Legislature(2017 - 2018)BUTROVICH 205
04/14/2017 03:00 PM RESOURCES
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HB 111-OIL & GAS PRODUCTION TAX;PAYMENTS;CREDITS 3:01:14 PM CHAIR GIESSEL announced consideration of HB 111, sponsored by the House Resources Committee. (CSHB 111(FIN)(EFD FLD), 30- LS0450\L, was before the committee.) She welcomed Representative Tarr, Co-Chair House Resources Committee, and staff to introduce the bill. 3:01:36 PM REPRESENTATIVE TARR, Alaska State Legislature, Juneau, Alaska, explained that when SB 21 was passed, oil was $94/barrel, and lawmakers didn't spend much time looking at the low-price environment. Since then, the price has changed dramatically going down to $27/barrel. Not envisioning that low-price environment, they didn't consider a scenario in which some of the "Big Three" oil companies might have to operate at a loss. LISA WEISSLER, Chief of Staff to Representative Josephson, Alaska State Legislature, Juneau, Alaska, introduced herself and said she was available to comment on HB 111. REPRESENTATIVE TARR added that their position is that the existing system is broken and is too generous in a low-price environment, particularly with the cash credits that can build up over time. For example, right now the Department of Revenue (DOR) has about $600 million in applications for FY17; $100 million has been addressed, but that leaves about $500 million more. It has $200 million worth of applications on hand and anticipates $400 million more for FY18. So, at the end of FY18, the entire obligation will be $1.1 billion, and that obligation will have to be met. She explained that the FY18 obligations represent the calendar year 2016 environment. So, the state is catching up from what were the historic lows. She said the state currently has, in SB 21, a hybrid system of a gross tax at low prices and a net profit tax at high prices. 3:04:12 PM SENATOR VON IMHOF joined the committee. REPRESENTATIVE TARR said they worked with legislative consultant, Mr. Ruggerio, who suggested establishing goals for what they want to accomplish with the oil and gas tax regime. For Alaska, stability is one of the goals, as well as remaining competitive relative to other regimes. Minimizing downside risk for the state (like what happened in a low-price environment) was another. According to Mr. Ruggiero the current system is too complex and difficult to understand. It has a lot of moving parts, like the migrating credits in which taxes are calculated monthly, but then unused credits from one month can be applied to another month. Stacking provisions on top of one another have dramatic consequences in a low-price environment. He also talked about how Alaska is the only regime to offer cash credits, but if that was the only thing that mattered, then all investment dollars should have been coming to Alaska. But all investment dollars didn't come to Alaska, so other things need to be considered. REPRESENTATIVE TARR said Mr. Ruggiero related that it was good to have a net profit system, but too many things are now linked to the price per barrel. If one runs the math, it means at some point someone is a loser, because the cost of doing business will either go up or down. If things are too closely linked to the price per barrel, the value erodes either for the industry or for the state. 3:06:54 PM SENATOR WIELECHOWSKI joined the committee. REPRESENTATIVE TARR said Mr. Ruggiero's recommendation was to bracket off the production tax value (PTV), or the net profit, and that is what this bill does. She explained that the per- barrel credit equation has a lot of power, because the tax calculation is calculated first, and then the per-barrel credit is added on top of that. Alaska was in the minimum tax for quite some time. The cross-over from the minimum tax to the net profit system happens between $60 and $80/barrel. None of this will change with changes proposed from HB 111, version \L. Transportation, lease expenditures, capital and operating expenses are also allowable deductions. 3:09:27 PM HB 111, version \L, eliminates the per-barrel credit and reduces the base tax rate from 35 percent to 25 percent. Mr. Ruggerio reasoned if one truly has a net profit system, that means one will allow for transportation costs and lease expenditures and then work off the production tax value, because that represents profits. She said 25 percent was selected, because that was the original base tax rate in SB 21. The previous tax policy, PPT, had a 22.5 percent base tax rate. With that background in mind, Representative Tarr said, they started to focus on production tax value (PTV), and the final version of HB 111 went along with Mr. Ruggiero's recommendation to do a bracketed tax system, just like an income tax system, but bracketed off the PTV, ensuring that it remains a true net profit system (where transportation and lease expenditures are deducted). REPRESENTATIVE TARR said the bill specifics are: - reduces the base tax rate to 25 percent. This was chosen because the original version of Senate Bill 21 that passed in 2013 proposed a base rate of 25 percent. - eliminates the per barrel credit. The per barrel credit couldn't be eliminated without also reducing the base tax rate, because 35 percent would be too high. - retains the minimum tax feature: below $50 is the point of demarcation for where it becomes a net profits system. So, below $50 a 4 percent minimum tax is retained along with the existing step-down structure as the price drops down to 1 percent. - hardens the floor at 4 percent, so there would be a true minimum tax, because it was a surprise to the Department of Revenue (DOR) when some of the credits went below that floor, which is what happened in the very low-price environment. REPRESENTATIVE TARR reviewed that HB 111 has the minimum tax of 4 percent with a hard floor and at $50 goes to a 25-percent tax rate. 3:14:40 PM She referred members to an on-line document about the history of the tax credits, and said everyone agrees that the purchasable tax credits must be addressed. Why were they offered in first place? The state had always hoped incentives would bring new entrants and independents to the state while making sure that the major fields were still producing. The cashable credit feature was to attract the new entrants, because they are in the phase of spending a lot of money but getting no production. If those cash credits are eliminated, an alternative is needed that will still make Alaska an attractive place to invest. REPRESENTATIVE TARR related that Mr. Ruggiero, among other things, suggested allowing 100 percent of the carried-forward losses, which this bill does. That was in response to some of the new entrants and independents saying they would be significantly disadvantaged by only being able to use a percentage of the credit, because of all the years of spending before production, and the 100-percent, carried-forward loss is typical of what other regimes around the world do. To encourage getting into production as soon as possible, she said HB 111 allows a 10 percent reduction in the value of the carried-forward losses after seven years, specific to the year in which it was earned. For example, if a company earns in year one, but doesn't get to production in year seven, at year eight only 10 percent would be reduced from the year-one losses. If a company went to nine years, 10 percent would be reduced from the year-two losses. So, there is a full seven years to be able to accumulate losses and still be able to use them against production tax. Mr. Ruggiero said this keeps Alaska competitive, and it's in line with what other regimes offer. 3:18:30 PM REPRESENTATIVE TARR said this version of HB 111 adds a level of progressivity where the first $60 (which represents $100/barrel oil) of PTV is taxed at 25 percent. Then, just like an income tax, there is another bracket, but it's only the portion of PTV above the $60 that would be taxed at 40 percent. So, for $120/oil, the first $60 of PTV would be taxed at 25 percent and the next bracket of $20 would be taxed at 40 percent. The consultant recommended taking less on the low end and more on the high end to provide a balanced average over time. 3:20:22 PM REPRESENTATIVE TARR explained that the gross value reduction (GVR) provision repeals the extra 10 percent GVR for the higher royalty fields. If the carried-forward losses are allowed for seven years and then production begins, but it's GVR oil, in addition to being able to subtract the losses against any tax liability, there are the GVR reductions. This provision was scaled back in trying to keep some value to the reduction. The third-party assignment of credits is also repealed. She explained that one of the things that has become challenging is the current provision that allows companies to borrow against the certificate from the State of Alaska. Now that some of those certificates have not been paid, those companies, in turn, have not paid their bank loans, resulting in the bridge loans. The bridge loans won't go on forever, so the domino-effect lesson was learned, and the state is transitioning to carried-forward losses. 3:22:03 PM REPRESENTATIVE TARR said there is an interest in having some transparency about the state's investments, because if cash credits are eliminated and the incentive is in the form of carried-forward losses, the state is essentially still a co- investor in these projects, and those losses represent lost revenue. Earlier, HB 111 had three or four different provisions related to information, both for legislators and the public, but most of those have been removed, and public disclosure is limited to the lease expenditures. Mr. Ruggiero said other regimes around the world deliver significant data to the public that include lease expenditures, activity, production, etc., but the state is not doing something that is that involved. 3:23:40 PM REPRESENTATIVE TARR said the interest rates were changed in HB 111. Currently the statute allows six years for completion of audits, but that timeline is challenged by some changes in the tax system that require new regulations to be drafted and adopted, thus creating delay. The Department of Revenue (DOR) is just meeting the six-year deadline now, but their goal is to get ahead of the schedule. She added that HB 247, which passed in 2016, changed the interest provision to no interest after three years, but this bill changes that back to six years, to make the timelines match. 3:25:33 PM The ring-fencing provision allows losses to be linked to locations rather than to companies. This would segregate work done by one company if it is operating in two areas and one is much more profitable than the other, and the losses from one less profitable field wouldn't completely eat away the value from another more profitable area. 3:26:33 PM REPRESENTATIVE TARR said the revenue impact for FY18 is about $20 million in the current price environment, which some people think will continue for some five years. Backup for HB 111 looks at several different price scenarios and compares Alaska to other regimes around the world. Their foundational goal was to create something that is durable at all prices and at all time horizons. REPRESENTATIVES JUSTIN PARRISH and DELENA JOHNSON joined the meeting. 3:30:09 PM MS. WEISSLER continued the analysis and related that she was working off a sectional analysis from CS HB 111(FIN)(EFD FLD), 30-LS0450\L. Section 1 deletes a reference to the 10 percent gross value reduction (GVR), which is being repealed. (conforming amendment) Section 2 amends disclosure tax information in accordance with the new provisions that are going to allow both tax credit and lease expenditure information to be made public. (conforming amendment) 3:30:55 PM Section 3 is where the three-year limit on the interest rate gets changed. 3:31:02 PM Sections 4 & 5 allows the Department of Revenue (DOR) to make more information public. Section 5 adds a new subsection that lets the DOR to make otherwise publicly available information public. Currently, they are hampered by the confidentiality statutes they operate under. This relates to the taxpayer's information and tax credits. Section 6 changes the tax rate from 35 percent to 25 percent after January 1, 2018. Because of SB 138, the gas tax is going to change to a tax on the gross in 2022. So, throughout the bill a lot of sections deal with that, because oil and gas are taxed together until 2022, which is when gas gets its own system. 3:32:43 PM Section 7 establishes a 15 percent tax bracket that is triggered at a production tax value of $60. Section 8 hardens the minimum tax floor to ensure that new oil will still benefit from the GVR incentive. 3:33:24 PM Sections 9 - 14 are conforming amendments with the new tax rate. 3:33:40 PM Section 15 eliminates the North Slope carried-forward annual loss (net operating loss credit). Middle Earth will still have a net operating loss credit that will still be cashable. Sections 16 and 17 are conforming amendments for the hardening of the minimum floor. they relate to both net operating loss credits and the new oil $5-per barrel credit, which remains the same. 3:34:16 PM Section 18 relates to the exploration credits which apply only to Middle Earth. That is changed to match with the hardening of the minimum floor. 3:34:29 PM Section 19 relates to the information that will be required now and this is for both lease expenditures and credits. It's a description of the expenditure and the lease or property for which the expenditure was incurred. 3:34:48 PM Sections 20 that relates to different filers. The information related to the lease expenditures will be helpful in the new ring-fencing provision. Section 21 is language that is in all versions of the bill that would insure that the gross value at the point of production does not go below zero. The gross value at the point of production is a determinative factor in both royalty and our production tax. The concern is that there are projects where transportation costs could be so high that it could take that part of it to below zero. 3:35:39 PM Sections 22 - 25 are conforming amendments. 3:35:49 PM Sections 26 is significant in that this is where the 100 percent of net operating losses will be carried forward to production. In conjunction with section 27, this is where the percent carried-forward gets reduced by 10 percent after seven years. This is also where the ring-fence provision is added. 3:36:19 PM Section 28 is a conforming amendment. Section 29 contains repeals: the sliding-scale per-barrel credit, the assignment of the tax credits to the third-parties, and the 10 percent gross value reduction for higher royalty fields. Section 30 establishes a legislative work group to analyze Cook Inlet. 3:36:50 PM Section 31 relates to the minimum tax floor, the net operating loss credit, the repeal of the third-party assignments, and those provisions will apply on or after January 1, 2018. Section 32, the net loss carried-forward provisions, apply to lease expenditures incurred on or after January 1, 2018. Section 33 is a transition for the assignment of tax credit certificates so that the department may continue to apply and enforce these tax credit assignments to third parties for credits applied for before January 1, 2018. 3:37:35 PM Sections 34 is another transition provision for filing to clarify that everything kicks in after January 1, 2018. Section 35 is another transition that a taxpayer produces oil or gas before January 1, 2018 will still qualify for that extra 10 percent gross value reduction for the higher royalty fields. Section 36 will allow for retroactivity of regulations to carried out this act. That often becomes necessary because of the time it might take to get regulations in place. Section 37 will make the change to the delinquent interest of the three-year cap on the accrual of interest that is retroactive to January 1, 2017. It doesn't affect anything, but the DOR can explain how it helps them with their accounting. 3:38:35 PM Sections 38 - 40 are the effective dates that failed in the House, so members can see what they were. 3:38:57 PM CHAIR GIESSEL thanked her for the sectional analysis, and finding no questions, invited the commissioners of DNR and DOR to the table. 3:39:10 PM RANDALL HOFFBECK, Commissioner, Department of Revenue (DOR), Juneau, Alaska, supported HB 111. He said the Governor has consistently stated Alaska needs a broad fiscal plan where all parties share in the solution that balances the state's budget this year. The budget has been cut dramatically, as well as public services to the people of Alaska. In addition, the people of Alaska have given in the form of a reduced dividend. COMMISSIONER HOFFBECK said the Governor feels strongly that a broad-based tax on oil and oil and gas tax credit reform need to be completed next, but he was going to focus on the oil and gas tax. Last year, the Governor introduced HB 247 that included both tax credit reform and new revenues, and in particular, an adjustment to the minimum tax component in the state's severance tax. HB 247 was passed by the legislature, but focused more narrowly on Cook Inlet credits. COMMISSIONER HOFFBECK said that this year the Governor has clearly flagged that oil and gas tax credit reform is a priority and part of a balanced fiscal plan; however, leaving the specifics of how to achieve that goal to the legislature. Last year, the Governor had difficulty moving a large slate of tax bill, and learned that legislation moves through the legislature a little easier when it has a champion within the legislature versus trying to push it through. The House picked up the oil and gas tax bill this year and has moved it through the House. The Governor, in honoring his commitment that he would accept legislation that would achieve the goal of a balanced fiscal solution, even if it varied from how he might have done it, supported it. HB 111 is different than what he proposed in the past; however, much the same as with the Permanent Fund Protection Act, which was also very different than what he originally proposed, the Governor was supportive, because it achieved the goal. HB 111 is the only vehicle in front of them for dealing with the oil and gas piece of the fiscal plan, and the Governor stands with the House in bringing it to the Senate for further discussion and review. They see it as a critical component to the broader fiscal solution, and the Governor's commitment to the Senate is the same as it was with the House: to work them and provide the best information possible, and work to come to a solution that everybody can agree upon. 3:43:56 PM ANDY MACK, Commissioner* Department of Natural Resources (DNR)* Juneau, Alaska* said DNR has a historically distinct role in Alaska and one of those is ensuring that both the DNR and the DOR fulfill their statutory responsibilities. They conduct a rigorous process in order to maximize the benefit to Alaskan residents and focus primarily on the leasing process, the unitization process, and managing those agreements, which come in the form of contracts with the state and various owner interests, and the state has historically done a "tremendously strong job." At one point in the HB 111 process, DNR had a very distinct role, but that is no longer the case. The section requiring DNR to do some pre-approval was taken out of the bill, but he was happy to discuss the processes that the department goes through. COMMISSIONER MACK said the department fulfills some very important roles in Alaska. One of those is in managing the state's lease interests and units, they consider a whole range of issues. They tend to stay away from any particular topic, for instance, tax, but look at the best way to manage those agreements to get to the maximum production for Alaska. Occasionally, they are asked to look at issues like royalty modification, for instance. In those cases, they put a range of issues on the table. If an applicant wants DNR to consider how to ensure that a particular unit can be placed in production, or if there is a unit under certain circumstances that is in production that might fall out of production, then they can consider a whole range of options. They stand ready to answer questions about that process. He wanted to be clear that DNR is driven by the constitution and by leases and unit agreements. 3:46:58 PM CHAIR GIESSEL said for the past 10 years the DNR and DOR commissioners have articulated goals of attracting investment, spurring competition, and getting more oil in the pipeline. Is that the same goal structure that he and the governor are working under? COMMISSIONER HOFFBECK answered yes. The goal for DOR is to have production and revenue from that production. Production just for the sake of production is not beneficial to the state. The state needs revenue to run on; it has many obligations to the people of Alaska. He said the Governor has been very clear that the oil industry - at all levels - is part of the fiscal solution. COMMISSIONER MACK answered yes; it is the policy of the DNR to constantly update and ensure that the leasing process is attractive, that the terms lay out a framework for folks that want to bid in that process, that once they have successfully secured the leases, which is an exclusive right to go in and develop the resource, that it effectively manages. Through the unit management process, DNR frequently deals with requests to expand units; in some cases, those expansion efforts are tied to work commitments. In certain situations, companies are also consolidating their efforts and the department works on that issue. In recent years, folks - Oooguruk, Nikaitchuq, and Nuna - have come to the state asking for royalty relief to bring projects on line. The state evaluated a number of factors and determined it was in its interest to modify royalty rates so that those projects could come on line. The process is rigorous and takes quite a bit of time. CHAIR GIESSEL said royalty is a gross tax, and at low oil prices, it takes a significant amount of the profit. She asked how he saw this bill helping with getting more production through TAPs and, therefore, more revenue for the state. COMMISSIONER HOFFBECK answered the answer is multi-faceted. The simple answer that gets thrown out there -increase taxes - doesn't increase production. The state has an unstable tax system right now. It's been modified multiple times over a period of time and is under continuous assault now, and there is no consensus within the community that it is the right tax structure. They are hoping to land on something where everybody "can put their swords down for a few years and just let it play out." But work must be done to get there. Another part of the answer is the billion-dollar appropriation to pay off the existing credits, probably the most significant thing they can do to get capital back into the fields and working again, but the Governor can't do that until the state has a stable fiscal environment. Part of that is to bring the oil and gas tax credit component in line so the state isn't continuing to build additional credit liability that it doesn't have the capacity to pay. He said, "I think stability and getting credits paid off will be a huge plus if we can move this bill as part of the fiscal package through the legislature to conclusion this year." 3:53:19 PM COMMISSIONER MACK added that royalty has been described many ways; as the owner's share of the resource in some cases. What the department has been doing recently is understanding how the state can capitalize on fundamental statehood agreements like access to areas which have previously been unavailable, like ANWR, NPRA, and OCS. They also continue to perfect the state's leasing system of areawide leasing, a very effective system for making sure that the maximum number of acres are available every year. CHAIR GIESSEL asked if he would agree that in the last two years production has increased on the North Slope. COMMISSIONER MACK answered that the actuals the year ending June 30, 2016 showed a 1-2 percent increase, and it looks like FY17 will be the same. CHAIR GIESSEL remarked the past couple of years have been pretty successful. 3:55:11 PM COMMISSIONER MACK responded that Alaskans should be very encouraged with those numbers, but also be mindful of the future. CHAIR GIESSEL said in terms of the goal of more oil through TAPS, that can be checked off. She asked how he would characterize the concept of the entrants into the North Slope and new finds over the last two years. COMMISSIONER MACK replied that without the unit data in front of him, he would just focus his answer on the North Slope. The news is positive with respect to the Prudhoe Bay Unit and satellite fields. One transaction resulted in Hilcorp taking over a handful of units on the North Slope. Kuparuk has some good news, and Nikaitchuq and Oooguruk have qualified for royalty relief; Nuna is not in production, yet. Those two fields are doing "reasonably well," but are not huge producers and have royalty reduction. A series of new announcements have come from the western side of the state-owned land: area that includes the SMU Unit, the Placer Unit, the Pikka Unit, west of the Colville River Unit, and the Greater Moose's Tooth Unit. Those units straddle both state and federal lands, and it's difficult to put together large permitting packages. In the case of the Pikka Unit, for instance, which is being driven by the Nanushuk Development, they must get a permit from the lead agency, the U.S. Corps of Engineers, along with other federal and state agencies. There is reason to be hopeful about the NPRA, tempering that with the need to get permits and safely develop those fields. CHAIR GIESSEL thanked him saying he made his points very well: any production takes years before it's realized. 4:01:14 PM SENATOR VON IMHOF asked the long-term price of oil in the recent spring forecast that was presented to the Finance Committee. COMMISSIONER HOFFBECK replied in the range of $70-75. The private nominal price is $54 for FY18 and $60 for FY19, and then growing up into the $80 and $90s. SENATOR VON IMHOF said with that in mind, they have identified a price, and considering that Alaska has some of the highest production costs in the world, she asked if they wouldn't want to create a suite of tax structures that incorporated those variables that are unique to Alaska as well as unique to this ongoing environment that is expected in the future. Her concern is that Commissioner Hoffbeck said he wanted to increase production but also increase the government's take on that production, and when the state already has a challenging environment and an extraordinarily long time to begin a project, they should want to create a ladder structure of fields coming on each couple years or so. "To do that we have to be competitive at all times globally," she said. So, Alaska must look at its environment and at what other regimes are doing so it can position itself. She is worried that he is being very hopeful for Alaska's unique situation. COMMISSIONER HOFFBECK explained that what he meant when he said the state needs more, is that production without revenue is not necessarily its goal. The state should receive revenue from the oil and gas production on the North Slope. It is a structural issue with our tax system, being a net tax, at least within the Unite States. When oil prices fell, Alaska lost 90 percent of its revenue. The next closest state lost 30 percent of its revenue. Most of the states were in the 6-7 percent range. SENATOR VON IMHOF asked what aspect of the net tax makes the largest impact to the state's flawed tax structure. COMMISSIONER HOFFBECK replied that multiple components within a net tax structure allow for large deductions against the sale price of the oil before calculating the tax, and the per-barrel credit is a substantial reduction in the value of the oil at low oil prices. Part of it is just the inherent fact that it's a net tax. In looking at what is a proper tax structure, rather than looking at how we compete with ourselves might not be the right question. The ultimate comparison goes more to Senator von Imhof's question: how does Alaska compete with other jurisdictions. 4:07:21 PM SENATOR WIELECHOWSKI said experts have told them over the years that the analysis is exactly the opposite of what he just said. Spencer Hosie, a former oil and gas attorney for the state for many years, said not to look at how we compete with other jurisdictions around the world. That when the oil companies sign a lease in the state of Alaska they have an obligation to produce when they can make a reasonable profit. One doesn't look at what a company can make in Texas or North Dakota. He asked the commissioner if he is saying now we shouldn't be looking at what the leases require them to do, which is to produce when they can make a reasonable profit? Furthermore, it's not following the law. 4:08:36 PM COMMISSIONER HOFFBECK replied that is not what he said. He said his concern was that people are asking if our current tax structure is this better or worse than our current tax structure. If the conclusion is that this is going to result in a great tax burden, and that somehow makes it a non-competitive tax structure, that is not the right comparison. The question is: does that tax change make us non-competitive at being able to compete for the investment dollars here in Alaska. 4:09:35 PM SENATOR WIELECHOWSKI asked him how they were going to move forward on this issue, because he had never seen an oil tax bill done in this fashion. He thought Representatives Tarr and Josephson had done an outstanding job, but it's highly unusual for a governor to not put forward a tax overhaul. The reason it's important for the governor and the executive to take a strong position is because he has the expertise and information that the legislature doesn't have access to. SENATOR WIELECHOWSKI said he also had never seen an executive not hiring consultants. So, he wants to know if this is going to harm the industry, and wanted the executive to take a position. Their obligation is to get the maximum benefit for the resource. 4:11:45 PM COMMISSIONER HOFFBECK said the administration and DOR had been actively engaged in analyzing and bringing forward information and presenting to the extent on the House side that he was accused of it being his bill. "The Governor stands by this bill," recognizing it has another body to get through. SENATOR STEDMAN commented on the magnitude of the reduction in the value of the oil to Alaska's treasury relative to other states, because Alaska is the only state that owns the oil. But, probably, everybody, including the property owners in states with private royalty systems, got pounded pretty hard. This morning they had an update on the state's revenue for 2017/18, and it was good news. He asked the administration to run the current structure and the proposed structure in HB 111, because he thought they would find FY17 is in the minimum tax environment, but will drop into a different calculation going forward with this bill, and possibly out of that minimum tax. That impact should be measured. It looks like a production tax value (profit oil) of just over $1 billion in 2017 changed to $2.4 billion. In other words, he said, miner movements make huge dollar differences in revenue. He explained that it is challenging for policy makers because all their data is consolidated monthly from multiple companies. He noted the importance of not falling into the trap of "single barrel examples." The calculations impact millions of barrels. CHAIR GIESSEL thanked him, adding that she agreed with what Senator Wielechowski said about the administration having a consultant in the past. It is very unusual that internal modeling is being used versus having a consultant. She invited the director of the Division of Oil and Gas forward and asked her to broadly paint a picture of what exists on the North Slope: the potential and if Alaska had experienced peak oil. 4:19:25 PM CHANTAL WALSH, Director, Division of Oil and Gas, Department of Natural Resources (DNR), Anchorage, Alaska, answered that looking at the past 30 years, it is safe to say the Prudhoe Bay reached its peak oil production a couple of years back, but this second year of production increase on the North Slope is very exciting. However, it is hard to think that enough production would come on to get the state over 1 million barrels a day. CHAIR GIESSEL stated that 1 million barrels a day "is not a standard that any of us have articulated aiming for." She is basically looking at more production through TAPS, because the less flow the pipeline has the more challenging it is for the flow to continue. 4:21:26 PM CHAIR GIESSEL said Armstrong and Repsol, partners in the Pikka Unit, have discovered a new stratum in the geology located in the west end of the North Slope, and asked her to elaborate on it. Have other discoveries happened there? MS. WALSH replied that the Pikka discovery is in the Nanushuk formation, and they were not the first to find hydrocarbons in that interval, but the first to find enough hydrocarbons to develop. It's a shallower horizon in much younger rocks. It was being looked for prior to this find. In large part, it is what was added to the ConocoPhillips announcement in the Greater Moose's Tooth area. CHAIR GIESSEL asked her to describe how far apart Pikka is from the ConocoPhillips discovery. MS. WALSH guessed it's about 30 miles to the west. SENATOR GIESSEL said in other words, this is potentially a "rather big strata." MS. WALSH responded that they are thought to be separate units and not connected from a geologic standpoint. The rock layer that keeps the formation intact is different in area than the other. CHAIR GIESSEL asked her what the expected production is from both the Armstrong and the ConocoPhillips discoveries. MS. WALSH answered Armstrong estimated 120,000 barrels a day and ConocoPhillips has estimated that same, as well. CHAIR GIESSEL asked her to describe the API, the grade of oil for both units. MS. WALSH replied the Pikka Unit is light oil (normal gas/oil ratios), and moving west the source rocks make it more challenging to bring the higher GOR oils into facilities, because of gas and water constraints. CHAIR GIESSEL asked if the light oils in the two discoveries might be beneficial to other companies that might be interested in starting to develop the heavier oil deposits using the lighter oil to dilute them for easier transport through the pipeline. MS. WALSH replied that a lighter oil will make it easier to transport heavy oils, particularly with the ability to mix them. The challenge for heavy oil is the price environment ($50/barrel range), because technology doesn't exist that allows it to be produced economically. 4:26:22 PM CHAIR GIESSEL asked if any other plays are connected to these two discoveries (in the Nanushuk formation). MS. WALSH answered that Armstrong/Repsol just drilled the Horseshoe Well 20 miles south of their play, and believe the two are connected. CHAIR GIESSEL remarked that is great news. SENATOR WIELECHOWSKI asked if there had been any economic analysis for the bill and compared to the existing regime, because that is the key in this whole debate. MS. WALSH replied that is a Department of Revenue question since it is more focused on royalties. SENATOR MEYER asked her thoughts on Smith Bay. MS. WALSH replied that the Smith Bay field is very exciting. It's also part of the Nanushuk formation, but a different interval. It's more inlaid with shales and has less clean sands, and it is in the very early years of exploration. The department hasn't seen production tests, yet. 4:29:15 PM SENATOR MEYER asked if the oil at Prudhoe Bay has a gravity of 35. MS. WALSH answered yes. SENATOR MEYER asked if the Willow and Pikka fields are like the flow at the Sadlerochit Formation in Prudhoe Bay. MS. WALSH replied that the Willow and Pikka fields have lighter oil than the Sadlerochit reservoir. CHAIR GIESSEL asked if her division handles the seismic information. MS. WALSH answered yes, along with the Department of Geological and Geophysical Surveys (DGGS). CHAIR GIESSEL said the state has a wealth of seismic information that is reaching its age to be disclosed, and she heard the department was considering determining its value and perhaps putting a user fee on it. How is that progressing? MS. WALSH replied that it has progressed, and the idea is not to put a price tag on the seismic, itself, but to put a price tag on what it costs the department to process the data to make it available publically. It takes quite a bit of staff interactions and following stringent regulations about what pieces of seismic data can be public. 4:31:47 PM KEN ALPER, Director, Tax Division, Department of Revenue (DOR), Juneau, Alaska, said he would take the lead on presenting the analysis of CSHB 111(FIN)(EFD FLD) on Oil and Gas Production Tax and Credits. He mentioned that he also included some history slides that everyone had seen before. CHAIR GIESSEL asked if this list captures the governor's concerns and if the governor views these elements as "must haves." MR. ALPER answered no, but his name is on one of the upcoming slides. He said the governor has spoken about several specific concerns that he hopes are addressed in whatever oil and gas legislation passes, and HB 111 meets those concerns, but it doesn't necessarily meet them in the only way possible. One of was his goals is getting Alaska out of the business of cash credits: accepting the reality that we no longer have the revenues, the cash flows, the financial standing to be able to participate with upfront cash towards these projects. The second goal is a little subtler, but it's about reducing the state's liability towards potential large future projects, because now that the state is out of credits and is accepting a paradigm that for all intents and purposes, costs are going to be carried forward and be used in the future. So, Alaska needs to get its head around what they are worth and how that relates to the taxes future producers are hoped to be paying once they bring that oil and gas into production. A third goal is to defer the state's participation until something comes into production. It's not just about not paying cash; it means making sure that whatever value created is not transferable to other fields. It should have to be used to offset the new value from the new production these programs are trying to incentivize and not to write down profits from legacy oil. And finally, just the general statement that the oil industry should be part of the broader solution, as Commissioner Hoffbeck alluded to in his opening remarks. CHAIR GIESSEL asked if industry had not been participating. MR. ALPER replied industry has been the largest participant in Alaska's budget over time, but if the state accepts that it is at the starting point of having a balanced and stable budget, several different things need to move a little bit between here and there. MR. ALPER stated that CSHB 111(FIN)(EFD FLD) eliminates the idea of the carried-forward, annual-loss credit (NOL), specifically for the North Slope, effective next January. That part is carved out of the oil credits statute and is replaced with the idea of the carried-forward lease expenditures. SB 21, passed in 2013, eliminated capital credits on the North Slope. For the most part, the small producer credit is being phased out. The main credit of value on the North Slope today is this NOL credit, and that is what is being eliminated in CSHB 111(FIN)(EFD FLD) and turned into carried-forwards. 4:37:15 PM MR. ALPER used slide 6 to explain the history of tax credits. The state has participated in tax credits to the tune of $8 billion through the end of the prior fiscal year. Of that $8 billion, about $4.5 billion is through offsets, subtractions from tax, and about $3.5 billion is in actual cash, appropriated money where the state wrote checks or electronic transfers to industry to compensate them for some desired behaviors (terms under one of the state's tax credit programs). The North Slope has $4.4 billion in tax offsets. During the earlier years of credits when the tax system known as ACES [Alaska's Clear and Equitable Share], the primary credit offsetting taxes was the 20 percent qualified capital expenditure credit, which was repealed in 2014 and replaced with the per-taxable barrel credit. That is the primary tax offsetting credit that has added up over a 10- year period to $4.4 billion. Meanwhile, the cash credit side on the North Slope has added up to about $2.3 billion. That is actual cash out the door and doesn't reflect the pending obligation that the state is holding now. 4:38:41 PM For the non-North Slope, which includes the Cook Inlet and the area known as Middle Earth, transactions are few and small in comparison, and it is very hard to report them without violating taxpayer confidentiality. Consequently, they get lumped in with Cook Inlet and get referred to as "non-North Slope." Very little credits are used against tax liability in this area, because there is very little tax liability. It has statutory tax caps at 17 cents per 1,000 cubic feet, and until this year the oil tax was effectively zero (less than $100 million). The tax caps resulted in another $500 million to $800 million in tax savings. MR. ALPER said Cook Inlet has had a lot of cash tax credits because of legislation passed that increased them in 2010, and the state put $1.2 billion into cash credits there. In doing so, it has hopefully resolved the supply shortages that were a major issue in that part of the state for several years. 4:40:35 PM CHAIR GIESSEL noted that the Native Corporations of Doyon and Ahtna are working in Middle Earth, and asked if they would pay a production tax. MR. ALPER answered that there is no current production in Middle Earth, and yes, the production tax is in addition to the underlying tax in SB 21. A maximum tax statute is in place for Middle Earth that is in some ways comparable to the maximum tax in place for Cook Inlet. It was passed as part of the Frontier Basin bill of 2012, and it works out to be 4 percent gross tax for the first seven years of production. That will phase out in 2027. If someone brought some resource into production, it would have a very low tax. CHAIR GIESSEL asked if Native Corporations pay a corporate income tax. MR. ALPER replied that they are for-profit corporations and not tax exempt. They are, for the most part, C corporation, because they have more than 100 shareholders. The department's annual corporate tax reports parse them out as a segment. 4:42:09 PM Of the $2.3 billion of North Slope credits, about $1.5 billion went to projects that are now in production. Going a little further, Mr. Alper said, the number of barrels are a little bit more every year and bring in about $24/barrel. Another $800 million has gone to 11 projects that do not yet have any production, Mr. Alper said. Some of them have been abandoned and some of them will continue to progress and hopefully will put oil in the pipeline. So, about two-thirds of the North Slope money has gone towards actual production. In Cook Inlet, about three-quarters of the money has gone to eight projects that now have production and a quarter (about $300 million) has gone to projects that do not yet have any production. However, some projects are just getting started and have a relatively minute amount of production to which some credits may have been applied. But over time, that production will dilute the credit obligation, and the state's per-barrel investment will decline. CHAIR GIESSEL noted that he has access to confidential data and asked if a legislator could sign a confidentiality agreement and see that data. MR. ALPER answered no. The Internal Revenue Service (IRS) restricts the department's ability to share this information. It has an extra locked door and rules over how the file cabinets are locked, for instance. A provision in HB 247 that passed last year calls for a report of how much tax credits were received by company per calendar year, and the first report will be released this month. 4:44:38 PM MR. ALPER said slide 8 shows why there is a strong need for the state to get out of the cash business. Conceptually, the department was expecting a large amount of revenue from this industry and thought 10-15 percent of it should be reinvested into the oil of tomorrow. However, once the revenue disappeared and costs stayed the same, that idea needed to be revisited. 4:46:38 PM Slide 8 showed what production tax looks like with each year being represented by three bars: the first one is what the production tax would have been without any credits, the middle one reflects the actual revenue received by the state, and the third bar subtracts the cash credits that were appropriated by the legislature and paid out by the Tax Division in a fiscal year. The high point was in FY08 when the state had over $7 billion in statutory revenue and nearly $7 billion in actual revenue received, and maybe $200 million was spent on cash credits. Revenue from the production tax ranged in the $2-6 billion range for seven or eight years until 2014 when the price collapsed. Now the state's credit obligations are very close to if not actually exceeding the revenue received from the production tax (not considering other revenue sources from the oil and gas industry, which analysis is on slide 9). Slide 9 looks at the same data set with the state's royalty, corporate income tax, and property tax layered on top. Although it's not quite as extreme looking, the impact is similar. Companies received upwards of $9 billion in five or more of the high years now to where it is in the $1-1.5 billion range. That makes a multi-million credit program no longer affordable. 4:47:10 PM CHAIR GIESSEL asked him to pause on slide 9 at 2017-2026 and asked if the credits are from the potential of the refinery, gas storage, and LNG credits. MR. ALPER replied this represents the status quo and doesn't incorporate any changes made by this legislation. So, the largest component of their ongoing credit obligation are operating loss credits earned on the North Slope. SENATOR WIELECHOWSKI asked what the blue line represents. 4:48:20 PM MR. ALPER replied that it represents the idea of non-cashable credits. The statute limits the availability of cash to companies who produce less than 50,000 barrels a day. So, the major producers and more recently Hilcorp who have publicly spoken to going over that threshold are not eligible for credits. Should those companies earn credits, they would have to hold them and carry them to a future year and use them to offset their own tax liability. It is a number that goes to zero immediately. Earlier versions of this analysis based on the spring 2016 forecast had a much lower oil price and they started seeing some large carried-forward NOL balances from the major producers, and that is why that data set was added to this chart. SENATOR WIELECHOWSKI asked if the NOLs had been zeroed out. MR. ALPER answered that the best data point to talk to is the expected price of oil for FY17. The fall forecast was $50/barrel (it was $47). Last spring's forecast was $39. The difference between that $39 and $47 is very material when the breakeven price for the average producer on the North Slope is around $43- 44/barrel. So, where the department was previously contemplating everyone losing hundreds of millions of dollars, now it sees a slightly better than break-even environment, so all the carry- forwards fell out of the analysis when the fall forecast was redone. 4:49:58 PM He next addressed the state's unpaid credits and said historically the statutory language was open-ended: the amount presented for repurchase is appropriated to the Tax Credit Fund. Money would be moved as needed, and there was plenty of it then. The totals would be counted at the end of the year and be reported in the Revenue Sources Book from year to year. What happened in 2016 is that at the end of the 2015 session, the Governor through his veto capped the appropriation at $500 million. That number turned out to be just about right; only $498.5 million was needed. So FY16 was for all intents and purposes "no harm, no foul." Of that number, about 60 percent ($287 million of $498 million) was paid out in Cook Inlet and Middle Earth outside the North Slope area. He said that the $1 billion appropriation that Commissioner Hoffbeck alluded to that was attached to HB 247 last year did not survive. The Senate and the House put $460 million into the budget. Of that, the Governor vetoed $430 million. Even had the $460 million passed, that would have been inadequate for the expected volume of credit obligation for FY17. MR. ALPER said that regulations cover what happens in the event of a cash shortfall: a first/in-first/out formula is used and the $30 million was paid out primarily to some older Cook Inlet capital credits. That will be documented in the report to be issued later this month. The FY18 budget has $74 million, and based on the formula change to the spring forecast update and slightly higher oil prices, that $74 million is going to be adjusted to $76 million. The formula is basically 15 percent of what the production tax calculation is before any credits are used to offset liability (AS 43.55.028(b)(c)). 4:52:23 PM So, with the $30 million limitation, a little over $600 million has been issued since the beginning of the current fiscal year. Of that, $100 million can be taken off the table one way or the other. Some of the credits have been paid; some have been transferred to a taxpayer who could use them against their own tax liability, and some of them are ineligible for repurchase, probably related to the size of the company. Now $500 million is awaiting repurchase. January 1, 2017, is an important date, because certain changes happened as part of HB 247: certain regulatory sequencing, a priority to hire Alaska hire, and other provisions. That does not apply to this $500 million. It will be paid first, and the rest will be paid pro-rata. So, should the legislature at the end of this day appropriate $76 million, roughly everyone who holds a credit certificate will get paid 15 percent of their obligation. Then the next $500 million, however many years that takes, will go this $500 million of calendar year 2016 certificates. Once they are completed, they will go to the 2017 certificates; those will be further ranked by this new filter of resident hire percentage. Should the legislature appropriate $400 million, everyone gets 80 cents on the dollar. 4:54:12 PM In hand, the Tax Division has $200 million in credits, the bulk of which are exploration credits (025. credits). These require a full audit and those will go out this year. A bunch of exploration credits came in late, because they sunset last July 1 (2016), and some companies may have "frontloaded" their work to take advantage of that credit. At the peak, being able to use the exploration credit in concert with the carried-forward annual loss credit, the state could have been on the hook for up to 85 percent of the ongoing expenses of an exploration project on the North Slope, specifically in the year 2015. The new work flow, which hasn't been aggregated yet, is primarily operating loss credits that came in with the 2016 production tax returns that were due on March 31. Those are expected to total $400 million. The whole suite of obligations totals $1.1 billion, minus whatever is appropriated this year. MR. ALPER stated that is why the state must get out of the cash credit business. 4:56:49 PM Issue number two is reducing the state's liability related to potential large future investments, or what the carry-forwards are worth. He explained that the House reduced the base rate from 35 percent to 25 percent, and that had certain tax implications at different price ranges. It also changes the way companies get to use their carry-forwards when they use them against a future tax. Currently, those carry-forward credits are worth 35 cents on the dollar to reduce taxes. The way HB 111 is written they would be worth 25 cents on the dollar, a reduction of 28 percent of their value to the company. It aligns the operating loss credit rate with the effective tax rate being paid by the company, so the state is not paying more on a loss than it is receiving on a profit at the other end. This is illustrated on slide 13, but it is distorted, reason being the per-barrel credit, an unintended consequence of the addition of the per-barrel credit that was done for certain policy reasons not so much related to revenue during the time of the SB 21 debates four years ago. MR. ALPER stated that Mr. Ruggiero started the conversation over how to align the loss rate with the effective tax rate and the House Finance Committee eventually adopted his idea of getting rid of the credits and simply going with a net tax rate that steps up over time. Their current iteration has a single bracket, but it does some "neat things" regarding effective tax rates that he would show later. CHAIR GIESSEL asked if the per-barrel calculation is a credit or part of the tax system. MR. ALPER replied for accounting purposes it is considered a credit, but in many ways, it is not a credit. It is a foundational part of Alaska's tax system. He added that the intent was not to tax anyone at 35 percent, but to have a sliding-scale, variable-rate tax that went up and down with the price of oil. But, because of the way the mechanical tax calculation works, a carried-forward expenditure is subtracted from the profit, and the benefit of that subtraction is calculated at the 35 percent rate. That is the disparity. Although the tax rate is lower in effect, the tax calculation is actually 35 percent, and it causes some unusual calculations. 4:59:59 PM SENATOR MEYER said he remembered when the sliding scale (the new progressivity) was put in and it was always confusing to him, because as the price of oil goes down the scale goes closer to the 25 percent base rate and as the price of oil goes up, it slides back up closer to 35 percent. He asked if that was correct. MR. ALPER responded that was absolutely correct and explained that SB 21 had three phases: the original bill had a 25 percent flat tax. The idea of a $5 subtractive credit, which provided progressivity at a higher rate at higher prices and lower at lower prices was added in the Senate. The sliding scale of .038 percent was added in the House Resources Committee. SENATOR MEYER referring to page 6 asked if the $8 billion in credits on the North Slope is an accurate number. MR. ALPER answered no; the number the department elects to use is $3.5 billion (on slide 7). That is the true cash obligation that impacts the state's budget. The other $4.5 billion is part of the foundational tax calculation; they didn't really expect to get that revenue before the subtraction. It's certain mechanical things that happen because of the way it's calculated that leads to these "unusual over-valuing of losses." 5:00:57 PM MR. ALPER continued to slide 14 that provides an example of a historic tax regime, ACES, and compares it to SB 21 for two different variables. The solid blue line reflects the effective tax rate under ACES at different price points. It was a 25 percent tax with a progressive element at higher prices and a capital credit that is subtracted and is based on certain assumptions of capital spending. It was a very steep tax that got very high at higher prices and it went down towards zero at low prices. The dotted blue line represents the 25 percent NOL credit rate that was part of the law during the ACES era. A company that was losing money and getting a benefit from the state for that loss was receiving it at the 25 percent rate. So, for the most part, if the price of oil was over $90/barrel, the tax rate exceeded the credit rate. If the price of oil was below $90/barrel, the tax rate was lower than the credit rate. SB 21, the red line, starts at a 35 percent tax that is stair- stepped down reflecting the phasing in of each $1 increment in the per-barrel credit until it gets down to around $70-75/barrel where it goes steeply up again. That is where it intersects with the minimum tax. SB 21 has a much harder floor than ACES did, so it has low-end protection. That is why the SB 21 revenue line is higher than the ACES line at lower prices, but what isn't illustrative about this slide is the 35 percent NOL credit rate that at all price points is higher than the tax rate. That is the distortion this bill attempts to resolve. This is separate and distinct from any conversation about tax increases resulting in more revenue. SENATOR WIELECHOWSKI asked him for a rough number on how much additional revenue the state gets for every effective rate percentage point increase. MR. ALPER replied that is impossible to say, because it's extremely variable with price. Obviously, 1 percent at $100 oil is very different than 1 percent at $50 oil. SENATOR WIELECHOWSKI asked him to use the current revenue forecast for a year, if they were to raise the effective tax rate 1 percentage point. MR. ALPER answered that earlier analyses of a prior version of the bill that had a minimum tax increase was a 1 percent gross rate going from a 4 to a 5 percent, and that was in the neighborhood of $50-60 million. CHAIR GIESSEL noted that Mr. Alper's modeling stopped at $50 and asked why he didn't go further down. MR. ALPER replied that he didn't create this table and didn't specifically ask for a cutoff. So, he couldn't say, but he could say that the minimum tax as prices get to the break-even point and beyond, reaches more than 100 percent. That's the nature of: if companies are losing money and the state is collecting a gross tax, that becomes a very regressive tax that goes to infinity. In the interests of fitting it on the graph, perhaps, is why it was cut off at $50. It was an executive decision made by the economist who put the graph together. CHAIR GIESSEL commented that they modeled SB 21 much lower, and that line that goes upward continued to go upward well past the SB 21 dotted NOL line. 5:05:17 PM MR. ALPER said the third issue being raised in HB 111 is deferring the participation to the new project. This is a controversial topic and it can be resolved in several ways, but this bill contains a ring fence, which means a carried-forward loss gets attached to a specific lease or property. The department would administer it by the unit, that says until that unit has value to be offset, those carry forwards can't be used. This protects the state's interest from the failure case of a project where someone has spent a lot of money but didn't get very close to production, and they could sell their company, and then those carried-forward losses would migrate to the buyer. If that buyer was a North Slope major producer who might own a share of Prudhoe Bay and/or Kuparuk, they could use these losses to offset taxes from the legacy production. That is not the intent of the program, so the purpose of these sections is to make sure that the state doesn't lose taxes until the fields come into production from which the investment was originally made. CHAIR GIESSEL asked if that is happening now. MR. ALPER answered yes, and the idea of a field-based tax is very typical everywhere else in the world. Alaska's tax is a co- mingled North Slope segment; all the North Slope producers file taxes together. So, there isn't an issue of carried-forward losses, because they are still in the credit paradigm. He said the ring fence is structured to be limited to carried- forward losses. In other words, if a company like ConocoPhillips that has incumbent production but a major new project on which they are spending a lot of money, that spending so long as its offsetting their profit on the North Slope continues to be a single entity for tax purposes. There is no delay in their ability to use that spending. If someone has a loss, because they don't have production or a low-price year as in the ConocoPhillips case, the amount of the loss is the only thing that would be bound by the ring fence. It is limited to carried- forward lease expenditures that can't be used in the current year. SENATOR VON IMHOF asked if this provision applies to other industries that have multiple locations in Alaska, as well, like restaurants and retail stores. 5:08:27 PM MR. ALPER replied no; Alaska's oil and gas production tax is unique, and he couldn't find a good analogue for it elsewhere in the tax system. SENATOR VON IMHOF asked what the incentive would be for an existing producer to buy a struggling project, if it's ring fenced. MR. ALPER answered, if a company believes it could bring it into production, because of the presence of a resource. The danger is if it's a failed project where the owner doesn't think it can come into production, but they are holding $1 billion of carry forwards that cost the state $250 million in offset taxes from legacy production. That is what the ring fence is trying to protect against. SENATOR VON IMHOF said she thought his thinking had flaws, but would need to reflect on the subject for a while. MR. ALPER said he looked forward to working with all the committee members as this bill works its way through the process. SENATOR WIELECHOWSKI recalled a lot of discussion about ring fencing under ACES, and the reason they didn't adopt ring fencing was to encourage major producers to go out and invest in other much more expensive fields and get a large write off. He asked if ring fencing is used in other parts of the world, and why. MR. ALPER replied that it's not so much ring fencing as project- specific taxes: a concession or some sort of production sharing agreement to bring a specific project into development. It will have its own investment and tax structure; it just doesn't blend into the next field over. Alaska was like that under the economic limit factor (ELF), a tax rate that varied from field to field. The idea of having the North Slope be a single blended tax unit is recent since the passage of PPT in 2006. 5:11:24 PM MR. ALPER said the specific provisions of HB 111 are straight forward. Previous versions changed the minimum tax, but the current version keeps the existing 4 percent floor, but many do not know it is actually a sliding-scale floor. If the price of oil should go below $25/barrel, it would go to 3 percent and below $20, it would go to 2 percent, below $17.50 to 1 percent, and should the price of oil be below $15, the minimum tax would go away completely. These kinds of numbers which are tied to fixed dollars tend to erode in value over time, as inflation gets in the way. This law was passed in 2006 and $25 oil then is very different than it is now. Interestingly enough, the graph that showed the SB 21 curve where the minimum tax goes as high as $75/barrel, but in the bill before them the minimum tax would only be relevant below about $50/barrel. The net tax would be in place at $50 and above. Even though the gross tax isn't changing, the net changes around it are moving the curves around. MR. ALPER said the other issue is one of hardening or making the floor not able to be penetrated using various credits. Under current law, the only credit that is hardened to the floor is the per-barrel credit (024(j)), which is being eliminated in this bill. HB 111 prevents most credits from being used below the floor; it is very much of a hard floor bill except for the small producer credit, which can be used to go below the floor. Then there is something of a hybrid calculation that's invented in one section that hasn't been seen before that allows the GVR subtraction, the 20 percent reduction to be applied to the gross before the minimum tax calculation. That amounts to a 3.2 percent hard floor (80 percent of 4 percent). So, they get to take the GVR, which is a 20 percent subtraction and then they calculate the 4 percent on that reduced number. This is a way of preserving some tax benefit for the GVR fields when the minimum tax is in place. 5:14:16 PM MR. ALPER referred to slide 18 and said the idea of carry forwards in HB 111 replaces the 35 percent NOL credit and 100 percent of losses are carried forward and subtracted from future production tax value. In many ways, it is no different than the current year's spending, only it can be brought up in the future. One feature is the decline in value that was presented as an incentive to get production done in a timely manner. So long as those carry forwards are used within seven years they have full value; beginning in the eight year they start eroding at 10 percent per year and would be completely lost after 17 years. The ring fencing is also present. 5:15:21 PM MR. ALPER said the tax rate, itself, has the most headlines on this bill and eliminating the current 35 percent tax with the per-barrel credit that ranges $0-8/barrel. It is replaced with a 25 percent flat rate and the per-barrel credit is eliminated. That is at lower prices, anyway, identical to the original SB 21 proposal from the Parnell Administration. It would be the same revenue and the same tax at oil prices below $90-95/barrel, the entire expected range of the near and mid-term future and at the time was acceptable to industry. However, it is a substantial tax increase of roughly $100-300 million at oil prices in the $50-100 range. Instead of having the progressivity, this bill has progressivity only instead of having it by subtraction, it has it by addition. So, the 25 percent is the base rate and then there is a bracket, should there be a relatively high profit year, where the production tax value is greater than $60/barrel. Only that portion of the value above $60 would be taxed at the higher rate, with the additional 15 percent surtax or in effect, a 40 percent tax. The first $60 would only ever be taxed at the 25 percent rate. That is more like the bill that the previous administration brought in in 2011, HB 110, which passed the House and not the Senate. Interestingly, Mr. Alper said this very closely tracks SB 21 and is revenue-neutral at high prices. It's not the same 35 percent tax; it's the 25 percent plus this progressivity, but the result is the same. Once you get out of the tax increase, above $100 it is the same revenue as current law. It aligns the value of the carried forward to the effective tax rate. If you're paying a 25 percent tax and have a carry forward, you are getting value at the 25 percent level. If you're paying a 30 percent tax and have a carry forward, you are getting value at the 30 percent rate. It creates some symmetry between the developer and the producer in the tax code. 5:18:15 PM MR. ALPER said there are some small changes to the gross value reduction (GVR) that experienced a major change last year with HB 247 in that it was made no longer permanent. It's now a temporary benefit for new production that meets certain criteria and it's a 30-percent gross reduction. So, CSHB 111(FIN)(EFD FLD) creates a hard floor which did not used to exist. Currently GVR oil can pay a zero tax; under the proposal a GVR oil would be paying the 3.2 percent hard floor. The 5-percent, per-barrel credit is maintained whereas the per- barrel credit on the legacy oil is eliminated. This has an unusual result: it's a tax increase at lower prices, because there is a hard floor, but at higher prices it's actually a tax cut on new oil, because a of the 25 percent tax supplanting the existing 35 percent tax. The other thing CSHB 111(FIN)(EFD FLD) does is repeal a provision from SB 21 that created a second category of gross value reduction, a 30 percent benefit, if all leases are state leases with greater than 12.5 percent royalty. It's something of a payback of the incremental revenue from high royalty fields. The 30 percent GVR is repealed in this version of the bill. 5:19:40 PM CHAIR GIESSEL asked how it is rational to raise the tax at lower prices and yet at higher prices it's a lower tax. MR. ALPER replied that he could speak to the motivations of the people who wrote this version of the bill, but he senses it is an unanticipated consequence of making multiple changes at the same time. The desire was to harden the floor, and hardening the floor is inevitably a tax increase at low prices if the floor wasn't already hard. They also happen to be cutting the base tax rate. If that $5 per-barrel credit were eliminated because the other per barrel credits was eliminated, he sensed that it would be more revenue neutral at higher prices. It's an interaction of choices that are made, and the bulk of the decisions are made around the legacy oil, because that's where the revenue is. CHAIR GIESSEL said the GVR was intended for new oil. The high royalty fields obviously have higher royalty (gross tax); even at low prices it's always there. She was confused about why it is being eliminated. MR. ALPER replied that he is not speaking for or against this provision, but Representative Seaton, who brought it forward, said in the Finance Committee if these are higher royalty fields, it means that industry sees them as more valuable. They could bid a higher royalty with the expectation that they were prepared to give a larger royalty to the state for the privilege of being able to develop that resource. Why, therefore, give that incremental royalty back through a higher new oil benefit? From his point of view, it seemed counter intuitive to give a larger benefit to a field that almost by definition has the higher prospectivity and higher likelihood of success. CHAIR GIESSEL thanked him for that explanation. 5:22:02 PM SENATOR WIELECHOWSKI recalled that when ACES was introduced it had a 10 percent gross floor and a lower progressivity of .2 percent, and the compromise was to take out the 10 percent floor. Then SB 21 got rid of the high end. So, now the state has no functioning income at the low end or the high end, but interestingly, he remembers members of the oil industry saying they were okay with ACES when it was originally introduced with the 10 percent floor. "Correct me if I'm wrong on that." His other point is the 30 percent GVR for high royalty fields, was a last-minute amendment to SB 21 had in the House Finance Committee with very little debate about where that 30 percent GVR was added. "Am I correct in my recollection of those two events?" MR. ALPER, working backwards through his questions, answered yes to his second question. That was not part of the bill that passed the Senate; the 30 percent GVR addition was part of the CS in the House Finance Committee a couple of days before the final passage. It's not productive to rehash the legislative history of ACES, but he and several committee members where here for it. "But you're here and I'm here, so why not?" The 10-percent hard floor was limited to Prudhoe Bay and Kuparuk, specifically defined as fields with life-time aggregate production of over 1 billion barrels. He recollected that it was not received well by industry, and part of the compensation for removing it from subsequent versions of the bill was to add the steeper progressivity calculations. 5:24:34 PM MR. ALPER said other provisions of the bill like the interest rate going to zero is a substantial hardship for the Tax Division to implement. The is not about incentivizing the department to get its audits done faster, but making it difficult to settle a tax obligation. If the department comes forth three or seven years later saying a company owes money, the instinct is to challenge and appeal it and take it all the way through the court system, because there is no down-side. It's not about years four, five, and six; it's more about years seven, eight, and nine. He was less concerned about what the interest rate is and more concerned that whatever it is it stay there for continuity of whatever the obligation is. His preference to align the interest rate for all tax types is not in this bill, although that is what the department did historically. It was 11 percent in the distant past and 3 percent plus the federal rate under SB 21, and HB 247 carved out a separate interest rate for the oil and gas production tax at this new 7 percent plus federal rate for three years declining to zero. Meanwhile, the 3-percent SB 21 rate remains in place for the other 20-odd tax programs he administers. MR. ALPER mentioned the annual report of refunded cash credits written in HB 247, this bill expands that to credits that are issued or held and not cashed, lease expenditure totals, lease expenditures carried forward, tying it to the lessor property, and the purpose of the expenditure. The dataset that gets used to build the ring fence is also within the limits of taxpayer confidentiality, and some legal advice is needed as to what can be reported. 5:26:46 PM SENATOR WIELECHOWSKI asked if he has any sense of cash credit impacts to the state if Smith Bay was built. MR. ALPER replied that the department uses a big round number to describe the Smith Bay project or the Pikka project, and it's not unusual for the capital cost to exceed $10/12 per barrel for a billion-barrel, in-the-ground project. He could comfortably say this could be a $10-billion project and possibly more. If a company were to spend $10 billion under current law, presuming the state is buying cash credits, it could result in $3.5 billion of credit liability. The current limitation is an individual company (not per project) can only get $70 million per year, with some caveats. One would assume that such a large project wouldn't be done by a company acting alone, but someone with three or four partners. So, they are looking at multiple hundreds of millions of dollars a year of obligation. 5:28:14 PM MR. ALPER said the third provision is the idea of gross value going below zero. His modeling slides used Point Thomson as the example, although he didn't like singling out a specific project, but he used Point Thomson because it happen to be a currently small production at a remote site with a very large pipeline that is therefore expensive to operate, and they are paying a $17 tariff to get the 22 miles to the nearest connection to pre-existing infrastructure. So, they could be in a circumstance at low prices where they would have a negative wellhead value before getting to lease expenditures and operating costs. Their gross value would be below zero. Under current law, gas cannot have a gross value below zero, but oil can. So, that negative value would migrate and be usable against their taxable value from other fields, essentially bringing a downstream cost into an upstream calculation. His staff has been adamant in saying that this is a necessary technical correction that should be made, and although it's controversial, this bill version does not let gross value for a particular field go below zero. 5:29:30 PM The assignment statute was added relatively late in the game in an unrelated non-oil bill that passed in 2013, the ability to directly assign the tax credit certificate, so that when the state is buying something it doesn't pay the company but pays the banker directly. That has led to some sub-optimal decisions being made over investment. Meanwhile that money isn't even going to go into the oil patch; it's going to go to somebody's banker. Taking away the assignment statute was intended to simplify that world. Finally, he said there is the creation in the bill of a Cook Inlet working group. House Bill 247 extended the tax cap last year, which was scheduled to go away in 2022. The intent, as he understood it, was for a perpetual extension. Meanwhile, there was an aggressive credit system, which will phase out and be eliminated next year. The tax cap extension resulted in the long-term tax plan for Cook Inlet now being the 17-cent gas tax and the $1/barrel oil tax. Interestingly, that $1/barrel oil tax effectively goes away in 2022, anyway. Because of the changes from the AKLNG bill, SB 138, which passed in 2014, the gas tax goes to a gross tax on the North Slope and Cook Inlet. That results in all the lease expenditures being calculated against the oil side. Because Cook Inlet is such a gas-heavy basin, that would be enough to zero-out the oil tax. The $1/barrel tax isn't a flat tax; it's a maximum tax and would reduce the oil tax to zero beginning in 2022 under current law. So, for that reason and others, the other body put in a working group to reconsider the oil tax in Cook Inlet. 5:32:17 PM CHAIR GIESSEL thanked him and noting they are at a breaking point in the presentation, she adjourned the Senate Resources Committee meeting at 5:32 p.m.