Legislature(2017 - 2018)HOUSE FINANCE 519
03/22/2017 09:00 AM FINANCE
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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." 9:08:11 AM KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE, relayed he had spent much of the previous day walking through the history and background of oil tax credits. He had just started walking through the bill sections of the presentation titled: "DOR Presentation - HB 111 Background and Bill Analysis" when the meeting concluded. He briefly paged through some of the sections that had already been covered; the interest rate section, the transparency and executive session sections, and the section on minimum tax. The committee had stopped at the issue of hardening the floor when time ran out. He referred to slides 37 and 38 regarding issues with a minimum tax. He had offered that if the state were to implement a minimum floor the near-term impact would equate to about $20 million. Mr. Alper turned to slide 39 to look at the different issues of hardening the floor. Hardening the floor meant ensuring that the minimum tax was collected in all circumstances. There were several separate policy decisions that needed to be made. If the committee wanted to harden the floor in some instances and not others it would be possible to parse out certain items from others. Mr. Alper continued that there was an issue of producers not being eligible for refundable credits. He was talking mostly about the major producers (companies that produced more than 50,000 barrels per day). They were unable to earn cash for their credits under current law and were required to carry them forward. The question was whether there should be clear direction that the carry forward credit could not be used to reduce the minimum tax payment. It would mean that the company would have to hold it and carry it forward for an additional year or two until the price of oil recovered sufficiently and they reached above the minimum tax level. Mr. Alper continued to discuss a second issue related to hardening the floor. The small producer credit was sunsetting but there were still a number of companies earning it. Upon reaching the minimum tax, he wondered if the smaller companies should be able to reduce it by the credit of up to $12 million. The regulatory language allowed them, under certain circumstances, to reduce their payments to zero. Mr. Alper explained that the third issue related to new oil. The per barrel credit earned on new oil was not specifically hardened to the floor presently. The $5 credit could be used to reduce payments to zero on new production. Generally speaking, the cross over point above a zero tax was in the $70 range. He suggested that to harden the floor for new oil would mean that the production during years that companies earned the Gross Value Reduction (GVR) would also pay the minimum tax. There was a unique structure in the bill that had not previously been seen in other oil bills that would create a reduced minimum tax specifically for GVR eligible oil. He would discuss this item in another slide. Mr. Alper drilled deeper into the minimum tax floor on slide 40. The slide addressed the major producers. It was clear in statute that major producers were not able to receive cash. Tax credits were carried forward. The net operating losses (NOL)s for the explorers were simply allowable expenditures. In other words, all of the explorers' spending became their operating loss because they did not have any offsetting revenue. The net operating loss for the producer was when spending exceeded revenues. The legal term that the state's auditors used was excess lease expenditures, generally referred to as an operating loss or an NOL. An excess lease expenditure could be due to a company doing more drilling and just starting up their production without a significant amount of oil. Alternatively, companies could be functional, but if the price of oil were to go far below expected and their costs were greater than revenues, they could incur a loss. Regardless, the state paid a credit based on a fraction of their operating loss. He clarified that at least one of the major producers claimed an operating loss in calendar year 2015. He could show members where in the Revenue Sources book implications showed up. It meant that the company was able to claim certain loss credits against their taxes beginning in 2016. He noted that it could be seen in the 2-page table in the Revenue Sources Book. It showed where the 023-B credits claimed against taxes by North Slope companies. That added up to $107 million between the three years, FY 17, FY 18, and FY 19. They were carry forward NOLs. There was no other 023B credit being earned on the North Slope that would be used to offset taxes by the major producers. 9:14:05 AM Mr. Alper moved to slide 41 which talked about the language in the bill that would partially harden the floor for new oil (GVR eligible oil). He noted the three columns on the slide. He explained that he set the table at $49 per barrel because the bill had a minimum tax change at $50 - he did not want the data distorted. He wanted to show the status quo tax versus what was being proposed in the bill. He relayed that at $49 oil in 2018 with average costs including transportation costs and lease expenditures the production tax value of legacy oil equaled $5.59 (Net Value After GVR). He noted that there was no GVR with legacy oil. A tax of 35 percent was applied and equaled $1.96 and the per barrel credit of $8 wiped the base production tax after credits to zero. He recapped that under the traditional tax calculation at $49 oil legacy fields paid zero. However, that was the point at which the minimum tax would kick in. Returning to the wellhead value of $39.32 multiplied by 4 percent would equal $1.57 per taxable barrel. Mr. Alper continued to slide 42 which addressed a new part of the bill, although it was something members had seen before. The issue of migrating credits was originally proposed by the governor in the original version of HB 247 [Legislation passed in 2016 - Short Title: Tax; Credits; Interest; Refunds; Oil and Gas]. The producers referred to the issue of migrating credits as the "true-up problem." He explained that the per taxable barrel was earned on a month-by-month basis. In statute it stated that, based on the average gross value of the oil in a specific month, the credit earned per taxable barrel was $8, $7, or $6 down to zero depending on the gross value. It also stated that the credit could not be used below the minimum tax. Inevitably, in a low-priced month, some of the per barrel credit could be lost. The credit could not be cashed or carried forward; it was a use-it or lose-it credit. If a company's average gross value was so low that it could not use the entire $8, the credit would essentially be lost. He continued that the minimum tax at the annual tax calculation was an annual minimum tax. A company could use certain per barrel credits that were earned in a low-priced month to offset taxes from a high-priced month where the company was still paying at above the minimum tax. He indicated that the following few graphs would illustrate his point. Co-Chair Foster relayed that Representative Guttenberg had joined the table and Representative Geran Tarr was in the audience. Vice-Chair Gara had a question about slide 41. He thought Mr. Alper had suggested some change to a possible minimum tax for GVR oil in the new bill. He had missed Mr. Alper's comments. He asked for a recap. Mr. Alper explained that previous legislation that hardened the floor equated to 4 percent of the gross value being paid. It basically eliminated any benefit for GVR-eligible oil because 4 percent of the gross was 4 percent of the gross whether it was old oil or new oil. He furthered that HB 111 took the gross value upon which the 4 percent or 5 percent were calculated and adjusted the gross by the GVR. Companies could take the 20 percent benefit off of the gross value and then take the 4 percent calculation. He described it as the minimum tax for GVR oil: 4 percent of 80 percent of the gross, a 3.2 percent gross tax. 9:20:09 AM Mr. Alper advanced to slide 43 which he thought provided a good visual depiction based on actual data for calendar year 2014. He highlighted the grey line at the top of the chart representing the price of oil by month with a scale on the right-hand side. In January, February, and March the price was in the low $100 range. In June, the price went up slightly, in July the price of oil began to rapidly decline, and by December the price of oil reached just over $50. The bar represented the actual revenue collected by the state per the monthly estimated tax calculation by the various producers. He noted that the top yellow bar represented the total calculated tax of 35 percent of the production tax value. The green bar showed what was actually paid to the state. He clarified that the size of the yellow was the per barrel credit - the amount subtracted from the tax calculation before the payment itself. The red bar represented the minimum tax if it came into play. He commented that that everything was more or less normal by the time July came around when prices began to decline but remained comfortably above the minimum tax. In October, the yellow bar was very large. By October, producers were earning the entire $8 credit. At the same time the price of oil was about $75 per barrel. Companies were able to claim the $8 credit. He pointed to the green sliver in October which indicated that the amount received was only slightly above what the minimum tax calculation would have been. If the price per barrel went down another $1 or $2 the minimum tax would have kicked in. He reported that in November the yellow bar was not quite $8 high because of the little black dotted area on top. The dotted black area represented the difference between the per barrel credits that were used and the per barrel credits that were earned. Producers were able to earn $8 and use $7 per barrel in November. In December, the price failed to the point where companies might have earned $8 but were only able to use $2. The dotted line made up the rest of the per barrel credit that was essentially foregone for the months of November and December. As far as the monthly estimated payment went it looked like slide 43. Mr. Alper turned to slide 44. He highlighted that the two dotted lines in November and December were more or less used to offset several taxes from earlier months in the year. They were shown being connected to January on the chart. In other words, the difference between the 12 monthly estimated taxes and the end of year true-up was that the state ended up paying $112 million in refunds based upon the ability to use the full $8 from the later months against months in the year that had a higher tax liability. Conceptually, the issue was that the per barrel credits were being used in a month other than which they were earned. He explained that the language in Section 7 and 8 in HB 111 tried to define that the credits could only be used to offset taxes accruing in the month the credits were earned. However, unused credits could not be moved to offset taxes from another month. The language was technical and had been worked on by the department and the legislature's legal department. He was not certain that the technical language did exactly what it was supposed to do. He suggested that if it was the committee's will to maintain the section, he wanted the legal teams to work together to ensure the use of correct language. 9:24:37 AM Representative Wilson asked how difficult it would be for the companies and the department to go back and make sure both parties agreed on what credits were in a specific month. She asked how the change would be implemented. Mr. Alper thought it would be fairly easy to implement with the department's existing software. It was a matter of programing changes to how different things were treated. The per barrel credit was earned by the month. The department knew the gross value and the production to the number of taxable barrels. The department knew the lease expenditures which were averaged out over the year with a one-twelfth formula. It was not like the money a company spent in January got deducted in January. It was a company's annual expenses which was in existing law. He surmised that calculating the taxes owed in a month based on the numbers was not difficult. The state was not returning to a monthly tax calculation similar to the way Alaska's Clear and Equitable Share (ACES) was, which was a true monthly tax. It was a matter of changing how the credits were applied. Mr. Alper turned to slide 45. He explained that the language stated that the amount paid due in the month could not be different than the amount that was due based on another section of the bill. He thought the language was complicated. However, he did not believe it would be that complicated to make the change.oweve,Commissioner Hoffbeck He clarified that the information on the slide was only relevant in a year where there was substantial volatility. In a normal year there was no value to the forecast, but rather an indeterminant revenue item. The reason was because the department did not forecast volatility. He provided an example. In order for the section to have any use or value some months of the year had to result in a tax collection below the minimum tax cross over and some months where they were above the minimum cross over. He relayed that 2014 was an example, which lead to a circumstance where the department's forecasts were off due to having to pay large refunds. The department began looking for a statutory fix and developed the current language in the bill. Representative Wilson asked if he knew how the bill would affect through-put. Mr. Alper could not answer the question. There were several decisions that a company made about investments and production. He was unaware of how substantial of an impact the bill would have. He argued that the $112 million was a relatively mild example. One of the advantages of having a monthly tax structure was to benefit from a price spike. He provided an example where the state would have $50 per barrel oil for an entire year. However, in the summer if a war broke out and oil transportation was disrupted, the price of oil might spike to $150 per barrel for 3 months and return to $50. He suggested that in the example, with a monthly tax, the state would benefit. The state would be getting a 35 percent tax for 3 months. For the other 9 months, when the price of oil was at $50 per barrel, there would be a significant amount of unused $8 per barrel credit. At annual true-up the state would be receiving the 4 percent minimum tax during the spike years. He estimated a potential loss of foregone revenue of about $300 million. Representative Wilson asked if the department consulted with the oil companies about the legislation. Mr. Alper relayed that the division heard from tax payers all of the time. He noted talking to them about mundane information. He suggested that what was being discussed was a technical concern originating from the Tax Division. The division had brought the issue to the attention of the bill sponsors from previous legislation. 9:30:28 AM Representative Guttenberg commented that the issue of migrating credits was a policy call. He asked about other unintended consequences based on the modeling. He asked if the department had looked at the potential scenarios. Mr. Alper indicated that it was the largest unforeseen consequence the department was digesting from SB 21 [Legislation passed in 2013 - Short Title: Oil and Gas Production Tax]. The other issue was resolved with a bill that passed the prior year. It had to do with the interaction of the gross value reduction with the net operating loss. Essentially, if a company lost $20 million but also earned a GVR which was subtracted, the state could be paying a credit based on a $50 million to a company that only lost $20 million. The credit would become 100 percent of their loss. It happened a couple of times and was corrected in the bill that passed in the previous year. He continued that there were regulatory issues regarding the sequencing of credits that the department was continuing to work through. He admitted there was still some statutory fixes were needed, but the committee was currently addressing the main issue. Representative Guttenberg asked, in a case where the calculation was more that 100 percent, if the state had ever paid a company more than 100 percent of their costs or losses. Mr. Alper answered that the state had paid tax credits equal to or in excess of 100 percent of a company's loss on a couple of occasions. The state had issued certificates that were paid based on prior law. He asserted that it would not be happening in the future because of the correction made in HB 247 [Legislation passed in 2016 - Short Title: Tax; Credits; Interest; Refunds; Oil and Gas]. Vice-Chair Gara considered the proposed changes as minimal. He asked about a press release that provided a statement from Repsol. The press release indicated the company would be coming to Alaska and investing three-quarters of $1 billion on leases and development and would move forward with projects that the state deemed economic. The company did so without asking for any tax relief under Alaska's Clear and Equitable Share (ACES), a stiff tax system. He asked Mr. Alper if he recalled the press release. He elaborated that the press release mentioned the geology and stability in Alaska which made the state an attractive place to do business. He asked if geology and a state's stability were important factors in deciding whether to invest. Mr. Alper recalled the press releases but did not remember their precise timing. He thought it was a large open debate. He agreed that Alaska had great rocks and people preferred a friendly tax regime. He did not know how the decision-making worked, but he believed the initial commitment from Repsol to come to Alaska was prior to the passage of SB 21. Co-Chair Seaton asked about the migrating credit issue. He asked if the issue had been addressed in HB 247 in the prior year. Mr. Alper responded affirmatively. He reported that the version of HB 247 that passed the House included language that would have resolved the issue. Co-Chair Seaton asked if the language in the bill was the same. Mr. Alper relayed that the language was slightly different. There was a technical problem with the version that came out of the House. He believed the language in the finance committee's version was better. He thought the current language in the bill was closer to what was in the governor's original bill. He suggested the language was in a couple of places. It was in the use of credits and in the definition of the monthly estimated payments section. He did not want to comment definitively that the bill did exactly what it was intended to do. 9:36:20 AM Representative Pruitt appreciated Mr. Alper's example. He thought there were two challenges with the $50 price; the dearth of supply and the oversupply in the market. He surmised that if a war broke out, the oversupply in the market, while there might be a spike in price, would temper growth. He thought the likelihood of a short timeframe was low, a longer timeframe might be possible with a war. He thought 2014 was the most extreme example he would expect to see at a drop of $50 or $60. He wondered about volatility in a normal year in the $50 to $70 range. Mr. Alper responded that if volatility stayed in the $50 to $70 range, the state would not see a substantial impact. If $75 was the crossover for the average tax payer between the minimum tax and the gross tax and there were a few months with the price in the $65 range and a few months at the $85 range, the state would see something less than $112 million. It depended on how extreme the difference was. It had to do with how much per barrel credit was unusable. In the low-price months, it depended on how far below the cross over a company got before it lost or was unable to use a large portion of its per barrel credits. He suggested that at the crossover at $75 a company was using exactly $8 of its per barrel credits. At $74 they might be using a little over $7. At $50 or less companies would start using zero, where 35 percent of their net without any per barrel credit started equaling 4 percent of their gross. It happened right around $5 above their break-even point - $46 or $47 per barrel. How close companies got and how high above the minimum tax would determine the size of the number. It would be less than $50 million in the $20 example. Representative Pruitt asked about the change made in the House Resources Committee to the sliding scale. He wondered if the change had an impact on what was presently being discussed. Mr. Alper replied that it was an annual tax. Under current law, the calculation of the per barrel credit was a monthly determination. He explained that the change made to the per barrel credit in the House Resources Committee changed the numbers. It was done differently in the original bill versus the committee substitute. Both of them were changes to the amount. He reviewed the changes. In the current version all of the brackets were moved $20 to the left. The $8 credit happened below $60 per barrel rather than below $80. The $7 credit happened below $70 instead of $90. It changed the places at which companies earned different values. However, it did not change the way the credits were used except for the migrating issue. It did not make the tax more monthly except with migrating credits. 9:41:14 AM Representative Pruitt wondered if it was a migration. He asked if it was still an annual tax. Mr. Alper responded that it was still an annual tax. The particular credit was earned monthly and was used monthly for the determination of estimated tax. To the extent the state was turning it into a monthly calculation, it was hardening the monthly estimated tax. The amount of per barrel credit used for the total of the 12 monthly taxes could not be more than the per barrel credit used in the actual original 12 monthly taxes. In other words, a company could not use more per barrel credit annually than they would have been able to use in their monthly estimated tax. Mr. Alper advanced to slide 46. He relayed that the largest change in the legislation was that the state was eliminating direct state cash support for North Slope activities. It was a dramatic shift from what the state had done for the previous 10 years. He explained that in Section 9, in the NOL statute describing how a company earned an operating loss credit, it eliminated the 35 percent operating loss credit earned on the North Slope. Sections 9  and 11  talked about how credits were cashable, transferable, and saleable to other companies. It carved out the North Slope NOL from the definitions around who could do various thing with the credits earned. The North Slope benefit and the benefit, itself, was elsewhere in the bill, which he would be explaining. Since the North Slope benefit would no longer be a credit, it would no longer be transferable and had to be held by the company. There was still a structure for cashable credits. The cash fund would still exist, and other things would be eligible for cash, just not as many of them. He relayed that the 4 items that would be eligible for cash was listed on the slide: Remaining credits eligible for repurchase: 1. Qualified Capital Expenditure and Well Lease Expenditure credits (only in Middle Earth after 2017) 2. Exploration credits (only in Middle Earth after 2016) 3. LNG Storage and Refinery Infrastructure credits (corporate income tax credits that aren't earned by oil producers) 4. (new dry hole credit added in Sec. 17) Representative Wilson asked how long the LNG storage credits would remain. She wondered if they had a cap. Mr. Alper was aware that it was capped at $15 million, the same as the Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) credit. He did not know whether it had a specific subset. The state kept anticipating the cap would occur in the following year but kept rolling it for a year at a time. 9:46:20 AM Representative Wilson remembered the LNG storage credits but could not recall whether there was a sunset. Mr. Alper confirmed he would get an answer for her. Vice-Chair Gara wondered about the refinery credit from a few years prior. He mentioned there was a little innocent royalty sales contract and all of a sudden, a refinery credit was added to it. The company that wanted the refinery credit was Tesoro. They had stated they did not need the refinery credit, but other companies wanted it. It ended up passing and 3 companies qualified for it, 2 owned by Arctic Slope Regional Corporation (ASRC) and 1 by Tesoro. He suggested that the state was not privy to some of the credits due to confidentiality. Some credits were deducted from company profits and some were cashable for companies that did not have profits. He asked if Mr. Alper could share how much has been deducted from company profits. He asked if the amount was up to $10 million per refinery. Mr. Alper answered that there was no way to aggregate the information because there were less than three transactions. He was aware the state had not paid any credits simply because of the timing. There was no cash in the fund presently. The first applications would not have arrived until the prior fall. The credit took effect January 2015 and the bill had passed in 2014. He spoke of an inherent delay. There was at least 1 claim for a refundable credit. However, the state was not able to pay it because of limited funds. Vice-Chair Gara was trying to get as much information without infringing on confidentiality. He asked if the legislature could know how much had been deducted by refineries that made a profit. He continued to ask about the applications that had been made for a certain amount of money for cash credits and about the amounts being requested. Mr. Alper did not believe the information could be provided because of the limited number of payers. The department would parse together whatever was possible. Representative Wilson responded that Tesoro had not taken any of the credits. She had verified the information with Tesoro. She also mentioned that Petro Star had not taken any cashable credits but had applied for their asphalt project and another project. They were the only 2 companies eligible with Flint Hills turning into a tank farm. Vice-Chair Gara commented that companies might not have received any cash credits, but he still wanted to know whether they had deducted a certain amount from profits. He continued his line of questioning. He wondered about a potential cost to the state of $30 million per year for 5 years totaling $150 million. Mr. Alper responded in the affirmative. He clarified that 1 year had gone by and one of the companies had taken themselves out of the running, which would reduce the maximum footprint of the tax. He was aware of the Petro Star asphalt issue. He could not specify how much they did or did not claim in a tax credit for that specific project. He had just been handed some information. He relayed that work had to be done before January 1, 2020 in relation to the LNG storage credit. The credit would equal $15 million or 50 percent of the activity, whichever is lower. 9:50:32 AM Representative Pruitt referred to the Middle Earth credits sun setting in 2022. He asked for an estimate of the cashable credits. Mr. Alper answered that the credits against liability were forecasted at zero because there was no forecasted production. No one had any revenue to offset for Middle Earth. The hope was for someone to find commercial quantity oil or gas that they would be able to produce and sell for a profit or, in some cases, used in local utilities. The amount the department estimated was about $20 million. In the department's forecast, Middle Earth and Cook Inlet were merged because there were so few transactions that the department could not separately report due to tax payer confidentiality. He reported a hearing in the Fall of 2015. The Senate Resources chair had conducted a series of outreach meetings on tax credits in the previous interim, one of which covered Middle Earth credits. At that particular hearing Mr. Alper, in response to a question, indicated he could not be specific because of confidentiality agreements. However, a gentleman from Doyon stood up and answered that the credits were mostly Doyon's. Doyon had received about $60 million in state cash credit support over several years. Representative Pruitt listed the credits eligible for repurchase that would continue to exist with the passage of the bill. He mentioned $20 million, the LNG storage at $15 million, and the refinery credit. He was unclear about the number of years remaining for the refinery credit. Mr. Alper responded that the credit would be used through 2022. Representative Pruitt asked if it was $10 million per year. Mr. Alper responded, "Yes." Representative Pruitt indicated that the state was creating a new dry hole. Mr. Alper added that, barring anything unusual with the dry hole credit, the total credit spend would be less than $50 million. Representative Pruitt asked if Mr. Alper meant $50 million per year. Mr. Alper responded affirmatively. 9:53:38 AM Mr. Alper continued to slide 47. He addressed the per barrel credit. The current credit was a sliding scale of $8 per barrel with the well head or gross value below $80; $7 below $90; $6 below $100; and going to a zero credit when the well head value exceeded $150. It was subtracted as part of the standard calculation for the net tax for SB 21. The amendment would change the section of the bill. It would keep the same stepdown language but changed the steps to where $8 would be below $60; $7 below $70; $6 below $80; and shifting most of the tiers to a lower threshold point by $20 with a larger step at the end at the higher price point. He suggested that it was important to recognize that it was rare companies received the whole $8 benefit because of the interaction of the minimum tax. In practice, there was fairly little of the credit that could be used at prices below about $70. The real change was the effective subtraction once companies were above the minimum tax cutoff. He indicated that it was a reduction of $2 per barrel in credit benefit. Once the price of oil reached above $80, $90, and $100 it amounted to about a tax increase of about $300 million. It was $2 per barrel that would not be subtracted from tax by the typical tax payer. The impact at lower prices would be fairly modest. Mr. Alper continued that as far as the language, it was an awkward structure that the credit jumped in dollar increments. He supposed that if a company made $109.99 and went to $110 in gross value, they would be losing $1 in value when they gained a penny in oil price. He opined that it would be nice if the formula was smoother. He thought it could be done with a statutory straight-line formula and create the same net affect. However, it was an issue that had not been resolved during the SB 21 deliberation. The bill also created a $3 drop at $110, dropping it to zero, instead of a $1 change, with a one penny increase in price, it became a $3 change. He indicated that the graph on slide 48 illustrated his point. Representative Guttenberg asked Mr. Alper to explain the rationale for the $8 credit. Mr. Alper discussed the $8 credit compared to the $5 credit and to the zero credit. First, he would go through the legislative history of SB 21. As originally proposed by the previous governor's administration, there was a 25 percent flat tax. The idea behind the flat tax was to create a progressive curve in which the effective tax was higher at high prices and lower at low prices. The Senate proposed a 35 percent tax with a $5 per barrel credit. At expected prices of $100 or $110 per barrel, the tax was revenue neutral with a little more money at high prices and a little less at low prices. Incentivizing production was only a talking point. He did not know whether the per barrel credit specifically incentivized production, as most of the barrels were already in production. He continued that going from $5 to a sliding curve was a late amendment that was offered in the House Resources Committee. The intent was to add slightly more progressivity. In exchange, there would be a larger benefit at the low end. The $6, $7, and $8 found its way into the formula that created a much lower tax at oil prices below $100 or $90 per barrel. Originally, it was a correction to the progressivity calculation. He was unsure of the rational behind moving the per barrel credit from $5 to $8. 9:58:35 AM Mr. Alper moved to the graph on slide 48. The blue line showed existing law. He explained that the Alaska North Slope (ANS) price was roughly $10 higher than the well head price. The graph showed the usable rate of per barrel credits at different prices. He reviewed the chart from right to left. At $160 per barrel the usable rate was zero. At $150 per barrel it was $1, and the ladder continued to step upwards. At around $90 per barrel a company earned the full $8 credit. He continued that at $70, when the minimum tax got in the way, the use of the credit fell dramatically, and companies were not able to use it. He had mentioned this drop when he discussed the migrating credit earlier in the meeting. Companies lost the ability to claim the entire $8 as prices got lower. The ability to use the per barrel credit fell to zero at around $50 per barrel. Mr. Alper continued that the amendments in Section 14 replaced the blue line with the dotted red line. He explained that everything was $20 over or $2 less. There was still the issue of not being able to use the credits below $70. The real impact was in the range between $80- 110. He highlighted that at a gross value of $110 the credit dropped from $3 to zero. The assumption was made that above $110 per barrel companies did not need a per barrel incentive and the 35 percent tax was adequate for the state. He noted a very large drop of $3 per barrel which equated to approximately $450 million at $120 per barrel price point. Representative Grenn asked Mr. Alper to place some sideboards on the word smoother. Mr. Alper responded that the formula in statute currently stated that if the gross value was more than $80 and less than $90 it was "X." If the gross value was more than $90 and less than $100 it was "Y." He suggested that a formula could be created that would result in a straight diagonal line that would reflect the same curve. He noted an amendment offered on the House Floor by Representative Tarr during the debate of SB 21 in 2013 that did the same thing. Vice-Chair Gara thought the change really did not go into effect at $65 to $70 per barrel. Mr. Alper responded that once prices got low and the per barrel credit essentially became unusable because of the minimum tax getting in the way, changes to the number did not matter that much. An affect could not be seen until getting over the minimum tax crossover in the $70 range. Vice-Chair Gara asked if the same was true with the new bill. Mr. Alper responded affirmatively. Although it was a different per barrel credit, the minimum tax crossover was the same. The slight gap between the red and the blue lines on the left side of the chart reflected the 5 percent versus 4 percent minimum tax change. Vice-Chair Gara asked when the department was forecasting $70 per barrel oil. Mr. Alper thought it was about 4 or 5 years into the future. Co-Chair Seaton interjected that the Senate's version of SB 21 had a flat $5 per barrel credit. It was seen as progressive because the $5 flat credit was a much smaller portion of the price as the price per barrel climbed to the range of $160-$200. It was supposed to be a progressive element but did not have much of an effect until the price increased to much higher levels. It started stepping down from $5 in dollar increments. He pointed to the blue line. He noted the last-minute change in the committee substitute. No one knew where the stair step above $5 came from. The change above $5 was very late in coming. Mr. Alper thanked Co-Chair Seaton for the information. Co-Chair Seaton continued to provide some history on SB 21. Mr. Alper appreciated the information. 10:04:46 AM Mr. Alper moved to slide 49. He explained that the slide showed the change to the minimum tax and the change to the per barrel credit in total state revenue. The flatter lines represented the minimum tax curve. The steeper lines were the net tax curve which dropped to zero. The tax that the state paid was the crossover between the two lines. Currently, Alaska's revenue could be seen as the blue line meeting the dark blue line. At $50 or $55 revenue would be well below $500 million. At $75 per barrel revenue steeply increased to where the state was making $2 billion to $2.5 billion. The change to the minimum tax was the shift from the blue line to the red [orange] line. The shift in the per barrel credit was the shift in the dark blue line to the yellow line. The state would be paying the orange to yellow line which would be reflected in the tax increase of about $50 million in the $50 to $75 range. There would be a larger tax increase above $75 represented by the gap in the two steeper lines on the chart. Mr. Alper turned to slide 50 and addressed Sections 15 and 17 of the legislation regarding the dry hole credit. The language was new and entailed that there was an exploration credit that was cashable for companies prepared to declare failure. Companies would report the work they had done, declare they would not go into production, pay their vendors, and return their leases to the state. He agreed with the chairman that if companies wanted to give their data to the state it would be helpful. Companies would not be able to use the related expenditures for another credit. He had a couple of technical concerns. First, he conveyed that as the bill was written the benefit would apply in Cook Inlet. However, all Cook Inlet credits were eliminated by the legislature in the prior year. He just wanted to make the committee aware of the potential of adding another credit benefit in Cook Inlet. He suggested that it could also be carved out of statutory language. His second concern was related to a company getting a fraction of their lease expenditures paid back at a discount if they were prepared to declare a failure. It would be linked to the idea of carried forward lease expenditures. It would be a separate credit and tied to the exploration language with a different set of criteria and rules for allowable expenditures. It potentially created a double dip problem. He provided an example of double dipping. 10:08:55 AM Mr. Alper moved to slide 51 and addressed cash limits in Section 19 of the legislation. The section talked about the ability to earn cash from the tax credit fund. It used to not have restrictions other than the 50,000 barrels per day number. In the previous year, the legislature added the 70 million per company per year restriction with the haircut provision on the second $35 million. He noted that the bill reduced that from $70 million to $35 million and repealed the section later in the bill that provided for the 25 percent haircut on the amount above $35 million. They were obviously linked with each other. The per company per year cash limit became $35 million and created a flat ineligibility for cash if production was below 15,000 rather than 50,000 barrels per day. It was a provision from the House version of HB 247 that went over to the other body in the prior spring. He relayed that although those were the changes in Section 19, there was a broader issue. Much of this was more or less superfluous to the other changes made in the bill because the state was no longer offering cashable net operating loss credits on the North Slope. All of the sections that talked about limits and what companies could receive cash would only apply to those few cashable credits. The amendments to Section 19 would only be restricting the issuing of cash credits for Middle Earth activities. Currently, no one was claiming $35 million per year or more. The amendment might not have any material impact in the near future. Co-Chair Seaton asked if the restriction would not apply to the currently issued certificates if companies wanted to redeem them for cash. Mr. Alper replied in the affirmative. The limits did not apply to things existing before the effective date. Similarly, the $70 million in current law did not apply to the $500 million in certificates issued before January 1, 2017. He also noted that the other limit with the resident hire percentage for HB 247 did not apply to the $500 million of in-hand certificates from before January 1. Representative Pruitt had a question about the change in cashable credits from 50,000 to 15,000. He wondered about the number of eligible credits at 50,000 and at 15,000. Mr. Alper relayed that the majority of the companies that had received cash credits had zero production which would not change. He reported that four companies were above the 50,000 taxable barrel level. He was unsure of the number of companies that fell within the range. He mentioned companies such as Eni and Caelus that were in the range. There were also companies such as Anadarko and Chevron who had junior minority interests in some of the larger legacy fields. They could fall into the range. He did not know if any of the companies were above or below 15,000 barrels per day. He thought, for the most part, they were below 15,000. 10:13:08 AM Representative Wilson mentioned having a lot of discussion regarding the range between 15,000 and 50,000. It was her understanding only one company would be affected. She expressed her concern about targeting one particular company. Mr. Alper spoke on slide 52. He relayed that there had only been one company that had received more than $200 million cash credits in a single year. There had been 5 circumstances where a company received between $100 million and $200 million in a year, and 11 instances where a company received between 450 million and $100 million. He highlighted a current issue which was that of the $500 million pending and awaiting cash, there were 3 different companies with more than $100 million worth of certificates in hand. They were not limited per the new $70 million cap. Should there be a large appropriation in the current year to pay off the old balance, those companies would not be restricted, and the state would be able to pay the $100 million or more to those three entities. Mr. Alper continued to slide 53 to explain the gross value at the point of production not being able to go below zero. He relayed that the gross value was the market price minus transportation costs. Generally, transportation costs were not supposed to exceed the value of the oil. If they did, the negative value could migrate into the other tax calculation and be used to offset taxable profits from other production from the producer. It had been possible in early 2016 when the price of oil dropped to $30 per barrel and below. He relayed that the average price of transportation was $10, but there was a wide range of costs depending on the specific circumstances of the location of the oil and where it was going. If oil were to go below $20 per barrel, it could impact more properties. Mr. Alper advanced to slide 54 that showed the chart of tariffs for the major North Slope units. He noted the box around Point Thomson. Point Thomson was a new and expensive project with low production presently. The regulatory tariff on the Point Thomson pipeline, which spanned 22 miles from its production site to the nearest connection to infrastructure, was $17.56. Point Thomson's total tariff was $26.54 to get product to Valdez in addition to a $3 marine transport cost. He relayed that it cost nearly $30 to get Point Thomson oil to market. If the price of oil was below $30, the production would have a negative gross value that could find its way into the tax calculation. The change made in Section 23 of the bill would indicate that for tax purposes, it would be considered zero. Companies would not be able to use a negative number specifically from the gross value calculation to be used elsewhere in the tax calculation. Mr. Alper turned to slide 55 regarding carry forwards: This is the major change to how losses are treated on the North Slope, and incorporates advice from LB&A consultant Ruggiero • Current law- company earns a credit based on a percentage of a loss Losses become a 35% credit, eligible for cash • HB111, 50% of lease expenditures carry forward to a future year to offset taxes · Since carry-forward balances can offset taxes, this is equivalent to a 17.5% NOL rate (50% of 35%) · Adds an "uplift" (Sec. 26) where carry-forward balances can earn interest for seven years Mr. Alper indicated that Section 25 housed the largest change. He indicated that the section outlined how to take something that was previously a loss and turn it into a carry forward. Under current law, a company earned a credit based on a percentage of their loss, a 35 percent credit. The credit was tied in many ways to the 35 percent statutory tax calculation. The way the bill changed it was to take 50 percent of the loss (excess lease expenditures) and carry them into the following year. Presuming there was production and value in the following year, it would offset the following year's value. The equivalent would be as if it were a 17.5 percent NOL credit rate. The reason for that was because if a company lost $1 and carried forward $.50 and offset a 35 percent tax with it, the company would receive 50 percent of 35 percent of a tax benefit, or a NOL rate of 17.5 percent. An amount would get added to compensate for time and uplift. Essentially, the state would be paying interest on carry forward losses. The uplift would be such that for up to 7 years a company could earn interest on their loss from their initial year until they were able to use it in the future. If the company were to wait more than 7 years to use it, there would be no specific sunset on the value. However, the state would stop paying interest. Mr. Alper advanced to slide 56 which showed the carry forward calculation. He reviewed an example. He relayed that the following section of the bill addressed the uplift. Mr. Alper turned to slide 57. The slide talked about why the 35 percent NOL rate might be slightly off. It had to do with amendments to SB 21. He elaborated that when the change was made from a 25 percent tax with zero credits to a 35 percent tax with a per barrel credit, it was perceived to be revenue neutral. The chart showed the revenue from a single barrel of oil under SB 21 in its original form and as it was amended. A barrel of oil priced at $100 with $40 in costs, net $60 of taxable net. At the 25 percent tax rate, the tax equaled $15. At a tax rate of 35 percent with a $6 per barrel credit it would also equal $15. The revenue was the same as far as the state was concerned. The question was, when the amendment was made, did the NOL credit rate get increased from 25 percent to 35 percent. He thought it was a reasonable question. He noted that the House version of HB 247 reduced the NOL credit rate to 25 percent over several following years. Vice-Chair Gara asked Mr. Alper to return to slide 56. It was easier for him to understand the effective tax rate and how much the state was giving away in per barrel credits. The per barrel credit had always been confusing to him. In looking at slide 56, it appeared that even with the change in the bill, at expected prices, the deduction rate was a higher percentage than the tax rate a company paid. In a world where most people received a deduction equal to the tax rate, not higher, they would still be allowed a higher deduction rate percentage than a company paid as its tax rate. He wondered if was understanding the slide correctly. Mr. Alper would rather wait until he reached slide 58 to respond. The slide graphically showed effective tax rates. He commented that the attempt to reduce the NOL rate was an attempt to make the credit rate about equal to the effective tax rate. Whereas, at 35 percent it was currently higher at all price points than the effective tax rate. 10:22:17 AM Mr. Alper continued speaking to slide 57. He relayed that the slide showed the side-by-side calculation. He highlighted the NOL credit rate in yellow. He asked why the credit rate increased when the effective taxes stayed the same. Mr. Alper turned to slide 58 to answer his question. He reported that the solid blue line reflected the effective tax rate of Alaska's Clear and Equitable Share (ACES) - the tax plus the progressivity minus the capital credit at a 2018 spending rate. He highlighted the steep progressivity with ACES which yielded a very high effective net tax rate at higher prices. The net operating loss rate, the credit earned by North Slope companies losing money, was 25 percent represented by the dotted blue line on the chart. There was a point at higher prices which the effective tax rate was above the credit rate, and there was a point at lower prices below about $85 which the effective tax rate was below the NOL rate. It was somewhere in the middle. Mr. Alper continued that the red solid line was the effective tax rate under SB 21. It was the number Vice- Chair Gara had referred to. The effective tax rate as a percentage of profits went down and tailed up again at lower prices because of the hard floor in SB 21. Once a company went below the minimum tax and companies were still paying 4 percent, the 4 percent could become a very large percentage of their profits. The minimum tax was the upward tail of the red line on the chart. Mr. Alper continued that the dotted red line was the NOL rate for SB 21, which was above the effective tax rate on the entire graph. The red line was not reached until oil reached $160 per barrel. The thought was that a lower number should be the appropriate NOL credit rate. He highlighted the green line representing the effective NOL rate of the committee substitute from the House Resources Committee - the 17.5 percent reflecting 50 percent not uplifted of a company's carry forwards. He noted the dark green line which represented the effective tax rate for HB 111. He pointed to the shift to the left of the per barrel credit on the slightly higher minimum tax on the left side to the tail. The effective tax rate would be below the NOL rate between $60 and $80 and above the NOL rate at higher and lower prices. Mr. Alper moved to slide 59. He did not see much difference between a NOL credit or a carry forward. By making it a carry forward, it automatically became non-transferable. The bill was written to create carry forwards which was more comparable to what other jurisdictions did that allowed companies to reclaim their costs once they went into production. Mr. Alper scrolled to slide 60. He noted some concerns with Section 25. The way the 50 percent provision was written might further reduce the amount another 50 percent every year. For instance, if a company had $100 million in the current year and $50 million in the following year, it might become $25 million in year 3. The language might require a technical fix. The carry forwards also appeared to be available statewide. It went back to the Cook Inlet question whether it was the committee's intent to expand the benefit and recapture for tax purposes to Cook Inlet. There was a question of how to apply carry forwards when a minimum tax was in place. For example, if a company had $1 billion in carry forwards and came into production and began earning $200 million per year, the question would be whether they would offset the entire $200 million to zero for 5 years and still pay the minimum tax. He suggested other ways to handle the minimum tax as well. He thought the issue needed clarification in the bill. He noted that the department had done modeling in one way whereas, Mr. Ruggerio had modeled it another way. There also might be a need for conforming language regarding limiting deductions for calendar years. 10:28:45 AM Mr. Alper discussed slide 61. He relayed that another possible concern was that the carry forwards were not supposed to be usable until the company got into production. It was possible that a company could invest $2 billion into a project then decide it was no longer workable. The company could then sell their entire Alaska subsidiary to a major producer at a great discount. The company would be buying $2 billion worth of carry forward lease expenditures which could then be used to offset their production tax value from Prudhoe Bay and Kuparuk. He thought some sort of ring fencing mechanism might be needed to make sure the carry forward expenditures were tied to the project or property rather than other values. HB 111 was HEARD and HELD in committee for further consideration. Co-Chair Seaton indicated that the meeting would have to stop due to the House Floor session beginning. He indicated that the committee would pick up with Section 26 of the bill at 1:30 pm and would be hearing industry testimony.
|HB 111 3.22.17 Rep. Gara Repsol Press Release Updated.pdf||
HFIN 3/22/2017 9:00:00 AM
|HB 111 DOR Response Letter to House Finance Committee - 4.7.17.pdf||
HFIN 3/22/2017 9:00:00 AM