Legislature(2015 - 2016)BARNES 124
03/21/2016 01:00 PM RESOURCES
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HB 247-TAX;CREDITS;INTEREST;REFUNDS;O & G 1:05:58 PM CO-CHAIR NAGEAK announced that the first order of business is HOUSE BILL NO. 247, "An Act relating to confidential information status and public record status of information in the possession of the Department of Revenue; relating to interest applicable to delinquent tax; relating to disclosure of oil and gas production tax credit information; relating to refunds for the gas storage facility tax credit, the liquefied natural gas storage facility tax credit, and the qualified in-state oil refinery infrastructure expenditures tax credit; relating to the minimum tax for certain oil and gas production; relating to the minimum tax calculation for monthly installment payments of estimated tax; relating to interest on monthly installment payments of estimated tax; relating to limitations for the application of tax credits; relating to oil and gas production tax credits for certain losses and expenditures; relating to limitations for nontransferable oil and gas production tax credits based on oil production and the alternative tax credit for oil and gas exploration; relating to purchase of tax credit certificates from the oil and gas tax credit fund; relating to a minimum for gross value at the point of production; relating to lease expenditures and tax credits for municipal entities; adding a definition for "qualified capital expenditure"; adding a definition for "outstanding liability to the state"; repealing oil and gas exploration incentive credits; repealing the limitation on the application of credits against tax liability for lease expenditures incurred before January 1, 2011; repealing provisions related to the monthly installment payments for estimated tax for oil and gas produced before January 1, 2014; repealing the oil and gas production tax credit for qualified capital expenditures and certain well expenditures; repealing the calculation for certain lease expenditures applicable before January 1, 2011; making conforming amendments; and providing for an effective date." [Before the committee was the proposed committee substitute (CS) for HB 247, Version 29-GH2609\P, Shutts, 3/18/16, adopted as the working document on 3/19/16.] 1:06:29 PM CO-CHAIR NAGEAK stated that the Department of Revenue will provide the committee with a presentation on Version P. KEN ALPER, Director, Tax Division, Department of Revenue (DOR), on behalf of the governor, provided a PowerPoint presentation entitled, "Oil and Gas Tax Credit Reform, Initial Reaction to CS HB 247(RES)\P." He began by thanking the committee for the opportunity to respond to Version P, the proposed committee substitute for HB 247. He explained that slides 2-3, "History of Oil and Gas Production Tax Credits," lay the groundwork on [the reason for HB 247]. The state's program of refunding tax credits began to grow in roughly 2010, he said, although the state has refunded tax credits since fiscal year (FY) 2007. Drawing attention to the chart labeled, "Refunded Tax Credits by Region," he pointed out that the trend over the last two or three years has been from being a very North Slope centered expenditure to a very non-North Slope, predominantly Cook Inlet, centered expenditure. For 2015, the last complete year, the expenditure on refunded tax credits was $628 million, of which a little over $400 million was for outside the North Slope. MR. ALPER moved to slide 3, recounting that last year the governor line-item vetoed the tax credit appropriation language limiting the spend for the current year to $500 million. Of that $500 million, about $473 million has actually been spent. Of that $473 million,  percent was non-North Slope, so the trend is continuing from last year - about $200 million was from North Slope and $273 million was from Cook Inlet and the Interior. The payout in credits was predominantly on credits that were earned based on activity that took place in calendar year 2014. The department is anticipating $700 million in total demand, but those will generally not be issued until this summer and will be paid in the next fiscal year. The gap of $200 million between the $500 million authorized and the $700 million expected is built into DOR's forecast number for FY 2017. 1:09:10 PM MR. ALPER displayed slide 4, "Major Bill Themes," and noted that the governor's bill as originally brought before the committee had several larger themes of what the administration was trying to do and why. One theme was to reduce the state's annual cash outlay, something that is very important in a cash-constrained environment. Another theme was to protect the net operating loss [credits] because those level the playing field by providing a benefit to the entities trying to establish themselves in the oil patch as opposed to the incumbent producers. Another theme was to put limits on repurchasing so that single companies do not get very large amounts. The other themes were to: strengthen the minimum tax so that the state's minimum revenue in these low price environments would be protected in some way; seek more open and transparent activity so names and numbers could be talked about better; and honor and pay the credits earned to date through any transition period. MR. ALPER showed slide 5, "Major Bill Concepts in Governor's Proposal," and stated he will discuss the six major concepts in the governor's original proposal, how those concepts evolved, and how they have been amended in Version P. Those concepts are: the exploration credits; the Cook Inlet drilling credits; the repurchase limits; the removal of exceptions/loopholes; the strengthening of the minimum tax; and other smaller provisions. 1:10:27 PM MR. ALPER presented slide 6, "Summary of Major Bill Provisions, Exploration Credits," and examined the exploration credits. For the most part, Version P keeps intact what the administration was looking to do. For the North Slope and Cook Inlet, the alternative credit for exploration under AS 43.55.025(a) expires on July 1, 2016; for Middle Earth this credit expires in 2022. The original bill allowed these to expire, as does Version P. The "super credits," the jack-up rig credit in Cook Inlet and the frontier basin credit in the Interior expire this July. These credits are allowed to expire under both the original bill and Version P. A provision in the original bill preemptively repealed several unused, dormant, exploration credit programs [in AS 38.05.180(i) and AS 41.09] in order to clear the decks of those and to clarify that it is not the intention to have stand- alone exploration credit programs on the books. This provision was retained in Version P. MR. ALPER continued examining exploration credits on slide 6, explaining that the original bill included a specific Department of Natural Resources (DNR) data sharing requirement [from AS 43.55.023(b)]. The department worked with the committee to try to revise that and make it work, but in the end the committee chose to not keep this provision in Version P, primarily because there is a data sharing requirement under AS 43.55.023(a)(2), the capital credit for exploration that does provide the data to DNR. Since that credit is going to remain on the books another data sharing provision does not need to be explicitly added in the bill's language. Responding to Representative Josephson, he clarified that Version P maintains the 20 percent [qualified capital expenditure] credit; AS 43.55.023(a)(2) allows that credit to be paid for exploration expenses and that spending includes a link to the language in the exploration credit that says seismic and other data must be shared with DNR, data which DNR can eventually release to the public. 1:12:37 PM MR. ALPER brought attention to slide 7, "Summary of Major Bill Provisions, Cook Inlet Drilling Credits," and said that the more material change in Version P was made to the Cook Inlet drilling credit section of the bill. The governor's original proposal looked to repeal completely the 20 percent [qualified capital expenditure (QCE)] credit [AS 43.55.023(a)] and the 40 percent [well lease expenditure (WLE)] credit [AS 43.55.023(l)] effective July 1, 2016. The decision in Version P was to phase out the WLE [credit] over 2017 and 2018 and to keep the QCE credit in place until 2022. He said 2022 is a forward looking year tied to the plan for a broader Cook Inlet tax reform bill. The governor's original bill looked to maintain the 25 percent [net operating loss (NOL)] credit, while Version P reduces it from 25 percent to 10 percent [beginning in 2017]. MR. ALPER continued on slide 7 and outlined the impact of the changes in the aggregate of Version P. The governor's bill, he said, was looking to reduce the total support for spending in Cook Inlet to 25 percent beginning in FY 2017. Version P reduces that total support to 30 percent beginning midway through FY 2018, a delay of 18 months in the full implementation versus what the governor's bill proposed. By preserving the 20 percent capital credit and reducing the loss credit, Version P changes somewhat the actual companies that will be receiving the credit support, specifically the companies outside the North Slope that are producing oil and gas and that if profitable are held harmless under the Cook Inlet tax caps that go back to the production profits tax (PPT) bill of 2006. Under Version P, those companies that may be profitable and not paying substantial taxes would be able to receive the 20 percent capital credit, whereas in the governor's original bill those companies would not get any credit support. Version P also adds language setting up a legislative working group to get to planning towards the broader Cook Inlet tax reform that needs to be on the books by 2022. 1:14:50 PM MR. ALPER addressed slide 8, "Summary of Major Bill Provisions, Repurchase Limits." He noted that these are statewide changes, although predominantly understood North Slope projects. The governor's original bill proposed a per company per year cap of $25 million, meaning if a company earned credits in excess of that number those would have to be carried forward into the next year or held onto until that company had a tax liability. Version P has a $200 million per company per year cap. The governor's original bill also looked at three other provisions: to exempt any payment at all for very large companies with an excess of $10 billion of annual revenue; to provide an Alaska resident hire provision; and to provide a 10-year sunset on carried-forward credits where those credits could be lost outright. Version P eliminated those three provisions. MR. ALPER said the impact of the $200 million per company per year cap is to protect the state in the event of a very large outlier project, such as proposed by Mr. Armstrong [of Armstrong Oil & Gas Inc., owner of the Pikka Unit]. For example, DOR's modeling of a comparable project shows that the state's credit liability in advance of getting substantial revenue could reach as much as $800 million per year. He clarified that Version P, as currently written, does not consider the possibility that if Mr. Armstrong were to proceed with this project and bring in three partners, each of the four partners could receive that $200 million cap and the state would potentially have an $800 million liability. 1:16:27 PM REPRESENTATIVE JOSEPHSON posed a hypothetical scenario in which Armstrong Oil & Gas Inc. has two partners and asked whether the state's liability would become $2.4 billion or would remain $800 million. MR. ALPER replied that the modeling done by Tax Division staff looked at the economics of the overall project life cycle. A large project like that had about $9 billion in capital expenditure associated with it, so the lifetime total amount of credits was about $3 billion over several years. The peak year of credits, regardless of the number of partners, was $800 million. The $200 million cap if it were a single company would change that project somewhat. If the project owner came in with multiple partners it would be less of a change, meaning that three partners or four partners could earn $600 or $800 million collectively and only the difference between that number and $800 million would be carried forward into the next year. 1:17:29 PM REPRESENTATIVE SEATON asked what the state's exposure would be in a scenario of 750 million barrels of shale oil with multiple players within a unitized area. MR. ALPER responded that the North Slope taxpayers pay tax as a company based on the company's total North Slope operation. The state does not have any sort of ring fencing from unit to unit. Regardless of how many partners there were, each could earn up to the $200 million cap. The governor's original bill was structured the same way as Version P, only the limit in the original bill was $25 million instead of $200 million. With a 35 percent net operating loss credit, which is the primary North Slope credit, a company would need to have $471 million a year in operating loss at 35 percent to earn the full $200 million. So, multiple partners in a shale development earning at that level would be a very large project. 1:19:09 PM MR. ALPER resumed his presentation, turning to slide 9, "Summary of Major Bill Provisions, Repurchase Limits (cont'd), Historic Notes on large annual credits." He explained that a look was taken at DOR's historic record from 2007 through the current fiscal year to get a sense for how many of these large payments there have been over time. There has been only one instance of a company in a single year earning more than $200 million a year in tax credits. There have been five instances where one company received between $100 and $200 million in a year. And, there have been eleven times where a company has received between $50 and $100 million [in one year]. Those sixteen transactions are the difference between what the governor's original bill was suggesting. There is an even larger number between $25 and $50 million, he added, but there was not enough time to do that much research. 1:19:59 PM REPRESENTATIVE HERRON, in regard to repurchase limits, posed a scenario of four partners. He asked whether all partners would automatically get the credits or whether a process must be followed such that some partners would get more than others. MR. ALPER replied that the answer depends on who the partners are and the ratio of their expenditures. Four equal partners, each spending $571 million per year, could each max out at the [$200 million] level. It is an operating loss credit and to qualify all those expenditures would have to qualify; certain types of activities do not qualify for credit. If some of those credits had a smaller participation, a company's credit would be capped at 35 percent of its actual spend. If a partner in question was a major producer that is ineligible to get cash because of the existing limit in statute where a company with more than 50,000 barrels a day in production cannot get cash credits, that producer would have to use its credits to offset its tax liability. If the producer had a tax liability, the producer could wipe it down to zero. But, if the producer does not have a tax liability, the producer would have to roll it forward into the next fiscal year. REPRESENTATIVE HERRON, regarding the historic instances, asked whether Mr. Alper has a ballpark figure of how many companies have received $49 million and below. MR. ALPER answered that that would be hard to do. Including the current fiscal year, he said, a touch less than $3.5 billion in checks for credits have been written. "Looking at the numbers before us," he continued, "this represents about a billion and a half dollars, I'm guessing; so, another $2 billion in smaller credits in smaller numbers." REPRESENTATIVE HERRON inquired whether that is spread over 20, 30, 40, or 50 companies. MR. ALPER replied it is probably a much larger number. There are some very small numbers, there are some very small junior partners in large fields who happen to own a little acreage who are getting a tiny share of it. There is a very large number of transactions in a year. There is a concentration in a few big ones, but there is a lot of line items. 1:22:20 PM REPRESENTATIVE JOSEPHSON addressed the previously mentioned hypothetical project of 750 million barrels, a large Pikka-sized project, with $800 million theoretically if there was or was not a number of partners. He asked whether the $500-$600 [million] in repurchasables would be in addition to the $800 million, such that the state's exposure with what Mr. Armstrong contemplates would be $1.4 billion at least in FY 2017. MR. ALPER responded that DOR currently has no such projects in its forecast. If, say, DOR is forecasting $600 million in a given year and then a company comes in and says it is going to spend $2 billion next year, then, yes, DOR would have to adjust the forecast by 35 percent of that in addition to what it is already forecasting. 1:23:23 PM MR. ALPER returned to his presentation, noting that the historic instances outlined on slide 9 are for both the North Slope and Cook Inlet, although the larger numbers are concentrated in the larger North Slope projects that have occurred. MR. ALPER moved to slide 10, "Remove Exceptions/Loopholes," and thanked the co-chairs as well as committee staff for working with DOR and allowing DOR to make its case on this. For the most part, he said, these issues were left intact in the committee substitute. Under Version P, a company cannot use the gross value reduction (GVR), the new oil tax reduction, to increase the size of a net operating loss credit. As was shown by the legislature's consultant, Mr. Mayer of enalytica, this could lead to instances of companies getting very large credits, in some cases greater than 100 percent of their loss. The other provision kept in Version P is the municipal utility exception where if a municipal utility is selling a portion of its gas to a third party, the utility only gets to deduct a pro-rata share of its lease expenditures against that sale for the purpose of calculating any credits. MR. ALPER displayed slide 11, "Strengthen Minimum Tax," and pointed out that several subsections in the original bill looked to strengthen or increase the size of the minimum tax floor. Provisions that would have impacted the legacy/major producers, included: the idea that a [net operating loss] credit in an extended low price scenario cannot be used to reduce payments below the [4 percent] floor; the idea that at true-up companies cannot use per-taxable-barrel credits earned in one month against taxes accrued in another month; and the idea of increasing the minimum tax from 4 percent to 5 percent. Provisions that would have impacted new oil producers included: extending the minimum tax to GVR-eligible new oil, which currently can go as low as zero; disallowing the small producer credit from reducing tax payments below the floor; and increasing the minimum tax from 4 percent to 5 percent. However, he said, all of the aforementioned provisions impacting the minimum tax are removed in Version P. 1:26:09 PM MR. ALPER reviewed slide 12, "Summary of Major Bill Provisions, Other Provisions." Regarding interest rates, he thanked the committee for keeping in Version P the provision for compound interest. He said DOR strongly believes that the simple interest resulting from a late amendment to Senate Bill 21 [passed in 2013, Twenty-Eighth Alaska State Legislature] was an inadvertent change. The department thinks compound interest is a more appropriate way to treat this. However, he continued, Version P maintains the current statutory interest rate of 3 percent above the federal discount rate, currently that is 4 percent interest. The original bill proposed 7 percent over the federal rate. Prior to the reforms of Senate Bill 21, the rate was 11 percent above the federal rate. In regard to confidentiality and transparency, he noted that the original version of HB 247 proposed making public the names of those companies receiving credits and how much each company received, but that section is removed in Version P. Another provision in the original bill was that transportation costs cannot reduce gross value at the point of production below zero, and this section is removed in Version P. However, Version P does preserve the authority to use a tax credit certificate to pay off another obligation to the state. Currently if a company owes taxes, DOR can withhold credit certificates to help pay those taxes, but DOR was looking to expand that to other liabilities such as royalty obligations that might be unpaid. While Version P substantially rewrites and restructures this provision, the net effect is roughly the same - DOR will have the authority to make sure that state agencies are kept whole. 1:27:42 PM REPRESENTATIVE TARR observed that in Version P, Section 7 is about the natural gas storage facility credit, Section 8 is about liquefied natural gas storage facility credit, and Section 9 is the in-state oil refinery infrastructure expenditure credit. Noting these were not included in the original version of HB 247, she requested Mr. Alper to discuss these provisions and how they apply to the outstanding liability of the state. MR. ALPER answered that Sections 7, 8, and 9 of Version P are purely conforming changes; similar references were made to these credits in Sections 9, 10, and 11 of the governor's original bill. These three credits are earned inside the corporate income tax statutes, AS 43.20, but are unique in that among the corporate income tax statutes they are cashable, they can be repurchased using money in the tax credit fund, AS 43.55.028. Restrictive language needed to be added in those three sections to say the state does not want to pay those if a company owes other obligations to the state. Although it has been rewritten dramatically by the legislative drafters, the net effect is the same. What is seen is new language that says "Subject to the requirements in AS 43.55.028(e)." He offered his belief that the committee will see an amendment eventually that changes that to (j). Version P, Section 17, subsection .028(j) is new language that talks about the mechanism by which the state can ensure that it does not pay out tax credits in cash if a company owes another obligation to the state. 1:29:45 PM REPRESENTATIVE JOSEPHSON drew attention to the last statement on slide 12 regarding the other provisions of Version P, "Preserves authority to use Credit certificates to satisfy obligations to the state before repurchase." He recalled Mr. Alper's inference that this could be lived with. He said the basic distinction he sees is that under the governor's original bill the state would make no payment whatsoever until other obligations were satisfied, but under Version P only the difference would be paid, not the full amount. Although he could see industry saying that [the original version] was too coercive, he said he views [Version P] as a serious distinction. MR. ALPER clarified that it was never the administration's intent to hold back the whole credit. The discussion among committee staff and himself was that the way the administration wrote it might be interpretable that way, but that was not the administration's intent. The desire is only to pay off any obligation that is actually owed to the state agency and still pay the company the remainder of the credit. Much of what is seen in Version P clarifies what the administration's original intent was. Version P adds another restriction in Section 17 which requires a company to authorize DOR to pay the obligation on the company's behalf, with the alternative, he supposed, being that DOR is effectively an escrow account by holding the money on behalf of both the company and the state agency to which the company owed money, but DOR would be unable to pay the state agency without the company giving DOR affirmative permission to do so. 1:31:37 PM MR. ALPER continued his presentation, noting that slides 13-18 provide example scenarios of how the changes in Version P would impact different types of producers and developers in different parts of the state. He explained that these example scenarios are updates to similar slides that he provided in his original presentation in February. Regarding slide 13, "Bill CS Impact: Example Scenarios, North Slope Major Producer," he stated that for the North Slope major producer there is no change at any price as to how such producers would be impacted by the changes in Version P versus current statute. MR. ALPER showed slide 14, "Bill CS Impact: Example Scenarios, North Slope New or Smaller Producer," and explained that at higher oil prices there would be no change for new or smaller producers. However, for a new producer with an operating loss, either because prices are very low or because the new producer is still building out its field and operating at a loss even though it is producing and selling oil, the provision where the size of the NOL credit cannot be increased through the gross value reduction will have a material impact on those new and smaller producers. REPRESENTATIVE JOSEPHSON inquired whether he is correct in recalling that the governor's original bill projected that this feature might save the state $12 or $13 million. MR. ALPER replied that that may have been what he said a month ago and sounds about right. However, based upon more recent information that number is a bit larger, because with the prices as low as they are more companies are going to be impacted. 1:33:17 PM MR. ALPER resumed his presentation and brought attention to slide 15, "Bill CS Impact: Example Scenarios, North Slope New Project Developer." In this scenario, he said, the project developer would not have any change, with the exception of the very large project limited by the $200 million per company per year cap. That $200 million a year reflects 35 percent of about $570 million [a year] in capital spending for a single company to reach the $200 million limit. So, short of that threshold there is no change in Version P from current law, but above that threshold an outlier project like the Armstrong project would start bumping up against the $200 million cap. MR. ALPER looked to slide 16, "Bill CS impact: Example Scenarios, Cook Inlet Existing Producer," noting that Cook Inlet's current statutory tax caps sunset in 2022 and Version P maintains this. Under current law the state's credit support is 45-65 percent through the [qualified capital expenditure] and [well lease expenditure] credits, and existing producers are not eligible for the [net operating loss] credit. Version P would reduce the state's support to 20-30 percent in 2017, and then to 20 percent beginning in 2018 and through the sunset of the credits. The [qualified capital expenditure] credit is repealed in 2022 and Version P has lots of language that conforms to some statutory changes being made six years from now in anticipation of another change, a new tax regime that the legislature will develop sometime between now and then. Version P includes a new section that requires a [legislative] working group, a process with a report to the legislature sometime in the first session of the Thirtieth Alaska State Legislature in the early part of 2017. The report will have recommendations on different tax regimes for Cook Inlet as well as for the other non-North Slope areas of the state. In 2022, without any change, Cook Inlet will revert to a very high tax of 35 percent net profits tax with only a 10 percent net operating loss credit and no per- barrel or capital credits. This underlying tax system in Cook Inlet is quite high, he advised, and therefore probably unstable and that is why there is a need to find some way to replace it. The key thing and major change in Cook Inlet is that Version P continues support for capital spending at the 20 percent level while the governor's original bill would have replaced that number with zero. 1:35:53 PM MR. ALPER addressed slide 17, "Bill CS Impact: Example Scenarios, Cook Inlet New Field Developer," explaining that this developer would be building something but would not currently have sales. In 2017 that company would receive about 35 percent credit support, whereas presently that company receives 50-55 percent. Currently there is the blend of the 20 and 40 percent plus the 25 percent net operating loss. Version P reduces that to a blend of 20 and 30 percent plus the 10 percent net operating loss, for an aggregate of about 35 percent. That would only be for one year. Beginning in 2018, the reduction of the [well lease expenditure] credit to 20 percent, or alternatively its repeal, is an immaterial dollar value difference. The reduction of the [net operating loss] credit will result in a 30 percent credit support, the state will be paying for 30 percent of the cost of an ongoing development in Cook Inlet between the 20 percent [qualified capital expenditure] credit and the 10 percent [net operating loss] credit. Very large projects would theoretically be limited by the $200 million per company per year cap. However, with a 10 percent [net operating loss] credit it would be very, very hard to reach these kind of numbers, it would take extremely large investments by a single company to approach the $200 million per company per year cap in Cook Inlet. MR. ALPER drew attention to slide 18, "Bill CS Impact: Example Scenarios, Interior / Frontier Area Explorer." The Frontier Area super credits will sunset July 2016, he said, while the exploration credits are extended through 2022. Extending the exploration credits means that qualified expenditures will continue to be paid at 50 percent, roughly 40 percent through the exploration and 10 percent through the operating loss. Addressing the first bullet, he explained that once out of the exploration phase and into the development phase, a company's 20 percent capital credit and 10 percent [net operating loss] credit would result in about a 30 percent credit support, lining up with the Cook Inlet numbers beginning in 2018. 1:37:59 PM MR. ALPER explained that slide 19, "To-date Cost of Sunsetting Credits," provides an aggregate sense of the dollar values of the credits that are intended to be sunset, that without any legislative action are going to be disappearing over the next several years. Regarding the various exploration credits since 2007 until sunset, the state has refunded/paid out about $270 million in credits on the North Slope, and companies have used about $190 million to offset their tax liability. Off the North Slope in Cook Inlet and the Interior, the state has refunded about $160 million and nothing has been used against liability because typically the Cook Inlet explorers are not taxpayers and even if they were there is very limited tax liability against which to offset their taxes, their credits. Regarding the small producer credit, he explained that a single company can earn up to $12 million per year of this credit, and there are multiple companies that are able to claim it. Currently about $50 million a year is used on the North Slope and over the lifetime of the credit through 2016, there will be smaller numbers in the years as the credit trickles out. The state has given out $340 million in credits against liability on the North Slope and off the North Slope the state has given out about $60 million. He pointed out that small producer credits cannot be refunded, they can only be used to offset a tax liability. In sum total for these sunsetting credits, the state has either paid or foregone revenue of slightly over $1 billion between their start and now. 1:39:40 PM MR. ALPER reviewed slide 20, "Revenue Impact, Changes in CS, Preliminary Analysis of Bill Changes ($millions), (based on Fall 2015 Forecast)." He said the chart on this slide tries to summarize the fiscal impact of Version P. He advised that a fiscal note is forthcoming that takes this information and extends it into the future. Also forthcoming will be a more detailed fiscal note that DOR is working on to break out many of the subcomponents of the bill. He explained that this chart is based on the fall 2015 forecast. The  spring forecast was released in preliminary form this morning, he continued, but DOR has not yet internalized those numbers into this chart. Under Version P the expected reduction in state spending is $400 million in FY 2017, $325 million in FY 2018, and $200 million in FY 2019. In FY 2019 the drop-off is tied primarily to unknowns, not knowing what kind of money companies are going to be spending and therefore DOR cannot project credits. Under Version P the expected increase in revenue is $50-$100 million per year. "By eliminating the floor minimum tax changes," he said, "those numbers are reduced to zero ..." REPRESENTATIVE OLSON, regarding the forthcoming fiscal notes, pointed out that the committee's next meeting is tonight. He presumed Mr. Alper is not meaning tonight. MR. ALPER responded that he redrafted both of the fiscal notes, they are completed and in the review process, and need to go to through the governor's office. The Department of Revenue issued two fiscal notes, one tied to the bill itself and the increases in revenue in the detailed description of the bill, and the other tied to the fund cap, to the money that is going into the tax credit fund and the reduction in annual money coming out of it. He said the hope is that the committee will have the fiscal notes today or tomorrow morning. 1:41:32 PM MR. ALPER, at Representative Seaton's request, repeated his review of slide 20. The governor's original bill envisioned three sets of changes, he said. On the revenue side was the minimum tax changes - the hardening [of the floor] and the increase from 4 percent to 5 percent. The original bill foresaw $100 million in the near-term years and $50 million in the outer years. [In Version P] those numbers are reduced to zero because the minimum tax is left intact. On the side of reductions in spending there is the North Slope category and the non-North Slope category. There are two distinctions in the credits. The first is the credits that are eliminated or reduced; the law is actually changed to say that a certain credit is not going to exist anymore, or the number is being changed, or a loophole is being closed and people are not going to get that money anymore. The second is the credits that are deferred; the companies are going to continue to earn the credits, generally speaking the certificate credits, but because of the caps that would be added, most importantly the $25 million cap, the companies are not going to get all of that money and must instead roll it forward into a future year. By putting in the $200 million cap, the so-called deferred category is zeroed out, there are not going to be any credits deferred in our forecast the way DOR has it structured. Should something large happen, in other words should something like the Pikka project be sanctioned and large amounts of money start to be spent, DOR would modify the forecast and then there would be a fiscal impact to the changes in Version P based on the $200 million cap. Because of the numbers that DOR has in its forecast, the changes in Version P eliminate the savings from deferred credits, which then brings things to the credits eliminated or reduced. For the North Slope the main difference is the GVR/NOL thing, which is left intact; in FY 2017 and FY 2018 the number is essentially the same, that number is reduced at the number DOR forecast it. Because of the delay in the effective date, FY 2017 ends up being half of a year. For the Cook Inlet the changes are related to the change in the credits: the well lease expenditure credit is eliminated over an 18-month period rather than immediately, the [qualified capital expenditure] credit is maintained, and the [net operating loss] credit is reduced. The effect of those changes is going to have a smaller fiscal impact for three reasons: because the numbers are smaller; because the numbers are delayed; and because support is maintained for producers who would not otherwise be getting any credit support under the structure of the governor's bill. The best preliminary estimates, which will evolve over time, are that the fiscal impact of Version P will be a reduction in the state's credit outlay of roughly $50 million or $60 million per year. 1:45:15 PM REPRESENTATIVE JOSEPHSON understood that Version P would largely keep the state where it is currently, although this would be less so in Cook Inlet in the out years. He asked what the other oil and gas producing states that are suffering the exact same oil and gas recession are doing with their credit packages. MR. ALPER answered he is not aware of comparable credit packages in the U.S. Alaska is the only state in the U.S. that taxes on net profits and Alaska has a more sophisticated tax regime, a more sophisticated incentive regime. He offered his belief that North Dakota's gross tax does get reduced at low prices because it is structured as a tax and a surtax. He added that the Competitiveness Review Board has put out a good report that highlights those things. He said he would not say things are being kept intact; Version P definitely making changes, they are simply not as aggressive as was originally proposed by the administration. REPRESENTATIVE SEATON asked whether he is correct in observing on slide 20 that for Cook Inlet/Middle Earth in FY 2017 the difference between the governor's original bill and Version P is $130 million. MR. ALPER replied, "To the best we could determine in the limited time available, yes." Continuing, he said FY 2017 is a bit deceptive because the governor's original bill had an effective date of July 1 , the beginning of FY 2017; but Version P does not bring in any changes at all until January 1, , which is halfway through FY 2017. Also, [in Version P] the [well lease expenditure] credit in FY 2017 is only reduced from 40 percent to 30 percent, which is quite a material number in Cook Inlet. Thus, a couple of things conspire to drag down the number specifically in FY 2017 as a percentage of the total. 1:47:38 PM MR. ALPER reviewed slides 21-22, "Implementation Cost, Transition." Addressing slide 21, he noted that the governor's original bill was written with an effective date of July 1, 2016. In Version P the predominant effective date is January 1, 2017, with the full repeal or the full reduction to 20 percent of the [well lease expenditure] credit not until 2018, which is about an 18-month delay. Version P retains the fiscal note initially proposed in the governor's original bill, which adds a fund capitalization of $926,575,000. That is not a random number, he explained, it is the number that when added to the number in the operating budget comes up with an even $1 billion, which is the number the administration looked to for funding a transition from the current system into the new system. That is more than enough money to cover any anticipated expending in FY 2017, but [DOR] expects the legislature will need to appropriate more money before getting to the end of FY 2018 and then beyond. [The impact of Version P] on the transition is that the money is still there, but will not go as far and so more money will be needed to maintain the program because the program and the state's liability would be larger in years to come. REPRESENTATIVE SEATON understood the initial fund capitalization was included because the credit amounts were being dramatically reduced, but in Version P that is not going to happen or is not going to happen for a deferred time. Noting that Version P retains the fund capitalization, he inquired where that money will come from. MR. ALPER responded that his original understanding was that an appropriation would be made from the constitutional budget reserve (CBR) to endow this transition fund, and that that would be part of the larger package of implementing the governor's entire fiscal plan. RANDALL HOFFBECK, Commissioner, Department of Revenue (DOR), confirmed that the original intent in the governor's bill was an appropriation from the CBR to endow the fund. 1:50:24 PM REPRESENTATIVE SEATON asked where the authorization for a CBR vote or an intent for a CBR vote is located in Version P. MR. ALPER replied the fiscal note for fund capitalization was written by DOR, but in some ways was on behalf of the Office of Management & Budget (OMB). He understood that, like any fiscal note, it would be attached to the operating budget and become part of the final vote on the conference committee substitute of the operating budget. It would be a separate line item and a separate vote with the final passage of the operating budget. REPRESENTATIVE SEATON said he has not before seen fiscal notes just freely following that are not required or do not have statutory authority, and the fiscal note is instituting the statutory requirement proposed in the bill. He asked whether it is in here or whether this is just a proposal to put $1 billion someplace without any statutory requirement and could this fiscal note then go by itself without any bill to attach it to. MR. ALPER answered he has seen in the past the conditional language in budgets and fiscal note sections, or that this appropriation is contingent on the legislature passing a bill that is equivalent to "HB so and so." He envisioned that that is how it would end up being structured by whoever writes those fiscal notes into the final version of the operating budget. But, he continued, there is no explicit reference to the spending in HB 247, there is no reference to the actual appropriation in the bill language. REPRESENTATIVE SEATON remarked that it seems very problematic to start down the road of putting appropriations into a bill that does not include any statutory authority in the bill to do that. MR. ALPER responded that, broadly answering this question, the intent of HB 247 as originally proposed was to reduce the state's annual cash outlay to the neighborhood of $50-$100 million a year. That number in many ways lines up with the 15 percent in the language in statute that creates the [oil and gas] tax credit fund, so it would be sort of self-sustaining, and then this $1 billion was intended to be the transition, the money that would get the state over the hump between the old plan and the new. Version P is somewhat different, it is a different paradigm and may impact how this transition fund is treated or how it is kept in budgets moving forward. He said he does not have a complete answer. 1:53:33 PM MR. ALPER recommenced his presentation. Displaying slide 22, "Implementation Cost," he explained that employees of the Tax Division who work day to day with the tax credit program, with the production taxes, will to have to change their work somewhat. The [Tax Revenue Management System (TRMS)] and the [Revenue Online (ROL)] will have to be reprogrammed because there are different calculations, different formulas, online tax paying forms, and so forth. The department has not yet received a solid estimate [from the software developer] and an estimate may not come until it is better seen what the bill is going to look like. However, DOR has put a placeholder capital cost of $1.5 million into the fiscal note to pay the contractor to reprogram the system; no cost is anticipated for the department itself to administer the program because it will be done with existing resources and existing staff. There will also be a fairly robust regulatory process to implement the changes in this or any version of the bill. The Department of Revenue has a couple of other large oil and gas regulatory projects on the back burner waiting for the completion of this legislative session and DOR anticipates doing all of them at the same starting this summer. 1:54:44 PM The committee took a brief at-ease. 1:55:55 PM REPRESENTATIVE JOSEPHSON returned to slide 7 and noted that the last bullet states, "By preserving 'capital' and reducing 'loss' credits, increases payments to producers (who pay zero taxes)." He surmised this means it is status quo and that the producers are not getting more under Version P, but are getting what they got at least until the middle of 2017. MR. ALPER answered that the use of the word "increases" in this bullet is meaning an increase from the governor's original bill. It is actually a decrease from what is currently being paid because in some cases the producers in question are getting the 40 percent [well lease expenditure] credit in combination with the 20 percent [qualified capital expenditure] credit. [Under Version P] producers would, by the beginning of 2018, only be getting the 20 percent [qualified capital expenditure] credit. 1:56:52 PM REPRESENTATIVE SEATON noted that the governor's original proposal would implement a change date of the state's fiscal year, while Version P would implement a change date in January, which is a tax year for the companies. Regarding well lease expenditures, he inquired whether there is any reason why that cannot be implemented mid-year of a cycle, since those are different than the tax rate or the tax liability because the credits are based on when the money is expended and so would be independent of such things as the company's tax rate or operating loss. MR. ALPER confirmed that Representative Seaton is correct. For the credits that are tied to spending - the capital, well lease expenditure, and exploration credits - as long as the receipt, the activity, the spending takes place before the cutoff date, DOR can very easily parse out that set of expenditures and write a credit; the department does not need to be tied to a calendar year or a tax year. With the exploration credits being sunset on July 1, , companies will be coming to DOR with a project and DOR is only going to be paying them on the spending that took place prior to July 1. The credit that gets awkward if it is changed in the middle of the year is the operating loss because that is tied to an overall year's profit and loss, and so this would become a very difficult accounting exercise. 1:59:02 PM CO-CHAIR NAGEAK advised that the co-chairs are considering hearing some of the members' amendments to HB 247 tonight, depending upon how many amendments are received by the deadline of 5:00 p.m. tonight. He asked whether members have any comments on whether to start amendment consideration tonight versus waiting until tomorrow. REPRESENTATIVE TARR stated it would be difficult to respond to the amendments because members have not yet seen them and therefore it would be nice to have the evening to review them. CO-CHAIR NAGEAK agreed to wait until tomorrow to start the consideration of amendments. CO-CHAIR NAGEAK, responding to Representative Seaton, said the co-chairs would like to receive the proposed amendments in both electronic and hard copy formats. [HB 247 was held over.]