HOUSE FINANCE COMMITTEE February 22, 2021 3:01 p.m. 3:01:34 PM CALL TO ORDER Co-Chair Foster called the House Finance Committee meeting to order at 3:01 p.m. MEMBERS PRESENT Representative Neal Foster, Co-Chair Representative Kelly Merrick, Co-Chair Representative Dan Ortiz, Vice-Chair Representative Ben Carpenter Representative Bryce Edgmon Representative DeLena Johnson Representative Andy Josephson Representative Bart LeBon Representative Sara Rasmussen Representative Steve Thompson Representative Adam Wool MEMBERS ABSENT None PRESENT VIA TELECONFERENCE Corri Feige, Commissioner, Department of Natural Resources; Maduabuchi Pascal Umekwe, PhD, Commercial Analyst, Division of Oil and Gas, Department of Natural Resources; Mike Barnhill, Deputy Commissioner, Department of Revenue; Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue; Colleen Glover, Director, Tax Division, Department of Revenue. SUMMARY COMMITTEE ORGANIZATION PRESENTATION: DEPARTMENT OF NATURAL RESOURCES - PRODUCTION FORECAST PRESENTATION: DEPARTMENT OF REVENUE REVENUE FORECAST Co-Chair Foster welcomed the committee and reviewed the meeting agenda. He introduced House Finance Committee staff. He shared his intent to start budget subcommittee work the following week. ^PRESENTATION: DEPARTMENT OF NATURAL RESOURCES - PRODUCTION FORECAST 3:04:30 PM CORRI FEIGE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES (via teleconference),provided a PowerPoint presentation titled "Fall 2020 Production Forecast," dated February 22, 2021 (copy on file). She provided opening remarks. She described the prior year as one of unprecedented volatility in oil markets and productions levels. She explained that the events were driven by the Corona virus pandemic related price collapse and the resulting pro- rationing of North Slope pipeline throughput and production curtailment due to low oil prices. Currently, a period of modest recovery and stability exists, with production levels at roughly 500 thousand barrels per day and prices in the sixty dollar range. She believed that the prior year showed the resilience of Alaskas oil producers. She related that the silver lining in the COVID cloud was that production levels remained comparable to prior years due to aggressive production optimization measures taken by the producers. 3:07:58 PM MADUABUCHI PASCAL UMEKWE, PHD, COMMERCIAL ANALYST, DIVISION OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES (DNR) (via teleconference),addressed slide 2 titled Outline: Background o 2020 Pandemic and North Slope oil production o FY2020 in review 2020 Production Forecast o Result highlights o FY2021 Outlook o Ten-year outlook Summary Mr. Umekwe shared that the forecast was produced by staff in the Division of Oil and Gas. He provided a brief background of the events of 2020. He moved to slide 3 titled "2020: Pandemic-Related Production Disruptions." He summarized the pandemic related forces that shaped 2020 oil production. The shuttering of economic activity led to a curtailment or strong reduction in oil usage. He detailed that the demand destruction was coupled with a decade long surge in production. The U.S. had contributed about 50 percent of the supply of global oil. The strong supply and drastically reduced demand shocked the oil market and collapsed the price in a short period of time. Oil storage became a problem that caused some production shut-ins. Inland producers felt the pinch more than areas close to waterways. 3:12:56 PM Mr. Umekwe continued that what resources would rebound post-pandemic preoccupied markets around the world. He reported that in a positive way the story for Alaska had been very different. Sometime in July, much of the production had come back online. The fear that lost production in aging fields could not handle the rapid off/on switch in operations did not materialize in Alaska. He believed that the rebound was a testament to the rocks in Alaska and the excellence the operators brought to bear in terms of technology and efficiency. 3:14:37 PM Mr. Umekwe turned to slide 4 titled "Production and the 2020 Pandemic: Medium/Long Term Effects." He pointed to a graph that depicted the North Slope production contribution by drilling year. Every year of drilling contributes to long term rates. Production from new wells helps to mitigate overall NS production decline. For example, some past years of drilling contribute on average 3% to 8% of annual NS production for almost a decade. Laydown of drilling rigs in the FY2020/FY2021 is expected to impact NS production decline in the short term as well as the long term. FY2020/FY2021 undrilled wells constitute a set of 'Missing Wells' that would typically mitigate decline for periods beyond the year the wells are drilled. 'Compensatory' production enhancement activities could mitigate this 'lost development drilling' impact in the short term. Mr. Umekwe spoke to the benefit of drilling wells and noted that effort was greatly reduced in 2020. He delineated that much of the drilling that would normally happen in a year did not take place. The wells that were not drilled, called missing wells would impact production in the near to long-term. He pointed out that wells drilled currently impact future production. However, producers could engage in optimizing activities that could compensate for the missing wells in the short term. 3:17:07 PM Mr. Umekwe moved to slide 5 titled "Overall Perspective: North Slope:" On average, modest decline in production over the last 5 Fiscal Years: o FY16 to FY20 on average annual ~1% decline in production Recent Major Changes in Production o Prudhoe Bay Unit: Change of operatorship; strong ongoing production optimization efforts o Kuparuk Unit: Natural decline; pandemic related production disruption /interrupted rig activity o Colville River Unit: Natural decline; pandemic related production disruption /interrupted rig activity o Milne Point: ~28% growth (FY19 to FY 20)-M, L, I pad drilling o PTU: Progressively improved facility reliability Future Projects coming in: o Near future: Fiord West Development, GMT2, Raven Pad in Milne Point Unit, CD5 Expansion o Farther out: Pikka: FEED 2021 Willow: FEED; FID YE 2021 Mr. Umekwe turned to the chart on the top right of the slide that portrayed an average annual 1 percent decline in production since 2016. He characterized the decline as phenomenal considering the typical 4 percent to 6 percent long term decline on the North Slope. He contributed the lower rate of decline to prior production enhancement and development activities. 3:20:48 PM Mr. Umekwe turned to slide 6 titled "Status Update of Key Future Projects: North Slope." He reported that the chart was a time capsule of activity for six projects from January 2020 through January 2021. He listed the projects: Moose Pad Development, CD5 second Expansion, GMT2, Pikka, Willow, and Liberty. 3:22:55 PM Mr. Umekwe moved to slide 8 titled "Fall 2020 Production Forecast: FY 2021 Outlook:" For the first 5 months of FY2021 (July 2020 to Nov 2020), on average, daily production has come in within the range forecasted by the DNR. Difference between average daily production and mean forecasted statewide production is ~40,000 bbl; related to operational and production ramp-up timing decisions Mr. Umekwe pointed to the graph on the slide that depicted production from July 2020 through November 2020 (North Slope and Statewide). He explained that the blue bars portrayed the range of the departments forecast from low, mean, and high. He emphasized that operational decisions made by the producers would affect production and therefore, the forecast. 3:25:25 PM Mr. Umekwe advanced to slide 9 titled "FY2021: Production Variance July - Nov 2020:" Deferred/forestalled summer turnaround maintenance (TAR) benefits summer oil and NGL production Ongoing production optimization efforts improve facility efficiency, as well as facility and well uptimes. Mr. Umekwe noted that the graph at the bottom of the slide shows the highs and lows in production related to the producers operational decisions. He conveyed that typical of the North Slope, winter production levels were strong due to the absence of maintenance work in the winter months. The summer was the optimal time to perform maintenance. In addition, temperature impacted the use of gas. Every summer DNR typically expected work that would take fields offline leading to slightly lower production. He pointed out that in the summer of 2020, there was not a dip in production because the operator deferred summer work, which resulted in strong numbers in the summer. 3:27:59 PM Mr. Umekwe turned to slide 10 titled "Comparing Long-Term Projections:" • DNR forecasts FY2021 average annual production at 470MBOPD and a range of 413MBOPD and 526 MBOPD • DNR's forecast is a snapshot in time, reflecting current information on all projects considered, as well as operators' current plans. • Operators' long-term outlook falls within DNR's long term forecast range • DNR's mean case falls below sum of the aggregate of operators' submitted case forecasts, for most of outlook period, reflecting differences in long term development case assumptions between DNR and operators. Mr. Umekwe illuminated that the gray bar on the graph depicted DNRs high prediction and the orange bar represented the operators outlook. The faded bar portrayed DNRs low side forecast. He informed the committee that DNR employed an independent method to formulate its forecast than the producers method that used different assumptions and standards. Despite the two different forecasting approaches, the DNR forecast covered a range that included the operators outlook and the departments mean forecast. 3:30:04 PM Mr. Umekwe moved to slide 11 titled "Long Term Production Outlook: Production Categories:" Currently producing (CP) fields remain the backbone of state oil production in near and medium term. Near- term projects under development (UD), often within existing fields, impact 12-month outlook. Future fields (UE), which are currently being evaluated by operators, begin to play a more significant role in farther out in outlook period. All new production/projects add to a declining base production Mr. Umekwe highlighted that the dark red portion of the graph represented projects under development. The blue field portrayed currently producing fields and the brown portion showed future fields. He underlined that the current production trend generally declined. 3:32:32 PM Mr. Umekwe moved to slide 12 titled "Increasing Uncertainty as New Fields/Projects Come Online:" Graph above shows seasonal variation in monthly production as well as widening uncertainty for the outlook period through 2030. New fields, currently in appraisal and under evaluation, are major drivers for medium/long term uncertainty in overall outlook Mr. Umekwe offered that uncertainty increased in longer- term forecasts. Often, the expected production was never what actually happened - production could exceed or be below projected. 3:34:03 PM Mr. Umekwe turned to slide 13 titled "Projects Under Evaluation Medium to Long Term." Mr. Umekwe explained that the map depicted the location of the projects located on the North Slope. 3:35:00 PM Mr. Umekwe advanced to slide 14 titled "New Projects Under Development/Evaluation: Adding to a Declining Base Production:" • New projects add to a declining base production. In the absence of new projects, decline of existing fields expected to exceed the 4% to 5% historical decline of the North Slope • In scope and estimated ultimate volumes, new projects compare closely with historical PBU/KRU satellites, as well as some standalone developments such as CRU-Alpine. • Inclusion of further risks and timing of new projects is reflected in rates lower than operator-announced estimates. • Actual outcome and timing of these projects remain critical in maintaining North Slope historical 4% to 5% historical decline or the possibility of flattening or growth in production. Mr. Umekwe described the graph as a portfolio of all projects anticipated to begin production in years two to ten of the forecast. The prediction is risk weighted. He underlined that the graph demonstrated the challenge to maintain flat production; new projects and increased investment in existing fields stem the decline. 3:37:27 PM Mr. Umekwe spoke to the Summary on slide 15: DNR forecast continues to use the best information available to DNR/DOR, to generate independent production outlook for oil fields within the state, with a focus on generating accurate near-term and realistic long-term forecasts for planning purposes. Production from projects under evaluation within the 10-year outlook period reflects uncertainty in operator plans towards return to drilling activity, specific project uncertainties, depressed oil prices and commercial risks, as well as project scope and timing risks. DNR forecasts assume steady-state development on currently producing fields, similar to past history for all the fields. While considering a wide range of drivers for different fields and potential projects and excluding specific exogenous production shocks such as production curtailments, prorations, or the full range of options available to operators in daily operations, the DNR forecast has so far provided a reliable range to guide fiscal planning for the State. Mr. Umekwe summarized that the goal was to have a forecast using the best information available to DNR. The 10-year outlook period reflected uncertainty in operator plans. 3:38:59 PM Co-Chair Foster acknowledged that Representative Ken McCarty was in the audience. Vice-Chair Ortiz referred to the passage of SB 21 Oil and Gas Production Tax [CHAPTER 10 SLA 13, 05/21/2013] that he described as the latest major piece of oil tax legislation in 2013. He remembered that due to the bill's passage, the industry reported it would be producing about twice as much oil, roughly 1 million barrels per day in a short amount of time. He asked why production had never come close to 1 million barrels per day (bbl/d) rather than remaining at the approximate 500 thousand (bbl/d). Commissioner Feige did not recall an assertion of adding 500,000 new barrels under SB 21. She offered to follow up. She observed that there had been a flattening of the decline curve since the passage of SB 21 the decline had remained at about 1 percent per year for some time. In addition, an invigoration of exploration work commenced in approximately 2014 in Pikka and Willow. She noted a roughly 90 percent discovery rate in a 5-year period, which represented new barrels of oil from new reservoirs and would come into production in approximately 2025. She concluded that the discoveries she described were the impacts of the passage of SB 21. 3:42:23 PM Representative Johnson looked at the key projects listed on page 6. She identified three wells located on state land she thought were important: Pikka, CD5, and the Moose Pad Development. She asked for a summary of what needed to happen to get to the production stage and what DNR could do to remove obstacles that stood in the way of production. Commissioner Feige reported that Moose Pad was in the Milne Point Unit and was operated by Hilcorp, which was aggressively expanding and had increased production by 28 percent or. She elaborated that there was some production in the unit that was subject to net profit share lease terms; the leases were economically distressed. There was currently legislation [HB 81-Oil/Gas Lease:DNR Modify Net Profit Share] that would unstrand the resources within the Milne Point Unit. She elaborated that the CD5 area expansion included ongoing drilling and was in an area of leases jointly managed by the state and Arctic Slope Regional Corporation (ASRC). CD5s development depended on access through the deployment of ConocoPhillips new large extended reach drilling rigs. The rigs drilled out from existing pads for 5 to 6 miles without having to build additional roads or gravel pads. She reported that the Pikka Project had been moved into the Front End Engineering Design (FEED) stage. She indicated that due to the low oil price environment the operators, Oil Search and Repsol, had taken another look at the development plan and were starting a phased development that could initially produce 80 thousand bbl./d. She declared that DNR continued to support the projects in addition to Willow, Liberty, and those within the Natural Petroleum Reserve-Alaska (NPRA) by staying engaged with federal partners and ensuring projects that had been through the National Environmental Policy Act (NEPA) process be allowed to continue. 3:46:52 PM Representative Johnson wanted to confirm that DNR was doing everything it could from the states perspective to keep the projects moving forward. Commissioner Feige answered in the affirmative. Representative Wool asked how long the rationing had taken place on the pipeline, that affected production during COVID. Commissioner Feige answered there had been prorationing events that began in April and extended through May. She elucidated that there was a prorationing and curtailment event in the Kuparuk unit of 60,000 bbl./d. In addition, Colevile River decreased by 40 thousand bbl./d, Badami oil field shut in 1, 500 bbl./d from May through October. In addition, two fields in Cook Inlet, West McArthur River and Redoubt Fields in total shut out approximately 1,900 barrels per day in May and had not come back online yet. The prorationaing on the Trans-Alaska Pipeline System (TAPS) ceased by the end of May when storage capacity in refineries on the west coast of the mainland opened up. Representative Wool asked if the prorationing had been due to storage. He recalled that for a time, the oil price was negative and it had cost money to move oil through the pipeline. He deduced that it was not a supply problem that caused rationing, but the price of oil. He asked if the issue had been foreseen by anyone. He wondered if the oil was not economical to sell it could create problems sustaining the pipeline. Commissioner Feige answered that when there was a low price shock such as took place in April [2020] and caused negative prices it was due to the pandemic related massive contraction in the global consumption market. She elucidated that global consumption had been decreased by 20 million barrels per day, which was the equivalent of total United States (US) production. The price and demand collapse had occurred so rapidly that there was not time to respond quickly enough to stop producing. She explained that it was necessary to back a well out of production, it could not be quickly shut off or damage to the foundation could occur. The negative price was a result of the collapse taking place so quickly causing the lack of storage. She delineated that any time the storage at Valdez reached between 60 and 70 percent capacity a notice of proration was issued. The oil vessels were sequenced to open up more storage and the whole system was managed upstream from Pump Station 1. Low throughput in very cold level temperatures was the greatest operational and structural challenge for TAPS. 3:51:59 PM Representative Wool cited slide 11 that showed the production curve remaining relatively flat through 2030 with all the projects coming online to offset natural decline. He deduced that the best case scenario would be flat production over the next 10 years. He wondered whether investors deciding not to invest in Arctic drilling, corporations like General Motors that had decided to not make gasoline powered cars by a certain date, and other global factors considered in the projections. Commissioner Feige deferred to Mr. Umekwe. Mr. Umekwe answered that there was uncertainty factored in projections based on several things: price, technological effects, and supply and demand. He delineated that in terms of single projects, the division did not try to calculate in every single factor that may impact the production but focused on the larger factors that might affect production. He noted that on slide 11 the numbers represented the mean case. He pointed to slide 12 and indicated the graph illustrated the full range of predictions, which included the best case scenario. The high case was approximately 700 thousand bbl./d. The mean case included much of the uncertainty that was recently discussed. 3:55:25 PM Representative Wool spoke about oil at $60 per barrel. He wondered whether the price was currently stable. He remarked that he had not seen a prediction for the price of oil. Commissioner Feige deferred to the Department of Revenue for the forecasted price of oil. She acknowledged the price of oil was modestly stable and vacillated according to geopolitical and climate events. 3:56:37 PM Representative Carpenter asked what the current and maximum capacity was for TAPS. He asked if the capacities changed over time. Commissioner Feige answered that the figure was just over 500,000 per day for the last seven days. The pipeline saw a peak of 2 million per day at its peak, but acknowledged that the optimum peak operating range was 1.5 million bbl./d. She shared that Alyeska Pipeline Services had well managed the pipeline and performed effective maintenance and modernization work over the years; the assest was in very good condition. She added that very cold weather events and lower volumes of oil, especially traversing Atigun Pass were the choke points. Aleyeska has added heat to the pipeline under those conditions to maintain the integrity of the flow of oil. Representative Carpenter asked if slide 8 referred to the spring 2020 forecast. Mr. Umekwe answered that the slide showed a five month comparison from July 2020 to November 2020 of what happened versus what was forecasted. 3:59:17 PM Representative Carpenter was trying to determine whether the numbers were based on the spring forecast. Mr. Umekwe clarified that it was based on the fall 2020 forecast. Representative Johnson asked if there were obstacles that DNR could remove to get state land projects moving along. Commissioner Feige answered in the negative. She detailed that the projects were in a period of routine permitting. Representative Johnson spoke to the states commitment to getting production into the pipeline. She asked whether DNR was doing everything necessary to the goal of increased throughput. Commissioner Feige replied, "Absolutely." She elaborated it was in no way in the state's best interest to slow down the process of new production. Co-Chair Foster thanked the presenters. 4:02:01 PM AT EASE 4:11:59 PM REONVENED ^PRESENTATION: DEPARTMENT OF REVENUE REVENUE FORECAST DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE (via teleconference), introduced a PowerPoint titled "Fall 2020 Forecast Presentation," dated February 22, 2021 (copy on file) beginning on slide 2: Agenda 1. Forecast Background and Key Assumptions 2. Fall 2020 Revenue Forecast Total State Revenue Unrestricted Revenue 3. Petroleum Forecast Assumptions Detail Oil Price Oil Production Oil and Gas Lease Expenditures Oil and Gas Credits Mr. Stickel moved to slide 4 titled Background: Revenue Sources Book: 1. Historical, current, and estimated future state revenue. 2. Discussion and information about major revenue sources. 3. Prepared in accordance with AS 37.07.060 (b)(4), and supports long term plan under AS 37.07.020. 4. Official revenue forecast used for Governor's budget proposal; updated in spring. 5. Located at tax.alaska.gov Mr. Stickel related that the Revenue Sources Book (RSB) was published every December and contained the fall forecast. The division gather data from the tax revenue management system, state accounting system, and various state agencies to report actual revenue for the most recent fiscal year to provide a 10-year revenue forecast. Mr. Stickel turned to slide 5 titled "Key Alaska Economic Indicators." 1. Real State GDP: $50.9 billion in Q3 2020 • Up 7.2% from Q2 2020, still down 4.9% from Q3 2019 • 2. Employment: 290,400 in December 2020 • Down 24,100 (-7.7%) compared to December 2019; heaviest impacts in leisure/hospitality, transportation/warehousing, and oil/gas industries 3 Wages & Salaries (seasonally adjusted): $21.8 billion in Q3 2020 • Up 5.2% from Q2 2020 and flat from Q3 2019 4. Alaska Bankruptcies: 313 for calendar year 2020, 19 for January 2021 • Compared to 400 for all of 2019, 38 for January 2020 5. Foreclosures: 98 in Q3 2020, 303 for calendar year 2020 • Compared to 197 in Q3 2019 and 729 for calendar year 2019 6. Housing Starts: 1,494 for calendar year 2020 • Compared to 1,689 for calendar year 2019 Mr. Stickel indicated that in the third quarter of 2020 state Gross Domestic Product (GDP) significantly increased by 32.2 percent of the annual rate after two quarters of major losses. The value of the economy was improving but was not back to pre-recession levels. Employment in the state was still down by nearly 8 percent compared to one year earlier. 4:16:46 PM Mr. Stickel turned to slide 6 titled "Fall Forecast Assumptions:" The economic impacts of COVID-19 are uncertain; DOR has developed a plausible scenario to forecast these impacts. Key Assumptions: o Investments: Stable growth in investment markets, 6.75% Permanent Fund returns. o Federal: Some CARES Act funds shown in FY 2021, no additional stimulus in FY 2022+. • Petroleum: Alaska North Slope oil price of $45.32 per barrel for FY 2021 and $48.00 per barrel for FY 2022. No further oil production curtailments. o Non-Petroleum: Most economic activity will return to baseline levels by FY 2022, except tourism full recovery by summer 2023. Mr. Stickel emphasized that the elephant in the room was Covid-19, which remained a large source of uncertainty in the forecast. 4:19:08 PM Mr. Stickel advanced to slide 7 titled "Relative Contributions to Total State Revenue: FY 2020." He explained that the slide depicted the relative importance of the different sources of revenue to total state revenue. He noted that federal revenue [48.2 percent], investment earnings [20.8 percent], and petroleum [19.7 percent] were the largest sources of total revenue. All other sources of revenue amounted to roughly 12 percent of total revenue. He advanced to slide 9 titled Total Revenue Forecast: FY 2020 to FY 2022 Totals and Percent Change from FY 2020. He detailed that the states revenue was broken into four categories of restriction including unrestricted general funds (UGF), designated general funds (DGF), other restricted revenue, and federal revenue. All categories had specific provisions around how the funding was used and was considered restricted revenue. He added that DGF, other restricted revenue, and federal revenue was often collectively referred to as restricted revenue. He elaborated that in FY 20 total state revenue was approximately $8.7 billion and forecasted total state revenue at $10.8 billion in FY 21 and $10.3 billion in FY 22. The unrestricted portion was $4.5 billion in FY 20 and the forecasted amount was $4.3 billion in FY 21 and FY 22. He pointed to the chart containing the percent changes between the fiscal years. He reported that overall, the fiscal year 2022 forecast for UGF was roughly 6 percent lower than fiscal year 20 levels and about 1.4 percent lower than fiscal year 21 levels. In FY 22, total state revenue was forecasted at 19.1 percent higher than FY 20 levels and 5 percent lower than FY 21 levels. 4:22:46 PM Mr. Stickel turned to slide 10 titled Unrestricted Revenue Forecast: FY 2020 to FY 2022 Totals and discussed unrestricted revenue. He expounded that investment revenue was the largest source of unrestricted revenue to the state. In FY 20, the total was nearly $3 billion and was predicted to be roughly $3.1 billion in both FY 21 and FY 22. The Percent of Market Value (POMV) transfer comprised most of the investment revenue. He furthered that oil revenue totaled a little over $1 billion in FY 20 and was predicted to total over $800 million in both FY 21 and FY 22. Non- Petroleum revenue contributed roughly $400 million in FY 21 and was forecast to remain that amount in the next two fiscal years. 4:23:50 PM Mr. Stickel advanced to slide 11 titled "Unrestricted Revenue Forecast: FY 2020 and Changes to Two-Year Outlook." He reported that the chart detailed each component of unrestricted revenue and included a comparison of the Spring 2020 forecast and the Fall 2020 forecast. He pointed to the Alaska North Slope oil price. The forecasted price increased by $8.32 bbl. between the Fall 2020 and Spring 2020 prediction totaling $45.32 bbl. and increased $7.00 bbl. to $48.00 bbl. in FY 22. The reason was stabilization and recovery in oil markets from the pandemic. The current futures market predicted a price of $60 bbl. in 2022. He noted the increase of $21.3 million for the FY 22 forecast between the spring and fall forecasts due to stronger than expected market returns for the last several months of FY 20, which affected the calculation for FY 22. He concluded that the FY 20 actual total investment revenue was in line with expectations. The FY 21 forecast was $87.5 million higher than the fall forecast and FY 22 decreased by $58.3 million. He indicated that one of the largest contributors to the FY 22 change was due to reductions in corporate income tax. 4:26:01 PM Mr. Stickel moved to slide 12 titled Unrestricted Investment Revenue: FY 2020 to FY 2022 Totals. He discussed that investments were now the state's largest source of UGF. He spoke to the importance of the Permanent Fund transfer that was expected to contribute over two- thirds of the states unrestricted revenue every year over the next ten years. The scenario represented the reality of living in a climate low oil prices and production decline. He mentioned that there was a small amount of other UGF that represented earnings from cash balances. Mr. Stickel spoke to slide 13 titled Unrestricted Investment Revenue: Percent of Market Value (POMV) Forecast: The statutory POMV rate changes to 5% beginning FY 2022. For FY 2019 FY 2021 this rate was 5.25%. Forecast assumes Permanent Fund's long-term total return expectation of 6.75%. Differing Permanent Fund returns and petroleum deposits could significantly alter actual POMV. Mr. Stickel pointed to the graph that depicted the POMV transfer at over $3 billion each year rising to $3.7 billion by FY 2030. He disclosed that the forecast was a baseline and did not factor in any unanticipated draws from the Earnings Reserve Account (ERA) beyond the POMV draw. Mr. Stickel highlighted slide 14 titled Unrestricted Petroleum Revenue: FY 2020 to FY 2022 Totals. He explained that there were four main sources of unrestricted oil revenues: Petroleum Property Tax, Petroleum Corporate Income Tax, Oil and Gas Production Tax, and Royalties. Petroleum property taxes were stable and contributed over $100 million each year. The corporate income tax was zero in FY 2020 and was predicted at $5 million in FY 21 and negative $20 million in FY 22. The negative amount reflected net tax refunds. He offered that the oil production tax or severance tax for the North Slope was comprised of a net profits tax with a gross minimum tax floor. The current forecast prices for the next two years was expected to bring in a little under $200 million. He added that royalties were the largest source of unrestricted petroleum revenue totaling $675 million in FY 20 and forecasted at over $500 million in the next two fiscal years. He noted that in addition to the unrestricted royalties a portion of royalty revenue was deposited into the Permanent Fund and was much higher than unrestricted royalties. Mr. Stickel examined slide 15 Unrestricted Non-Petroleum Revenue: FY 2020 to FY 2022 Totals. He related that Non- Petroleum corporate income tax was the largest source of unrestricted non-petroleum tax revenue and generated $102 million in FY 20 and was predicted to decrease to $30 million in FY 21 and $25 million in FY 22. Other significant taxes included Mining License Tax, Insurance Premium Tax, and Fisheries Taxes. The total unrestricted non-petroleum tax revenue was predicted to generate $216 million in FY 21 and $228 million in FY 22. The total unrestricted non-petroleum revenue was expected to be $363 million in FY 21 and $372 million in FY 22. He presented slide 16 titled Unrestricted Revenue Forecast: Non-Oil and Gas Corporate Income Tax (CIT). He shared that forecasting the corporate income tax was challenging. He briefly described the methodology he used to predict the income tax revenue. He conveyed the two major unusual impacts to income tax revenue: the recession, and the impact from the Coronavirus Aid, Relief, and Economic Security Act (CARES Act.) He explained that the CARES Act provisions allowed corporations to carry back any net operating losses from 2018 to 2020 up to five years and receive refunds for previous taxed paid. In addition, another provision allowed companies to accelerate certain alternative minimum tax refunds into 2019. The CARES Act provisions were automatically applied to Alaskas tax via state statute, unless the legislature chose to decouple or modify the provisions. He elucidated that for general corporate income tax, the department was expecting lower revenue from the pandemic related recession and the Cares Act impact further reduced the expected FY 21 revenue by $20 million totaling $30 million for FY 21 and $72 million in CARES Act related refunds in FY 22 reducing the net revenue for FY 22 to $25 million. The department forecasted that the revenue would rebound to $130 million in FY 23. 4:34:20 PM Mr. Stickel moved to slide 17 titled "Unrestricted Revenue Forecast: Oil and Gas Corporate Income Tax. He indicated that the oil industry was deeply impacted by COVID and paid no corporate income tax in FY 20. He was predicting very low revenue for FY 21 and estimated a net negative for FY 22. In FY 23, the oil and gas corporate income tax was predicted to rebound to $55 million, which was far lower than the several hundred million per year generated when oil prices and profits were higher. 4:35:05 PM Mr. Stickel advanced to slide 19 titled Petroleum Detail: Changes to Long-Term Price Forecast. He related that the graph depicted the fall 2020 forecast in comparison to the spring 2020 forecast. The fall forecast had been generated on December 1, 2020 and based on the most recent futures market projections. The fall forecast was based on the Alaska North Slope average oil price of $45.32 bbl. and was $8.32 higher than the spring forecast. The FY 22 forecast was $48 per barrel, a $7.00 increase over the prior forecast. He commented that beyond FY 22 it was assumed the oil price would increase with inflation; prices would increase by $1 or $2 per year. He reviewed Slide 20 titled "Petroleum Detail: Nominal Brent Forecasts Comparison as of January 20, 2021. The graph compared DOR's ANS forecast to Brent price forecasts from the U.S. Energy Information Administration (EIA) futures market known as NYMEX and the average of analyst forecasts. He addressed Slide 21 titled "Petroleum Detail: UGF Relative Price per Barrel (without POMV): FY 2022. He explained that the graph showed how unrestricted revenue for FY 22 would change with different oil prices. The data assumed official forecasted North Slope production of 439,600 barrels per day. Near the forecasted ANS price of $48.00, a $1 decrease in price led to an approximately $15 to $20 million change in UGF revenue, and a $1 increase led to an approximately $25 to $30 million change in UGF revenue. 4:38:18 PM Mr. Stickel turned to slide 22 titled "Petroleum Detail: North Slope Petroleum Production Forecast. He articulated that the graph portrayed the forecasted decline of 8 percent in FY 22 to 440 thousand barrels per day. The decline reflected the lack of drilling due to the pandemic. Production was expected to stabilize in FY 23 and slightly increase to 482 barrels per day as new fields began producing. He highlighted Slide 23 titled "Petroleum Detail: Changes to North Slope Petroleum Production Forecast." He indicated that the slide showed the fall 2020 forecast compared to the spring 2020 forecast - the overall changes were minor; a slight increase was expected in FY 23 through FY 25. He moved to Slide 24 titled "Petroleum Detail: North Slope Allowable Lease Expenditures. He elucidated that the graph depicted how allowable lease expenditures changed over the last decade and forecasted the expenditures over the next 10 years. The costs were reported on tax returns. He remarked that company spending was an important measure of current and planned investment. In FY 20, North Slope capital expenditures was $2.6 billion and operating expenditures were $2.9 billion. The amounts were well below the spending over the last decade. The division observed dramatic cutbacks in spending in FY 21 with some signs of recovery on the horizon. He anticipated that total North Slope spending would decrease by $1.6 billion in FY 21. Capital spending was expected to increase in FY 22 and FY 23 as companies invested in major investments such as Willow and Pikka. Capital expenditures were forecasted to stabilize at $2 billion per year. The division forecasted that many of the operating expenditure reductions made by companies in the past year would be permanent. 4:41:39 PM Mr. Stickel highlighted slide 25 titled "Petroleum Detail: North Slope Transportation Costs. He offered that looking at transportation costs was important because it reduced the value of oil for both tax and royalty purposes. The transportation costs included all costs of getting oil to market including feeder pipeline tariffs, Trans Alaska Pipeline tariffs, and all transportation costs. The forecast estimated the average transportation cost was $8 in FY 20, $9.21 per barrel for FY 21, and $9.91 for FY 22, increasing to $11.00 per barrel. Further out the increases were based on lower production, inflation, and that a greater proportion of production will be subject to feeder pipeline tariffs. 4:43:00 PM Mr. Stickel addressed Slide 26 titled "Petroleum Detail: Tax Credits for Purchase Detail. He illuminated that the graph showed a projection of how the outstanding balance of tax credits, estimated at $760 million, would be reduced over time if the statutory appropriation were made beginning in FY 22. He expounded that prior to 2016, various oil tax credits existed in statute that reduced tax liability or were turned into tax credit certificates that the state could purchase at face value. The legislature imposed sunset laws by 2017 on all new credits and were currently totally phased out. However, an outstanding balance from credits issued prior to the sunsets remained. The statutory annual repayment formula was based on either 10 percent or 15 percent of estimated production tax levied before credits. The multiplier was 15 percent when the ANS price forecast was below $60 and 10 percent for prices above $60 per barrel. He furthered that since FY 07, $3.6 billion had been spent by the state to purchase the full amount of tax credits. After 2016, less than the full amount of tax credits had been purchased; FY 20 was the first year no repayment appropriation was made. The forecasted scenario assumed a statutory appropriation in FY 22 that increased each year through complete repayment in FY 31. 4:45:44 PM COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE (via teleconference), provided an oil and gas production tax audit update on slide 28. She shared that the division made significant progress towards maintaining a three year audit cycle for oil production taxes. Currently, the statute of limitations for audits was 6 years from the return filing date. The division had adopted the Tax Revenue Management System (TRMS) that had enabled the production tax team to work remotely and deliver audits without any paper. The auditors were working proactively to request additional data shortly after the return was filed, which increased the amount of retrievable backup information the auditors received. Audit Completion and Catchup Plan: o 2014 Audits completed 4Q 2020 o 2015-2017 audits complete by 3Q 2021 o 2018-2019 audits complete by 1Q 2023 o Reach and maintain three-year audit cycle by 1Q 2023 ? Improvements to Reach Goal o Automated processes vs manual processes o Ability for taxpayers to use customer portal o Stability of workforce o Effective two-way communications 4:48:49 PM Representative Josephson looked at slide 13 that showed a substantial increase in POMV transfers. He noted that DNRs production forecast predicted sustained production at 500,000 barrels per day. He surmised that it was important to guard the 5 percent POMV draw because it was what sustained the government. Mr. Stickel answered that it was an astute observation. He reiterated that the POMV was forecast to represent more than two-thirds of the state's unrestricted revenue stream over the next decade and beyond. Representative Josephson looked at the oil and gas production tax of $163 million on slide 14. He recalled that production tax had been in the billions in the 2000s and on. Currently, it was substantially less than royalty. He asked whether his assessment was correct. Mr. Stickel replied in the affirmative. He remarked that when oil prices and company profits had been higher the production tax had been higher and brought more revenue to the state. 4:51:31 PM Representative Josephson looked at slide 26 and the payment of the oil and gas tax credits. He believed that beginning in FY 16 the state had paid less than the statutory formula. Most recently, the state was not paying anything. He asked for the accuracy of his statements. Mr. Stickel answered that prior to FY 16, the state had paid higher than the statutory formula in full. Since FY 20, no appropriations had been made to repay tax credit certificates. Representative Josephson looked at the $50 million payment on slide 26. He asked if it was reflected in the governor's proposed operating budget for FY 22. Mr. Stickel deferred the question. MIKE BARNHILL, DEPUTY COMMISSIONER, DEPARTMENT OF REVENUE (via teleconference), asked Representative Josephson to restate the question. Representative Josephson reiterated his question. Mr. Barnhill answered that the budget included $60 million for tax credit repayments. 4:53:51 PM Vice-Chair Ortiz followed up on a question by Representative Josephson regarding the importance of the POMV for state revenue on slide 13. He asked how the line on the graph would change if the state made an additional $3.2 billion draw beyond the 5 percent POMV draw. Mr. Stickel answered that there would be a significant increase in the near-term and later the line would decrease. He would have to follow up with detailed numbers. Vice-Chair Ortiz asked if the slope would be significantly less steep over the long-term. Mr. Stickel agreed that the slope would be lower if more was drawn from the fund, and it would increase if more was put into the fund. Vice-Chair Ortiz referred to slide 11 related to the Permanent Fund transfers to the POMV and wanted clarification. He noted that the FY 20 transfer amounted to roughly $2.9 billion and was significantly more revenue than generated from oil taxes. He cited slide 7 that pertained to FY 20 total state revenue. He pointed out that investment earnings only made up 20.8 percent of the states revenue and petroleum accounted for 19.7 percent. He thought there would be a larger difference the two sources of revenue based on the data on slide 11. 4:57:10 PM Mr. Stickel answered that slide 10 looked at FY 20 actual state revenue. He offered that earnings for the Permanent Fund had been well below 6.75 percent in FY 20. However, the long-term return estimate was 6.75 percent annually. Representative LeBon referred to slide 5 and commented on key Alaska economic indicators. He suggested that banks had been working with secondary mortgage borrowers to keep Alaskans in their homes through loan modifications or other means. He remarked that borrowers took advantage of the low interest rate environment and purchased homes. He commented that foreclosures and bankruptcies had been down and that the banks were working with the borrowing community to help make successes. 4:59:35 PM Representative Wool looked at slide 5 and asked what percent of the $50 billion DGP was oil. Mr. Stickel replied that he did not have the data on hand. He remarked that oil and gas was a significant amount of the state's output. Representative Wool stated that other slides showed oil revenue at about $1 billion. He asked what it would have been before the oil crash of 2014. Mr. Stickel referenced data from FY 2012. He noted that there was an appendix (Appendix A-3 on page 101) of the 10-year history of oil revenue in DORs Revenue Sources Book. He reported that in FY 12 unrestricted oil revenue was $8.9 billion and restricted oil revenue was an additional $1 billion that totaled just under $10 billion of total petroleum revenue in FY 12. The total value of oil and gas had been higher at that time. Representative Wool ascertained that the states oil revenue had been reduced to approximately 10 percent of what it had been in a 10-year period. He asked if he was correct. 5:01:58 PM Mr. Stickel answered in the affirmative. Representative Wool asked if there was a total revenue projection over the next ten years. He cited slide 19. Mr. Stickel answered that the fall 2020 forecast was based on the most recent projections as of December 1, 2020. He detailed that at the time, the expectation for FY 22 was the ANS forecast of $48 per barrel increasing with inflation. The $60 price was approximately what the FY 22 outlook might be when looking at the present futures market. He viewed the forecast as one source of optimism that oil prices were trending a bit higher than when the fall forecast had been prepared. 5:04:39 PM Representative Wool looked at slide 28 related to the oil and gas production tax audits. He asked whether the state negotiated a settlement amount with companies that owe money as a conclusion of an audit. Ms. Glover replied that when an audit was issued the taxpayer could agree and pay or appeal. She communicated that there was an informal appeal process within the division adjudicated by an appeals team that issued an independent decision. The taxpayer then had the option to pay or file a formal appeal with the Office of Administrative Hearings. There was a final appeal available to the courts. During any time in the process settlements could be reached via DOR and the Department of Law. Representative Wool asked whether settlements had occurred in recent audits. Ms. Glover replied in the affirmative. Representative Wool asked about the tax credits offered by the CARES Act [slide 16] that amounted to $91 million. He deduced that the net result to the state was ultimately the same; the state was currently paying the credit instead of taking less tax in the future. 5:07:20 PM Mr. Stickel clarified that the CARES Act impacts on slides 16 and 17 were not tax credits. He reiterated that net operating losses were able to be carried forward and use the value of the loss against future taxable income. The CARES Act allowed companies for 2018, 2019, and 2020 to carry back any net operating loss to reduce taxable incomes for previous years by refiling and potentially receive a refund for the lower tax liability. He agreed that it was the same net operating loss (NOL), the state had an exposure one way or another. He added that there was the potential that not all NOLs would be able to be used in the future, but if so, it would be a net wash for the state. He characterized it as a timing issue. Representative Wool surmised that CARES Act impacts were a credit and not a refund that normally applied to future earnings. He asked about the loss of state income taxes from oil companies. He asked if the forecast considered that BP was being bought by Hilcorp; it did not pay taxes to the state. Mr. Stickel stated his understanding of the question. He replied in the affirmative - the transaction was reflected in the forecast. The forecast assumed that roughly 70 percent of oil and gas production was attributed to C corporations. 5:10:43 PM Representative Wool reiterated that BP was a C corporation and paid income taxes to the state and Hilcorp was an S Corporation and did not pay the same income taxes. He asked for the amount BP had paid in income taxes in the last year and assumed that Hilcorp would not pay the same amount as an S corporation. Mr. Stickel answered that the department could not speak to what a specific taxpayer had paid or was expected to pay. He could only speak to the aggregate amount. Representative Wool speculated that about 30 percent was not C type corporations. 5:11:39 PM Representative Rasmussen looked at slide 5 and felt that the slide figures painted a misleading picture. She elucidated that her husband worked as a mortgage originator and had seen a recent increase in mortgage interest rates. She guessed that 2020 was a record year for the real estate industry. She asked if there was a breakdown of the $21.8 billion in wages by industry. She wondered how the hospitality, transportation, and the oil industry fared in wages and salaries. She deduced that wages in those industries would be in decrements. She wondered how a bust in the real estate boom would impact the economy if the real estate industry became impacted by the higher interest rates. Mr. Stickel replied that the wage data came from the Department of Labor and Workforce Development (DLWD), which also provided the jobs data. He related that the low interest rates had been acting as a stimulus to the economy and anyone borrowing money was benefitting from the current low interest rate environment. Representative Rasmussen stated that the real estate industry could see a sharp decline quickly from the impacts of interest rates climbing. She reiterated her question regarding how a decline in the real estate industry would affect the rest of the economy. 5:15:44 PM Mr. Stickel agreed that higher interest rates was an area of concern and merited paying attention to. He determined that if the higher interest rates were accompanied with a broader economic recovery, it could offset some of the impacts. He thought that if the Federal Reserve and lenders were forced to raise interest rates rapidly it could have a negative impact. Representative Rasmussen reiterated her questions. Mr. Stickel rephrased Representative Rasmussens inquiry. He stated that of the $21.8 billion in wages and salaries in the third quarter of 2020, how much was dependent on the real estate industry. He offered that the best way to approach the question would be to provide a breakout of the contribution of the key industries to the number. Representative Josephson pointed to slide 5 and asked whether DOR was concerned that the number of bankruptcies were as low as they were during the Covid-19 crisis because they were forestalled by artificial means through federal assistance. He wondered if bankruptcies were anticipated to be a problem once the COVID relief monies ceased. 5:18:56 PM Mr. Stickel agreed that bankruptcies were an area of concern assuming that federal aid would eventually be withdrawn as the economy recovered. 5:20:12 PM Vice-Chair Ortiz cited slide 28 regarding the tax audit update. He wondered whether the division had data regarding the average amount paid through negotiated settlements versus the total amount that was owed. He provided the example of settling for .90 cents on the dollar and wondered what the impacts from the settlement process was. Ms. Glover answered that each audit process was different, and the settlement amount depended on the audit issues. Vice-Chair Ortiz asked if she meant there were no parameters on the process. He wondered whether the settlement could fluctuate between .90 cents on the dollar to .30 cents on the dollar. Ms. Glover answered that not every audit resulted in an appeal process. She reiterated that each audit was different, and the issues were different. 5:22:36 PM Mr. Barnhill shared that Mr. Stickel gave a presentation called order of operations in the Senate Finance Committee. The point was made that the state's oil and gas tax regime was the most complex in the world, partly due to changes that were made frequently. He deduced that due to the complexity and frequent changes it was difficult to achieve any consistency in settlement values. He offered that every tax case was scrutinized by the Department of Law (DOL) via a settlement committee that advised DOR on the strength and weaknesses of the case. He assured the committee that there was a very robust process for reviewing and assessing a tax settlement case before DOR takes a position on the case. Representative LeBon responded to Representative Josephsons question regarding foreclosures on slide 5. He voiced that banks reported their financial conditions quarterly in a document called a call report. The call report contained several leading economic indicators, delinquency rates, other owned real estate, and trends of non-performing loans. He suggested reviewing call reports 18 months before the pandemic began through the present to gain insight on where the economy is headed. Co-Chair Foster thanked the presenters and reviewed the schedule for the following day. ADJOURNMENT 5:26:21 PM The meeting was adjourned at 5:26 p.m.