SENATE FINANCE COMMITTEE February 13, 2025 9:01 a.m. 9:01:41 AM CALL TO ORDER Co-Chair Stedman called the Senate Finance Committee meeting to order at 9:01 a.m. MEMBERS PRESENT Senator Lyman Hoffman, Co-Chair Senator Bert Stedman, Co-Chair Senator Mike Cronk Senator James Kaufman Senator Jesse Kiehl Senator Kelly Merrick MEMBERS ABSENT Senator Donny Olson, Co-Chair ALSO PRESENT Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue; Senator Cathy Giessel. SUMMARY PRESENTATION: ORDER OF OPERATIONS DEPARTMENT OF REVENUE Co-Chair Stedman discussed the agenda. He commented that the presentation on the order of operation would address the state's oil and gas tax structure. He commented that the structure was one of the most complex on the planet. ^PRESENTATION: ORDER OF OPERATIONS DEPARTMENT OF REVENUE 9:04:13 AM DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE, discussed a presentation entitled "Order of Operations Presentation Senate Finance Committee" (copy on file). He relayed that the purpose of the presentation was to provide a high-level overview of Alaska's oil and gas production tax. The presentation would focus on Alaska North Slope (ANS) oil. He agreed that there was a lot of complexity and nuance in the tax code. Mr. Stickel showed slide 2, "Acronyms," and noted that he would endeavor to minimize the use of jargon in his presentation. Mr. Stickel spoke to slide 3, " Agenda • Oil and Gas Revenue Sources o FY 2023 FY 2027 oil and gas revenues • Production Tax Calculation "Order of Operations" o Detailed walk-through of for FY 2026 o FY 2023 FY 2027 comparison • Additional Discussion o FY 2026 Illustration Challenges o Examples of spending scenarios and tax impact o State Revenue by Land Type o Revenue per $1 of Oil Price and Historical Context Mr. Stickel relayed that he would offer a high-level overview of oil and gas revenue sources for the previous couple of fiscal years, with projections to FY 27. The presentation was not intended to be policy but rather illustrate the nuts and bolts of the fiscal system and set the groundwork for future discussions. The additional discussion listed on the slide was related to questions from the committee. Mr. Stickel referenced slide 4, " Disclaimer • Alaska's severance tax is one of the most complex in the world and portions are subject to interpretation and dispute. • These numbers are rough approximations based on public data, as presented in the Fall 2024 Forecast and other revenue forecasts. • This presentation is solely for illustrative general purposes. •Not an official statement as to any particular tax liability, interpretation, or treatment. •Not tax advice or guidance. • Some numbers may differ due to rounding. Mr. Stickel expanded that he was attempting to take a complex, nuanced tax system and put it in easily understandable pieces. He noted that he was an economist rather than an auditor or tax lawyer, and his comments were not an official tax interpretation. 9:07:53 AM Mr. Stickel turned to slide 5, "Oil and Gas Revenue Sources • Royalty based on gross value of production o Plus bonuses, rents, and interest o Paid to Owner of the land: State, Federal, or Private o Usually 12.5% or 16.67% in Alaska, but rates vary • Corporate Income Tax based on net income o Paid to State (9.4% top rate) o Paid to Federal (21% top rate) o Only C-Corporations* pay this tax • Property Tax based on value of oil & gas property o Paid to State (2% of assessed value or "20 mills") o Paid to Municipalities credit offsets state tax paid • Production Tax based on "production tax value" o Paid to State calculation to follow Oil and Gas Revenue Sources * C-Corporation is a business term that is used to distinguish the type of business entity, as defined under subchapter C of the federal Internal Revenue Code. Co-Chair Stedman asked for Mr. Stickel with help defining royalty, and whether it applied to gross or net profit. Mr. Stickel explained that royalty represented the state's share of oil as a landowner. The royalty would go to the landowner, which was primarily the state. There was also oil produced on federal land, and the royalty went to the federal government. A small portion of the federal royalty was shared with the state. There was a small portion of production on private land, and the royalty went to the private landowner. Most royalty was assessed on a gross value basis and was typically one-eighth or one-sixth, which was 12.5 percent or 16 and two-thirds percent of the value of the oil. There were some royalties that incorporated a net-profit scheme, which was referred to as net profit share lease royalties, which were less common. The royalty represented the state's share of the oil as landowner, after leasing out the land to companies to do the production. Mr. Stickel explained that the severance tax was a levy that the state assessed as a sovereign for the privilege of severing resources from the state. There was a net profits component to the severance tax as well as a gross component. 9:11:21 AM Mr. Stickel considered slide 6, "Oil and Gas Revenue Sources: Five-Year Comparison of State Revenue," which showed a table with all revenue from oil and gas from FY 23 to FY 27. He noted that the property tax revenue shown was state share of property tax, and there was an additional significant amount of over $500 million per year that went to municipalities. The corporate income tax applied to C corporations. There was a bit of a reduction between FY 23 and FY 24 primarily due to lowering oil prices as well as some refunds and one-time impacts in FY 24. He mentioned production tax, the value of which had dropped quite a bit over the years due to oil prices and higher company investment. Mr. Stickel addressed the royalties shown on the table, which represented the state share as well as the Permanent Fund and School Fund shares. The amount represented the unrestricted and restricted portion of the royalties. He highlighted two smaller sources of revenue. The Constitutional Budget Reserve Fund (CBR) Settlements, which were any settlements from oil and gas disputes. The Natural Petroleum Reserve-Alaska (NPRA) shared revenue was half of royalties received by the state from the NPRA were shared with the state and had special restrictions on spending. The funding functioned similarly to a pass-through to impacted communities. The revenue was expected to increase quite a bit beyond the time horizon of the slide as new developments such as Willow came online in the NPRA. Co-Chair Stedman asked for more detail on why there was $1.6 billion more to balance the budget in 2023. Mr. Stickel relayed that the primary driver for the higher oil and gas revenue in FY 23 was the ANS oil price shown on the first line. He noted that $86.63 per-barrel (bbl) was a fiscal year average. Prices throughout the year showed higher value months earlier in the fiscal year. The state had a very progressive production tax system and generated quite a bit more revenue when prices were high. Co-Chair Stedman thought the difference was important to point out while working on the budget and observing the difference in revenue. He summarized that the difference was primarily due to price. Mr. Stickel affirmed that the difference was primarily a function of price but was also a function of increased investment by certain taxpayers. 9:16:05 AM Mr. Stickel displayed slide 7, "Fiscal System: Overall Order of Operations," which showed a high-level flow chart of the order of operations. The chart showed how the elements of the oil and gas fiscal system were applied. Royalites were first, and the landowner got their share of the resource off the top before calculating of any taxes levied. State and local property taxes came second and were considered lease expenditures or allowable costs for the production tax and other tax calculations. Production tax came after royalties and allowed a deduction for property tax and came before calculation of corporate income tax. Mr. Stickel continued and discussed state corporate income tax, which used worldwide income as part of the tax base. Property taxes and production taxes were excluded from the calculation of worldwide income. Lastly came federal corporate income tax. All state taxes were allowed as deductions against the federal corporate income tax, including any state corporate income tax paid. Co-Chair Stedman asked about state corporate income tax, and why the tax counted revenue all over the planet. Mr. Stickel thought he was not the person to best elucidate the policy decision of how the state did the apportionment. Co-Chair Stedman asked Mr. Stickel to provide a high-level answer. He discussed apportionment, which he thought was started under the Hammond Administration. Mr. Stickel reiterated that he was not a tax lawyer. He mentioned that for determining corporate income tax, there were a few options. There was an option for separate accounting, in which a company would account for all its revenues and expenditures in the taxing jurisdiction, which was similar to what the state did for production tax calculation. The state chose to look at all of a company's revenue and expenditures all around the world and determine what share was attributable to Alaska. He recalled that at one point the state had shifted the Alaska-specific methodology and separate accounting and there had been litigation. Ultimately the state had prevailed, and the court allowed the state to use the separate accounting methodology, however the state had chosen to retain the apportionment methodology for corporate income tax. 9:20:34 AM Mr. Stickel highlighted slide 8, "Production Tax "Order of Operations": FY 2026," which showed a table showing gross oil production and price down to total tax paid to the state at the bottom. He noted that several slides would address the topic. The information was based on the income statement as presented in Appendix E of the Revenue Sources Book (RSB). The table walked through the FY 26 production tax calculation and was focused on ANS oil, as it was the largest portion of the state's oil and gas production tax revenue. He highlighted the $70/bbl oil Department of Natural Resources (DNR) forecast price, and a production forecast of 469,000/bpd, which calculated out a value of $33 million per day or about $12 billion for the year. He noted that the focus of the next several slides was taking the annual value of $12 billion of oil and looking at how it was taxed and split between the different components. Co-Chair Stedman referenced property tax and noted that the committee was viewing the presentation from the state's perspective. He pondered how a company's perspective on property tax would differ. Mr. Stickel explained that property tax was a cost of operation and equated to 2 percent of value or 2 mills of tax. The state allowed for a deduction for property taxes in the production tax calculation, to the extent that the tax was levied on pipeline structure or production and exploration infrastructure. Co-Chair Stedman asked if the state looked at property tax disregarding who ended up with the property. He thought sometimes people looked at only the state's portion, which he thought could lead to confusion. He surmised that for a company, the property tax recipient did not matter but it was an expense. Mr. Stickel answered affirmatively. 9:24:06 AM Senator Kiehl asked if the oil and gas property tax included everything a company owned, including a building in Anchorage or a company truck. He referenced pipelines and field infrastructure. Mr. Stickel explained that the oil and gas property tax applied to exploration and production property. The building Senator Kiehl mentioned would not be subject to the oil and gas property tax. Senator Kiehl did not think there was a slide on how the tax structure treated other municipal taxes such as taxes on office buildings. Mr. Stickel emphasized that the oil and gas property tax was accounted for and allowed as a lease expenditure. Other administrative overhead expenses were not directly accounted for, although there was an allowance for overhead. The production tax calculation allowed for a 4.5 percent overhead allowance that was treated as an operating expenditure. Senator Kiehl requested that Mr. Stickel make note of the allowance when addressing the production tax calculation. Co-Chair Stedman thought some of the items would not show in the calculation. He mentioned that the state used the Internal Revenue Service (IRS) definition of capital expenditures. Mr. Stickel agreed and noted he would be addressing more on the topic on slide 11. Mr. Stickel looked at slide 9, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on the first step of the tax calculation with royalty and taxable barrels. He explained that royalty barrels were subtracted from the tax calculation regardless of the owner. Typical rates were one-eighth or one-sixth of value, but rates did vary. For purposes of the production tax calculation, the state subtracted federal and private land royalty as well as the small number of barrels that were not subject to tax due to being in offshore federal waters beyond the 3-mile limit. Subtracting the items from total production arrived at the taxable barrels calculation of about 149 million barrels in FY 26, for a total taxable value of about $10.5 billion. 9:28:06 AM Mr. Stickel addressed slide 10, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on the second step of the tax calculation by addressing the gross value at point of production (GVPP), also known as well-head value. He relayed that the concept was widely used in both the tax calculation as well as the royalty calculation in determining the gross value. To get to gross value, transportation costs were subtracted, which included all of the costs of getting oil from the wellhead on the North Slope to market, typically on the West Coast. The official ANS price was priced in Long Beach, California. The calculation deducted marine transportation costs, the Trans-Alaska Pipeline System (TAPS) tariff, and any feeder pipeline tariffs or miscellaneous adjustments. For FY 26, the transportation costs were estimated to amount to $10.38/bbl, which left an average wellhead value of $59.62/bbl, with a total gross value for tax purposes of $8.9 billion. Mr. Stickel advanced to slide 11, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, with lease expenditures highlighted. He noted that production tax was essentially a modified version of a net profits tax. The state allowed companies to deduct costs of operation when calculating the net profits. For capital expenditures, the state generally used IRS guidelines. The expenditures were typically investments that had a lifespan of a year or more. He noted that the state did not have a depreciation calculation for capital expenditures. Companies were allowed to immediately deduct all capital costs in the year in which the costs were incurred. Operating expenditures were any allowable expenditures other than capital expenditures, typically the ongoing costs of operations and labor, including property tax and an allowance for overhead. Mr. Stickel noted that there were two terms to understand on the slide. He addressed allowable lease expenditures, which were any of the costs directly associated with production of the oil that were allowed in the tax calculation. There were some items that were specifically excluded, including financing costs, costs of acquiring leases, and dismantlement costs. He addressed deductible lease expenditures, an unofficial term developed by the Department of Revenue (DOR) that referenced that portion of the allowable lease expenditures that were applied to the tax calculation in the year incurred up to the gross value. He pondered how much of the lease expenditures reduced the tax calculation. He explained that to the extent that a company did not have sufficient gross value to apply the lease expenditures in the tax calculation, any additional lease expenditures became carry-forward lease expenditures, which could potentially reduce a future years' taxes. 9:33:07 AM Co-Chair Stedman thought it was important to note that when considering deductibility, some expenditures that were not deductible as lease expenditures but were deductible under federal income tax. Capital expenditures were fully deductible under the state tax structure but were spread out in the corporate tax environment. He clarified that there was not "double dipping" happening. He mentioned severance tax. Senator Kiehl mentioned operating expenditures and 4.5 percent for overhead including local taxes. He asked whether the state's oil and gas corporate income tax was deductible. Mr. Stickel referenced the overall order of operations and noted that the production tax came before corporate income tax. Senator Kiehl referenced things that were disallowed from being deductible. He asked about advertising and lobbying, and whether the expenses were excluded. Mr. Stickel thought the items would be categorized as "overhead," and would not be costs directly associated with producing or exploring for oil and gas. Senator Kiehl asked if the items were excluded. Mr. Stickel thought the items would be excluded from allowable lease expenditures, as they were not considered direct costs of exploring for or producing oil and gas. The overhead allowance was intended to account for all ancillary expenditures above and beyond exploring for and producing oil and gas. Mr. Stickel continued to address slide 11 and summarized that there was an estimated $7.6 billion of allowable lease expenditures in FY 26. He pointed out that $6.5 billion was forecast to be deducted in the tax calculation. The last line showed a forecast of $1.1 billion in lease expenditures in FY 26 to be not deducted and carried forward as lease expenditures to offset a future year's tax. Co-Chair Stedman asked about carry-forward expenditures. Mr. Stickel affirmed that there were some examples in the presentation. He offered that in a nutshell, if a company did not have sufficient gross value of production to apply all of its lease expenditures, the state allowed to carry the expenditures forward and potentially offset a future year's tax liability. He mentioned a new entrant that was developing a field and would potentially get benefit from the spending similar to the way an existing producer would. He thought the concept could be counter-intuitive and mentioned that there were three examples towards the end of the presentation that looked at what happened with different companies making investments in the state and how the companies benefitted from the lease expenditures. 9:38:08 AM Mr. Stickel looked at slide 12, "Production Tax "Order of Operations": FY 2026 which showed the same table as the previous slide, but focused on the calculation of the production tax value (PTV), which was the gross value minus the deductible lease expenditures. He described a "slope- wide ring fence," in which each company calculated its production tax value based on its all its slope-wide activity, including all fields and developments. The concept was important since each company operating in the state had a different portfolio of producing properties and investments. He cited that the production tax value worked out to roughly $16/bbl or about $2.4 billion total for FY 26. Co-Chair Stedman thought it was an important point that in the scenario Mr. Stickel described he had referred to three companies with varying levels of profitability. He noted that the legislature received company data in an aggregated fashion, despite the companies having different structures. He thought it was challenging when the legislature set policy to consider a tax structure to fit the variability. He referenced companies testifying indifference to the tax policy, while others expressed favor or disfavor. He thought it was an important nuance. Mr. Stickel showed slide 13, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on the gross minimum tax floor. He described two calculations done side-by-side, after which the company paid the state the higher of the two. The minimum tax floor was four percent of gross value anytime annual oil prices were greater than $25/bbl. In the chance that oil prices were lower on an annual average, there was a graduating scale of lower minimum tax rates. For FY 26, in the aggregate there was a projected gross value of $8.9 billion. At the 4 percent minimum tax floor there was a minimum tax of about $356 million. The minimum tax was compared to the net tax (shown on slide 14). The net tax took a 35 percent statutory tax rate and applied it to the PTV to determine the tax before credits, which was the higher of the net tax or gross tax. The department was forecasting that the tax before credits would be a net tax of about $843 million. 9:42:43 AM Mr. Stickel advanced to slide 14, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on the net tax and gross value reduction (GVR). The state was not forecasting the GVR would affect the gross value reduction in FY 26. The GVR was a benefit for companies that were developing a new field, under which it could exclude 20 percent or 30 percent of the gross value of production from qualifying new fields in the calculation of production tax value. The next tax was calculated after any applicable reduction for the GVR. The department did not forecast that the GVR would impact the production tax calculation for FY 26. Co-Chair Stedman acknowledged that Senator Cathy Giessel was in attendance. Mr. Stickel turned to slide 15, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on tax credit against liability. He explained that after calculating tax before credits on the previous slide, then any tax credits against liability would be applied. The major credits in the system included two versions of per-taxable-barrel credits. One version was for non-GVR eligible oil for fields that had been in production for several years. The fields had a sliding scale of per-taxable-barrel credit that ranged from zero (when the wellhead value was greater than $150/bbl) up to $8/bbl (when the wellhead value was less than $80/bbl). Mr. Stickel relayed that in FY 26 and throughout the time horizon of the revenue forecast, DOR was forecasting that companies would generate the full $8/bbl sliding scale tax credit. There was a separate flat $5/bbl tax credit that was generated for GVR-eligible production. A company could only use the sliding scale credits to reduce tax liability down to the minimum tax floor. If the company chose to forego sliding scale credits or was a new producer not generating any sliding scale credits, the company could use the other credits to reduce the tax below the minimum tax floor. Mr. Stickel continued that for FY 26, DOR was estimating that $1.19 billion worth of per-taxable-barrel credits would be generated and was forecasting that $572 million of the amount would be used against the tax calculation. A little over half of the generated credits were forecast to be foregone, and then could not be cashed out or carried forward. The average credit value per barrel was estimated to be between $2.33/bbl for the GVR-eligible credits, and an average of $3.86/bbl that was realized for the sliding scale tax credits. 9:47:30 AM Senator Kiehl asked Mr. Stickel to discuss how the credit functioned. He asked whether companies could make a profit at $90/bbl. Mr. Stickel explained that the calculation of the tax credit, and how much was generated, was irrespective of profit and was based on the wellhead value. The sliding scale credit was $8 per taxable barrel when the wellhead value (the gross value) was $80/bbl or lower. Given transportation costs, the price roughly equated to a $90/bbl market price. The ability of the company to apply and realize the full benefit of the tax credit would depend upon profitability. He mentioned that there were examples later in the presentation. He mentioned that of the $8/bbl that was forecast to be generated, only about $3.86 of the amount on average would actually end up reducing taxes. Co-Chair Stedman asked about the tax floor and "leaks" in the floor. Mr. Stickel mentioned the gross minimum tax floor of 4 percent of gross value. If a company applied any sliding scale tax credits, it could not reduce its tax liability below the minimum tax floor. However, if a company did not apply slidingscale tax credits, it could use other tax credits to go below the minimum tax floor. Co-Chair Stedman asked if Mr. Stickel would address the credits that went under the minimum tax floor. Mr. Stickel explained that the other credits would primarily be per-taxable-barrel credits for GVR-eligible oil. If there was a new entrant that did not have sliding- scale tax credits, for the first three to seven years of production would receive the GVR and would receive a $5/bbl credit that it could use to pay below the minimum tax floor. He mentioned the small producer credit, which was phasing out in the next few years but could be applied to go below the minimum tax floor. 9:50:48 AM Mr. Stickel considered slide 16, "Production Tax "Order of Operations": FY 2026," which showed the same table as the previous slide, but focused on some other items that were incorporated into production tax revenue received by the state in a given tax year. He listed prior year taxes or refunds, taxes on Cook Inlet oil and gas, gas on the North Slope, and a conservation surcharge. The primary item included in FY 26 was adjustment for company-specific issues. He mentioned companies that were in very different tax situations, which resulted in total tax paid to the state being different than taking an aggregate calculation. He identified that for the order of operations chart, there was about a $180 million difference. The adjustment item trued up the aggregate calculation to the actual revenue that DOR was forecasting. He identified that the per-barrel credits and minimum tax floor being two key components. Mr. Stickel displayed slide 17, "Order of Operations: Five Year Comparison," which showed the same analysis of previous slides but shown over a five-year period. For FY 23, there was a net profit of about $7.5 billion, and about $1.5 billion of total tax paid to the state for an effective tax rate of about 20 percent. He pointed out the effective tax rate on the bottom line as being fairly stable, with a roughly 19 percent effective tax rate in FY 27, based on a lower production tax value of about $2.2 billion and a lower tax paid to the state of about $427 million. He considered the five years and discussed changes in components, with lower production value and gross value based on changes in oil price, quite a bit higher lease expenditures based on increased company spending on new investments. The combination of two factors led to the reductions in estimated profit or production tax value. 9:54:22 AM Mr. Stickel highlighted slide 18, "Question: Why Doesn't the FY 2026 Tax Calculate Exactly?" He noted that the previous slides had been the main presentation, while the next several slides walked through specific issues in the current year, and some questions DOR had received. He pondered the question of why the tax didn't calculate out perfectly for FY 26. He explained that if one just looked at the aggregated calculation, versus the forecast for production value, there was a roughly $180 million difference which had to do with the significantly different tax situations for each of the companies operating in the state. He discussed the aggregated tax illustration, which was done to try and tie to specific numbers as possible. The per-taxable-barrel credits were higher in the company- specific calculations than they were in the aggregate calculation. He explained that some companies were able to realize the full $8/bbl credit and were paying tax revenue above the floor. Other companies were able to utilize less than the $8/bbl and some companies were not able realize any per-taxable-barrel credits at all. Mr. Stickel explained that tax paid to the state was higher when calculated on a per-company basis than the aggregate calculation, because some companies paid the minimum tax floor and each individual company completed the "higher of" calculation. Some companies ended up paying the state more due to the minimum tax floor than they would if based on the net tax calculation minus credits. He noted that there were a couple of examples that would walk through how the structure would work for different companies. Co-Chair Stedman noted that previously it was possible to calculate the numbers more closely. Mr. Stickel explained that the change had to do with some of the major investments taking place, as well as the position of oil price. He mentioned that at an oil price of about $70 /bbl, the state was very close to the threshold between companies paying at the minimum tax floor and paying above the minimum tax floor, which made the calculation more challenging. 9:58:44 AM Mr. Stickel noted that the following couple of slides showed examples of how a company's tax situation could vary depending on its portfolio of producing properties and investments. He noted that the slides were not intended to reflect any particular producer. He looked at slide 19, "Example 1: Low-Cost Producer," which showed a table that assumed a company with 50,000 bpd of production. The example considered lease expenditures that were lower than the slope-wide average, and the company would be paying the net profits tax. The lease expenditures were $24/bbl, giving a production tax value of about $35/bbl. The net profits tax would be $588 million, and the company would be able to utilize the full value of all per-taxable-barrel credits to reduce tax liability down to about $208 million, still paying above the minimum tax floor. Mr. Stickel addressed slide 20, "Example 1a: Low-Cost Producer w/ Increased Spending of $100 Million," which showed the same table as the previous slide, using the assumption that the company paid $100 million of additional lease expenditures. Under the scenario, the company still ended up paying above the minimum tax floor. The tax due went from $209 million to $172 million. The $100 million additional investment gave a 36.6 percent tax benefit, while still paying above the minimum. The company was able to deduct the $100 million as a lease expenditure, plus the overhead allowance on the $100 million. Mr. Stickel advanced to slide 21, "Example 2: Mid-Cost Producer," which showed the same table and example of the previous slide, but using a company with 150,000 bpd of production with an average cost structure. The company operated a mix of fields and was making investments into developing new fields. Under the example, the producer had a tax before credits of $266 million, which was the next tax. It earned the same $380 million of per-taxable-barrel credits as the first example but were only able to use $152 million of the credits in the tax calculation. The company was limited by the minimum tax floor and so ended up paying the state the $114 minimum tax floor. The company only realized $3.24/bbl of per-barrel tax credits versus the $8/bbl on the prior example. 10:02:57 AM Mr. Stickel looked at slide 22, "Example 2a: Mid-Cost Producer w/ Increased Spending of $100 Million," which showed the same table and example of the previous slide, but showing an additional $100 million investment. With additional investment, the company still paid the minimum tax floor. The company would reduce its net profits tax but would be also able to use less per-taxable-barrel credits to get down to the minimum tax. For the company's $100 million additional investment, it received no tax benefit. Since it had a positive production tax value, it also earned no carry-forward lease expenditures. Mr. Stickel spoke to slide 23, "Example 3: New Entrant," which showed the table example depicting a new entrant without current production. The example could also be an existing producer with very high investment expenditures relating to whatever current production it did have. The new entrant would pay no tax to the state but would earn a carry forward for the expenditures it was making. The example showed $1 billion in expenditures plus the overhead uplift, generating a $1 billion and $45 million carry- forward lease expenditure that could potentially be used to offset a future year's tax liability. Mr. Stickel referenced slide 24, "Example 3a: New Entrant w/ Increased Spending of $100 Million," which showed the table depicting the example of a new entrant with $100 million of additional spending. The new entrant would get to increase the value of its carry-forward lease expenditure by the $100 million plus the uplift. The company would get a potential 35 percent benefit by the spending in a future year. Senator Kiehl asked if the company would get a benefit from new barrels produced. Mr. Stickel answered affirmatively. Senator Kiehl asked if there was an allowance for new production. Mr. Stickel noted that the state offered the GVR, which was a benefit in the production tax calculation for new barrels, in which a company could reduce the net profits tax portion of the tax calculation for up to three to seven years of production. Senator Kiehl asked if the amount was additive to the carry-forward benefits. Mr. Stickel affirmed that the company would get both benefits, which showed up in different places in the tax calculation. 10:06:25 AM Mr. Stickel turned to slide 25, "Three Production Tax Situations • Low cost producer •All lease expenditures applied in tax calculation •Full benefit of per-taxable-barrel credit •Pays above minimum tax floor (net tax) • Higher cost producer •All lease expenditures applied in tax calculation •Zero or partial benefit of per-taxable-barrel credit •Pays at minimum tax floor •No benefit for additional lease expenditures "the Donut Hole" • New entrant •No lease expenditures applied in tax calculation •Zero benefit of per-taxable-barrel credit •Pays no tax, earns carry-forwards Mr. Stickel noted that the slide summarized the three previous examples. He explained that most major companies working on the slope fell into one of the three categories listed on the slide. He described what was termed a "donut hole," in which there was one group of companies that would benefit from new investment (the lower cost producers), one group that would benefit as a new entrant earning carry- forwards, and then a group of companies in the middle that would not get any additional benefit from investment within a certain range because of the position of profitability and minimum tax. 10:08:35 AM Mr. Stickel considered slide 26, "State Petroleum Revenue by Land Type," which showed a table of how petroleum revenues to the state varied by land type. He relayed that DOR had received a question related to the revenue impact of new developments such as Willow, and how the state's revenues compared to other production in the state. The slide showed how the petroleum revenues varied by land type. He noted that there was a version of the slide in the RSB. For any oil produced in federal waters more than six miles offshore, the state would not receive any direct revenue, and there was currently no production in the category. For any oil produced within three to six miles offshore, the state received 27 percent of the federal royalty, but state taxes would not apply. The only production on the North Slope that fell into the category was a small portion for North Star. Mr. Stickel continued that for anything on state land and up to three miles offshore, all state taxes applied regardless of land ownership. For any land within the three-mile limit, royalty applied and depended upon landowner. The state collected a direct royalty on state- owned land. For federal owned land and the NPRA, the federal royalty applied, and the government shared 50 percent back to the state. The state had to use the funds to support impacted communities, which was essentially pass-through revenues for the NPRA. He added that for federal owned production in the Alaska National Wildlife Refuge (ANWR), under current law the federal government shared 50 percent of revenues back to the state with no spending restrictions. For other federal land, the federal royalty applied, and 90 percent would be shared back to the state with no restrictions. There was currently no land in the category. Mr. Stickel continued that for private land, which was primarily Native corporation owned land, there was a privately negotiated royalty. The state did not get a direct share of the royalty but did levy a tax on private landowner royalty value as part of production tax. Co-Chair Stedman thought it would be helpful if the table on slide 26 had an additional column that showed the number of estimated barrels for each land type. 10:12:13 AM Senator Kiehl referenced Mr. Stickel's earlier comment that new barrels provided a benefit to all. He pointed out that as he looked at the chart, it looked as though the state provided all the credits whether the state got a royalty or not and no matter what the share to the state from the federal government. He thought it would be different if the state had a structure in which all the new barrels paid all the taxes. He thought the return to the state was highly dependent upon where the oil came from. Mr. Stickel affirmed that the value to the state was dependent upon the source of the oil. He referenced the slide and noted that state land had the oil that belonged to the state and naturally received a higher value. He referenced a white paper and analysis on the department's website that looked at the Willow project in particular that indicated the new projects were beneficial to the state. He mentioned the benefit of new development being more oil going through the pipeline, allowing the cost of the pipeline to be spread amongst a greater number of barrels, making the barrels more valuable. Senator Kiehl understood the dynamic. He referenced earlier slides that looked at $10.50 downstream costs. He thought the value got thin quickly. Co-Chair Stedman asked Mr. Stickel to provide the document he referenced. He thought the concern referenced by Senator Kiehl that "all oil was not equal" was frequently raised. 10:16:15 AM Mr. Stickel displayed slide 27, "Petroleum Detail: UGF Relative to Price per Barrel (without POMV), FY 2026*," which showed a graph that showed how unrestricted revenue for FY 26 could change with different oil prices. He mentioned questions about how state revenue might change with higher or lower oil prices than what was forecast. He cited that near the forecast price, a $1 increase or decrease led to about a $35 million change for revenue in FY 26. Co-Chair Stedman mentioned that one of the issues that had yet to be explained to the public was the source of information related to companies' expenditures. He asked Mr. Stickel to provide information on how often DOR interacted with industry. Mr. Stickel explained that DOR had a very robust set of filing requirements for companies and received monthly information filings with an incredible amount of detail included to support tax calculations. There were annual filings that trued up the entire year of tax information. The submissions were the basis for actual and historical data from companies. There were two supplemental tax filings for the economic research group. One was a production forecast filing with details about future production plans and was collected once per year in collaboration with DNR. There was a cost-forecast filing, through which companies submitted projections and documentation for operating and capital cost on a unit- specific basis that was collected twice per year. Mr. Stickel described conversations and written outreach to companies. For some companies there were follow-up meetings, on an as-needed basis, that were in collaboration with DNR. The production outlook was a ten-year outlook and the cost outlook was a five-year outlook with additional information gathered through meetings and written responses. 10:20:34 AM Mr. Stickel highlighted slide 28, "Question: Why Only about $35 million per $1 ANS Change? •Comparing to several years ago when the rule of thumb was closer to $100 million •Somewhat lower production impacts tax and royalty •Somewhat more non-state-land production impacts royalty •Somewhat more non-C-corp production impacts corporate tax •Progressive production tax •Lower price especially in real terms •Higher lease expenditures •More companies at minimum tax floor Mr. Stickel noted that the slide built on the previous slide. He highlighted the progressive production tax system, emphasizing that oil prices were lower and costs for investment were higher, so there was a lot less profit in the system to tax. He referenced the five-year comparison with over $7 billion in production tax value going down over five years to just over $2 billion in production tax value. There were more companies paying at the minimum tax floor. When at the minimum tax floor, a change in oil price only benefited the state 4 percent. When above the minimum tax floor, the state benefitted 35 percent of the change in oil price. All of the impacts led to the $35 million rule of thumb being used for FY 26. At higher oil prices such as $110/bbl or higher, the heuristic would be closer to a $75 million impact for every dollar change in oil price. Co-Chair Stedman asked about the $75 million impact for every $1 change in oil price. Mr. Stickel affirmed that if the oil price was over $110/bbl there would be a $75 million impact. Co-Chair Stedman thought expenditures on development of the North Slope had made a big impact. Mr. Stickel agreed and considered that all the impacts together had brought the state to the $35 million impact he referenced. Co-Chair Stedman asked if Mr. Stickel had any good news. Mr. Stickel affirmed that oil prices had been running slightly above the forecast, and he hoped to bring more good news later in the session. Co-Chair Stedman hoped for DNR and DOR to make productions as accurately as possible without skewing to the positive or negative based on political considerations. He asked if Mr. Stickel could recall the first time he had given the presentation in Senate Finance. Mr. Stickel could not recall but thought it had been at least a decade. Co-Chair Stedman thanked Mr. Stickel for his work and appreciated the layout of his presentation. He noted that the committee had asked the pension actuary to follow the structure used by Mr. Stickel in his presentation. Mr. Stickel looked at slide 29, "THANK YOU": Dan Stickel Chief Economist Department of Revenue daniel.stickel@alaska.gov (907) 465-3279 ADJOURNMENT 10:27:01 AM The meeting was adjourned at 10:26 a.m.