its costs during further production. Therefore, the economic limit factor was part of a formula developed to bring the tax rate down as fields decline, in order to give companies an incentive to continue producing from marginal fields, but there was not a credit system until PPT. CO-CHAIR TARR, elaborating on Representative Birch's earlier question, confirmed during debate on ACES, the proposed progressivity rate was increased from 0.2 percent to 0.4 percent. MS. WEISSLER said that sounds right. She agreed progressivity increased exponentially with higher oil prices. 1:41:20 PM REPRESENTATIVE BIRCH informed the committee he has read that the majors would not make the investments today that they made many years ago. He asked whether HB 111 is an increase or a decrease, and if approved, for the broad range of the changes the bill would net the state. MS. WEISSLER said modeling is needed for the specific changes and numbers, and she deferred to the bill's fiscal note. 1:42:57 PM CO-CHAIR JOSEPHSON directed attention to Ms. Weissler's estimate that the outstanding credits are growing by "only" about $100 million per year over the next decade, and noted this amount could be offset by new opportunities on the North Slope; however, because the payments could be capped at [$74 million by the credit fund statutory formula], the credits can accrue into the billions of dollars. He questioned whether this is a conservative number. MS. WEISSLER said Alaska's tax credit system is an unknown as far as companies' decisions are concerned, and on how the tax credits factor in; also, the state's return on investment is unknown. She deferred the question to the Department of Revenue (DOR) and advised the existing system lacks information and analysis on the state's return on investment. [CO-CHAIR TARR passed the gavel to Co-Chair Josephson.] 1:45:37 PM The committee took an at ease from 1:45 p.m. to 1:50 p.m. 1:50:28 PM CO-CHAIR TARR directed attention to a document provided in the committee packet, verbally identified as a "cheat sheet," that will help the committee recognize relevant sections of Alaska Statutes during the sectional analysis of HB 111. One of the goals of the proposed legislation is to establish durability in the state's tax policy, understand the history of the policy, and only make changes that move the state toward a stable and predictable tax system at all oil prices. She pointed out the frequency of repeals and reenactments of tax policy legislation illustrates the difficulty in making the right decisions. 1:52:59 PM REPRESENTATIVE BIRCH returned attention to HB 111 fiscal note Identifier: HB111-DOR-TAX-02-10-17, and asked if the bill is a $45 million tax increase, raising to $85 million in fiscal year 2023 (FY 23). CO-CHAIR TARR explained the one tax increase in the bill is the change in the minimum tax from 4 percent to 5 percent; most of the other changes in HB 111 are prospective in nature, changing the state's risk after the effective date of 1/1/18. She said further discussion on the fiscal note would follow after the sectional analysis. CO-CHAIR TARR paraphrased from the sectional analysis for House Bill 111, Version O, as follows [original punctuation provided]: Section 1. Amends AS 43.05.225 regarding interest on delinquent oil and gas production tax payments to remove a three year limit on accrual of interest. Since 2014, the interest rate for delinquent taxes was set three points above the Federal discount rate. HB 247 added a new section increasing the rate for oil and gas to seven points above the Federal discount rate compounded. The higher rate applies only for the first three years after the tax becomes delinquent after which there is no interest. The amendment repeals the three year limit because zero interest discourages companies from settling tax disputes with the state. CO-CHAIR TARR further explained the three year limit is removed because it is inconsistent with existing statute. The Department of Revenue (DOR) has six years to complete audits, due to the complexity of the tax system, thus the three year limitation on interest is a "mismatch." She acknowledged the industry's criticism of the time the state requires to complete audits; in fact, no audits of the present system have been completed. Co-Chair Tarr reviewed the history of this issue. She continued the sectional analysis [original punctuation provided]: Section 2. Amends AS 43.55.011(f) to change the North Slope minimum tax from not less than four percent of the gross value to five percent for oil and gas produced after 2018. The section removes the variable minimum tax that would occur at sustained oil prices at below $25 per barrel; the five percent minimum tax would apply at all prices. Note: The section ends the minimum tax for oil and gas in 2022. That is not the intent. The minimum tax for oil should continue past 2022. In existing statute, the net production tax on gas will change to a gross value tax system in 2022 and the minimum tax for gas will end. A correction will be made in a future draft of the bill. CO-CHAIR TARR said the 5 percent minimum tax would apply at all prices after 1/1/18. In addition, there is a drafting error to be corrected by a later version of HB 111. 1:59:19 PM CO-CHAIR JOSEPHSON recalled the increase from 4 percent to 5 percent was proposed last year and was related to the governor's fiscal plan and its premise that all sectors of the economy should participate in solving the state's fiscal problem. He questioned whether the increase is based on "the administration's thinking, at least last year." CO-CHAIR TARR agreed. During the debate on Senate Bill 21 [passed in the 28th Alaska State Legislature] oil prices ranging from $30 to $40 per barrel were not considered. However, the price environment has changed, perhaps for the foreseeable future. She continued the sectional analysis [original punctuation provided]: Section 3. Adds a new section to AS 43.55.011 to make it clear that application of any tax credit issued under the oil and gas production tax may not be used to reduce the minimum tax of five percent. The second sentence in this subsection relates to fixing a situation where a taxpayer can apply per barrel credits that cannot be used in one month due to the minimum tax to offset a tax liability from a different month in that calendar year (the "migrating" credit issue). This issue only occurs in a year where the tax rate is below the minimum tax in some months and above the minimum tax in other months in a year. CO-CHAIR TARR further explained the second part of Section 3 refers to the migrating credit issue described in the earlier presentation. She continued the sectional analysis [original punctuation provided]: Section 4. Amends AS 43.55.020, related to monthly installment payments, to reflect the change to the minimum tax in section 2 and the migrating credit issue in section 3. Section 5. Changes the carried-forward annual loss the net operating loss credit rate on the North Slope from 35 percent to 15 percent. After January 1, 2018, a taxpayer will only be able to apply for tax credits up to 15 percent of their net operating loss. CO-CHAIR TARR further explained Section 5 does not eliminate any of the state's current liability, but reduces the amount companies can earn. The aforementioned fiscal note will show additional information on the effect of Section 5. 2:06:25 PM REPRESENTATIVE BIRCH directed attention to page 2 of the fiscal note indicating $8 billion in tax credits have been received by companies. Tax credits are meant to incent certain types of behavior, such as exploration, and he questioned if the amount of investment that has offset the amount in tax credits is known. For example, whether $8 billion is offset by $100 billion worth of investment. CO-CHAIR TARR responded net operating losses (NOLs) are currently earned at 35 percent of loss, which is approximately one-third [of investment]. Net operating losses are normally a function of collecting against an income tax, and companies can use NOLs against a corporate income tax. She reviewed some of the state's previous approaches to taxes and methods to incent behavior, and restated the legislation's goal to determine the best way to provide incentives that will result in desired activities. She referred to previous testimony from DOR estimating that roughly one-half of the previous incentives have led to production; however, at this time policymakers lack sufficient access to privileged information to know. Co-Chair Tarr continued the sectional analysis [original punctuation provided]: Section 6. Amends AS 43.55.023(d) to remove the ability for taxpayers to apply for a cash payment for net operating loss credits issued under AS 43.55.023(b). CO-CHAIR TARR noted the cheat sheet provided indicates subsection (a) is a qualified capital expenditure (QCE), and (l) is a well lease expenditure (WLE); Section 6 limits net operating losses, but not does limit QCE and WLE. She continued the sectional analysis [original punctuation provided]: Section 7. Amends AS 43.55.024(j), the per barrel tax credit, from zero to $8 to zero to $5 per barrel depending on the price of oil. The most a taxpayer could receive is a credit of $5 per barrel at prices below $80. 2:11:25 PM CO-CHAIR TARR pointed out Section 7 only addresses non-gross value reduction (non-GVR) oil. The bill does not address gross value reduction (GVR) oil as that was addressed in House Bill 247 [passed in the 29th Alaska State Legislature]. As discussed in the earlier presentation, there remains the question as to whether some oil was already going to be produced, even without financial incentives. She directed attention to the bill on page 14, beginning on line 24 and continuing to page 15, which read [in part]: (1) [$8 FOR EACH BARREL OF TAXABLE OIL IF THE AVERAGE GROSS VALUE AT THE POINT OF PRODUCTION FOR THE MONTH IS LESS THAN $80 A BARREL; (2) $7 FOR EACH BARREL OF TAXABLE OIL IF THE AVERAGE GROSS VALUE AT THE POINT OF PRODUCTION FOR THE MONTH IS GREATER THAN OR EQUAL TO $80 A BARREL, BUT LESS THAN $90 A BARREL; (3) $6 FOR EACH BARREL OF TAXABLE OIL IF THE AVERAGE GROSS AT THE POINT OF PRODUCTION FOR THE MONTH IS GREATER THAN OR EQUAL TO $90 ... CO-CHAIR TARR said the change means if prices go up, the state would see some additional revenue, although at current prices, the producers' breakeven price is about $46 per barrel. She questioned whether the state wants to issue a credit when prices are between $50 and $80 per barrel and the producers begin to make a profit. She said this is a policy call that does not fundamentally change Senate Bill 21. 2:15:56 PM REPRESENTATIVE JOHNSON expressed her concern that Section 7 of the bill would affect the current increase in production. CO-CHAIR TARR advised the base rate in ACES was a 25 percent credit, which was increased to 35 percent in Senate Bill 21, along with the addition of the per barrel credit. A way to simplify the system would be to adjust the base rate, which would act like "a reverse progressivity." She has asked DOR to provide modeling for each section of the bill at the hearing scheduled for 2/17/17. CO-CHAIR JOSEPHSON agreed production is up, but because of the credit outlay, the state will not gain net revenue from severance tax - setting aside royalty - until the price of oil increases, thus the bill seeks to narrow the span of the per barrel tax credit. REPRESENTATIVE PARISH surmised "old oil" gets an $8 per barrel credit, and "new oil" gets a $5 per barrel credit, which provides a competitive advantage to legacy fields. CO-CHAIR TARR restated the bill affects non-GVR oil, which is old oil, and this provision does not apply to new oil. As discussed in the earlier presentation, a net profits tax system is generous with deductions and provides incentives for producers; the policy question is whether additional incentives are needed. However, she opined 35 percent of the base rate would be unusually high. 2:20:25 PM REPRESENTATIVE BIRCH referred to an earlier statement "setting aside royalty." He pointed out a 3 percent increase in production does generate additional royalty income to the state, and questioned whether the primary focus of the bill was on non- royalty provisions. Representative Birch opined royalties are significant, and should not be set aside. CO-CHAIR JOSEPHSON said the state owns its royalty share, and the question is whether the oil otherwise would not be produced. He said the debate has moved to a greater focus on royalty because that is where the current money is, and restated the royalty "is ours, sort of by definition." Co-Chair Josephson posited the reduction from 35 percent to 15 percent in NOLs for the producers, is argued by industry that in times of low price the reduction discourages their continuing investment, because the state is not there to help them in the current low-price environment. 2:22:18 PM CO-CHAIR TARR said it's possible. However, the producers always benefit from deductions for transportation, capital expenditures (CAPEX), and operating expenditures (OPEX), and the NOLs are quite expensive for the state, as reflected in the bill's fiscal note. She opined the production and revenue forecast is confusing because the state not only has the liability of cashable credits, but also lost revenue due to low prices. Also, if prices go up, the state will still not benefit because the carry-forward loss credits will reduce any additional income from higher prices. The effective date of the bill is 1/1/18, so the producers - even at $30 per barrel oil - due to all of the deductions, will still have protection in the system for years of low prices, but the state has none. In response to Representative Birch on his question of royalty, she said in Alaska, natural resources are common property and on public land the state gets its royalty share; however, in other states where oil and gas development happens on private land, the royalty goes to the landowner and taxes go to the sovereign. In Alaska, the royalty share and tax revenue can get confused. CO-CHAIR JOSEPHSON asked how the bill would affect non- producers; for example, currently if a company spent $10 billion to develop a large field, the state would be responsible for about one-third of the cost of development. However, under the terms of HB 111, the state would be responsible for 15 percent, and would provide much less cash assistance after 1/1/18. CO-CHAIR TARR said the state seeks incentives for certain behaviors and must decide what it can afford and what incentives will be successful. A future section of the bill will explain how the bill will limit the state's exposure, but not the amount companies can earn. She continued the sectional analysis [original punctuation provided]: Section 8. Amends AS 43.55.028(a) to reflect the section that removes the ability for taxpayers to apply for a cash payment for net operating loss credits. The only credits that may qualify for a cash payment are the qualified capital expenditure credits in AS 43.55.023(a) and the well lease expenditure credits in AS 43.55.023(l). Under HB 247, for Cook Inlet, the qualified capital expenditure and well lease expenditure credits apply only to expenditures incurred before January 1, 2017. Once those credits phase out, the only credits that may qualify for cash payments are capital expenditure and well lease expenditure credits acquired by companies operating in the area outside Cook Inlet and the North Slope known as "Middle Earth. 2:26:12 PM CO-CHAIR TARR said DOR will provide modeling based on the premise that the state paid the statutory minimum on net operating loss credits during past years of high and low prices. Also, after QCE and WLE are phased out, Section 8 will only apply to NOLs for companies operating in Middle Earth [the non- North Slope, non-Cook Inlet areas of the state]. She continued the sectional analysis [original punctuation provided]: Section 9. Changes AS 43.55.028(e) to limit the state's purchase of credits to $35 million per company. Only companies with production of not more than 15,000 barrels per day may apply for a cash payment. Current law sets the purchase limit at $70 million and applies to companies with not more than 50,000 barrels per day. CO-CHAIR TARR further explained Section 9 - also in the oil and gas tax credit fund - limits the state's purchase of credits to $35 million per company, reduced from $70 million. She reviewed the history of the changes to the limit, and observed these cash payments had the original intent to help non-producers, small companies, and independents with exploration and drilling. 2:32:01 PM REPRESENTATIVE BIRCH advised the committee a basic aspect of finance is the time value of money. He questioned the value of an incentive a company would have to wait 30 years to receive. Invoking a tax credit to induce a behavior, and delaying payment for a long time, when the tax credit is needed for current obligations, is disingenuous at the least. CO-CHAIR TARR acknowledged there has been extensive debate on this topic. She agreed if a company has "a long time horizon" for funding, the net present value of the tax credit is zero. She restated the prospective nature of the legislation and pointed out companies most impacted by this change will have an opportunity to evaluate the changes. Also, the proposed limitations may allow the state to pay its debts, creating more stability, which also has value. REPRESENTATIVE BIRCH said the legislature appropriated the money to pay the tax credits and the governor vetoed payment. Although the proposed legislation may be prospective, at this time the state has a $1 billion liability, and businesses are making significant decisions affecting jobs and opportunities based on the state honoring its obligations. CO-CHAIR TARR agreed the state is considered an unstable business partner at this time; the state must address its liability and also meet its goal of stability and durability of its tax system at all prices. 2:37:28 PM CO-CHAIR JOSEPHSON clarified the aforementioned legislative appropriation was $430 million, not the entire allocation, and the legislature chose not to override the governor's veto. Co- Chair Josephson opined the governor was prepared to appropriate $1 billion to the liability, and the reason for the veto was that the legislature did not produce a fiscal plan. REPRESENTATIVE JOHNSON appreciated the historical information but urged the committee to focus on what is proposed. She asked how many companies are producing not more than 15,000 barrels per day and will be affected by Section 9. CO-CHAIR TARR said currently the limit is 50,000 barrels per day which qualified the three majors and Hilcorp; after the reduction to 15,000, Caelus will be impacted. CO-CHAIR JOSEPHSON added the statute does not require credits to be cashable, but provides the option to the legislature through its power of appropriation. He stated his personal concern about the state's failure to pay the credits. REPRESENTATIVE RAUSCHER observed companies on the North Slope have been bought out over the past 10-30 years, and questioned whether bankruptcies are due to state inaction, when what is desired is to "help them help us." He asked if after a bankruptcy or sale, the new buyers also acquire tax credits. CO-CHAIR TARR responded it would depend upon whether the purchasers used a bank for financing. If a bank lent money based on the state's payment of tax credits, testimony from Bank of America revealed borrowers will default without the payment of the tax credits, and after default the assets and lease become the property of the bank and would be sold. Otherwise, without bank financing, the credits go to the next owner. CO-CHAIR JOSEPHSON, in response to Representative Johnson, said at least 12 companies in the exploration and development phase are affected by the reduction in Section 9. He urged for testimony from Caelus regarding the effects of the bill. 2:43:46 PM REPRESENTATIVE RAUSCHER inquired as to additional testimony on the bill. CO-CHAIR TARR said the bill will be heard for two weeks. She then clarified the aforementioned 12 companies are those currently awaiting payment, and the change brought by Section 9 also affects Caelus. She also restated the limit is on cash payments for NOLs. Co-Chair Tarr continued the sectional analysis [original punctuation provided]: Section 10. Adds a new section to AS 43.55.150 to ensure that the gross value at the point of production does not go below zero. The gross value is determined by subtracting tariffs and transportation costs from the West Coast sale price per barrel. The gross value at the point of production is used in various calculations throughout the production tax statute. Section 11. Repeals AS 43.55.028(g)(3). The language proposed to be repealed was added in HB 247. If an applicant wanted to apply for the full $70 million in credits in one year, they would receive 100 percent of the first $35 million and 75 percent of the other $35 million. This was to give applicants an incentive to wait and collect credits in a future year and lessen the cash outlay by the state in a single year. Section 12. (a) Sections 3 and 4 the five percent minimum tax and resolution of the migrating tax issue apply to credits applied to reduce a tax liability for the tax year starting on or after January 1, 2018. (b) The changes to the net operating loss credit in section 5 apply to lease expenditures incurred on or after January 1, 2018. Section 13. If a person has applied for cash payment of a net operating loss credit before January 1, 2018, the department may purchase the credit. Section 14. The change to the interest rate is retroactive to January 1, 2017. 2:49:01 PM REPRESENTATIVE JOHNSON questioned whether the legislation creates a new tax rate effective retroactively to 1/1/17. CO-CHAIR TARR explained the retroactive 1/1/17 effective rate applies to the interest rate and not to the tax rate. For example, if DOR finds delinquent taxes after an audit, it will charge an interest rate for the delinquent amount during its settlement negotiations. In further response to Representative Johnson, she suggested the dates in question are related to the provisions of House Bill 247, that are based on a calendar year, and the one provision in the proposed legislation, that is based on the fiscal year, and therefore must be reconciled. CO-CHAIR JOSEPHSON surmised industry files [tax returns] in spring, thus the timing should not create a problem for industry. CO-CHAIR TARR agreed the timing is challenging to explain and gave an example: during calendar year 2016, taxes are due in 2017, but [filed] in fiscal year 2018 (FY 18). She continued the sectional analysis [original punctuation provided]: Section 15. The change to the interest rate and its retroactivity is effective immediately. Section 16. All other sections take effect January 1, 2018. CO-CHAIR TARR directed attention to the fiscal note summary of revenue impact on page 2, and the total revenue impact, total budget impact, and total fiscal impact on page 4. She pointed out various elements of the fiscal note. 2:57:44 PM CO-CHAIR JOSEPHSON questioned whether the 35 percent NOL was intended to parallel the 35 percent "progressive rate at the highest price per barrel." CO-CHAIR TARR said yes; however, the rate is not progressive but is a flat 35 percent tax rate. In addition, she said, "It's not really ever 35 percent because you have credits you can always apply to it." CO-CHAIR JOSEPHSON acknowledged the legislation is very complicated and urged the committee to work with the co-chairs on developing consensus; he stressed the state's cash obligation to the industry is owed, but is untenable. REPRESENTATIVE TALERICO anticipated many hearings of the bill and testimony from all of the affected parties. He stated it is very difficult for the committee to determine estimates of capital expenditures as they involve drilling and infrastructure, and encouraged additional forthcoming information. REPRESENTATIVE BIRCH directed attention to page 4 of the fiscal note analysis that indicated a $45 million impact in FY 18, increasing to a $300 million per year total fiscal impact in FY 26; he concluded the proposed legislation seeks to add $50 [million] to $300 million per year to state take. CO-CHAIR JOSEPHSON agreed. CO-CHAIR TARR cautioned the analysis by DOR is based on a five- year forecast of production, and thus there will be many changes. She noted the presentation on the history of oil and gas tax policy was intended to help the committee understand previous decisions and thereby avoid repeating mistakes. [HB 111 was held over.] 3:02:48 PM ADJOURNMENT  There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 3:02 p.m.