Legislature(2021 - 2022)ADAMS 519
01/19/2022 01:30 PM House FINANCE
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|Presentation: Department of Natural Resources Production Forecast|
|Presentation: Fall 2021 Revenue Forecast|
* first hearing in first committee of referral
= bill was previously heard/scheduled
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HOUSE FINANCE COMMITTEE January 19, 2022 1:32 p.m. 1:32:21 PM CALL TO ORDER Co-Chair Foster called the House Finance Committee meeting to order at 1:32 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 (via teleconference) Representative Steve Thompson Representative Adam Wool MEMBERS ABSENT None ALSO PRESENT Maduabuchi Pascal Umekwe, PhD, Commercial Analyst, Division of Oil and Gas, Department of Natural Resources; John Crowther, Deputy Commissioner, Department of Natural Resources; Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue; Senator Bert Stedman; Senator Click Bishop; Senator Natasha von Imhof; Senator Bill Wielechowski; Senator Donny Olson. PRESENT VIA TELECONFERENCE Corri Feige, Commissioner, Department of Natural Resources. Colleen Glover, Director, Tax Division, Department of Revenue. SUMMARY PRESENTATION: DEPARTMENT OF NATURAL RESOURCES PRODUCTION FORECAST PRESENTATION: FALL 2021 REVENUE FORECAST Co-Chair Foster relayed that the committee would be following COVID-19 mitigation policies in effect. He reviewed the meeting agenda. He recognized Senate Finance Committee members including Co-Chair Bert Stedman and Co- Chair Click Bishop in the room. SENATOR BERT STEDMAN, offed a gift of appreciation on behalf of the Senate Finance Committee to the House Finance Committee for all of its hard work over the past several years. He held up a symbolic check in the amount of $4.943 billion to the principal of the Permanent Fund on behalf of future generations of all Alaskans. He held up a second symbolic check for $4 billion dated July 21, 2021, for future generations of all Alaskans. He offered one of the two checks for the House Finance Committee to display. The other check would be displayed in the Senate Finance Committee room. He stated the committees had worked together to save approximately 10 percent of the entire Permanent Fund for future generations. He stated that in 30 to 40 years the $8.9 billion would grow to "stacks of billions." Co-Chair Foster asked for any comments from members. Representative LeBon stated that any bank would honor the checks. He asked to accept the $4 billion check. Co-Chair Foster suggested accepting the $4.9 billion check. 1:37:49 PM Representative Edgmon thanked the Senate Finance Committee for its growing commitment to growing the Permanent Fund. He remarked that Alaska was the only state with an endowment. He lauded the committee for holding the line in terms of growing the fund. He appreciated the gesture. He remarked there was lightheartedness in the gesture, but the underlying message was serious. Co-Chair Merrick thanked the Senate Finance Committee and appreciated working collectively with the committee in the past couple of years. She believed it was an example that working collaboratively resulted in achieving great things. Co-Chair Foster stated he was up for taking either check. Representative LeBon concurred with Co-Chair Foster's choice. Representative Wool thanked Senate Finance for all of its work. He asked for the larger check. Co-Chair Foster requested to receive the $4.9 billion [symbolic] check. Co-Chair Stedman thanked the committee. Co-Chair Foster thanked the Senate Finance Committee. ^Presentation: Department of Natural Resources Production Forecast 1:40:05 PM CORRI FEIGE, COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES (via teleconference), echoed thanks to both finance committees for their commitment to growing the Permanent Fund for future generations of Alaskans. She believed it was germane the [symbolic] checks were presented on the frontend of the 2021 production forecast because of the relationship to royalty revenues directed into the Permanent Fund. She introduced Department of Natural Resources (DNR) staff. She provided opening remarks with a prepared statement: Looking back, in 2021, the oil sector recovery from the chaos and extreme price and demand fluctuations that were so prevalent during 2020 and the peak of the global pandemic, the International Energy Agency notes the demand has now been ahead of supply since the th third quarter of 2020 through the 4 quarter of 2021. Year 2022 is looking like we will see higher and more stable prices enduring. Members of the committee will probably know that Alaska North Slope Crude closed just above $89/ barrel yesterday. 2022 will likely see global rebalancing and continued strong prices, though that can change very quickly in this rather uncertain and highly politically charged global environment. At the most th recent meting of the OPEC Plus on January 4, those member nations announced that they planned to continue to their restrained monthly increase in supply; however, some analysts worry that this restrained approach indicates that the idle capacity in some of these nations is going to be difficult to return to production and it is that market dynamic that has driven prices higher over the last couple of weeks. Stronger and more stable prices and increasing demand is good for Alaska's industry. Though when the current political climate, companies across the petroleum sector and especially those operating in Alaska, face significant headwinds, there is pressure on all companies to exhibit capital discipline and increase shareholder profits and returns and that combined with climate activism and energy transition dynamics is resulting in financial barriers and slower reinvestment in the sector. The times are uncertain. Alaska's operators are taking full advantage of the price rise and near-term stability to continue to capture more efficiency, value, and production from the existing assets, and that is resulting in somewhat flattened decline rates across many of Alaska's major North Slope fields. 1:44:20 PM MADUABUCHI PASCAL UMEKWE, PHD, COMMERCIAL ANALYST, DIVISION OF OIL AND GAS, DEPARTMENT OF NATURAL RESOURCES, provided a PowerPoint presentation titled "Fall 2021 Production Forecast," dated January 19, 2022. He addressed elaborated on comments made by Commissioner Feige. He remarked it had been an interesting 12 to 24 months with [oil] prices swinging between below zero and the current numbers. He intended to discuss the production outlook throughout the presentation. He noted the work had been conducted within the Division of Oil and Gas by a team of geologists, engineers, and commercial analysts, who worked with the assets on a daily basis. The forecast had been done in close collaboration with the Department of Revenue (DOR). The presentation included a review of FY 21, the DNR production forecasting approach, and the fall 2021 forecast results. Mr. Umekwe advanced to the outlook for FY 21 production on slide 4, which DNR had forecast in fall 2020. He pointed to a black bar reflecting actual production in a bar chart on the lower right of the slide. He noted the gray bars in the extremes [to the far left and far right of the chart] represented the high and low production ranges generated by DNR, while the gray bar to the immediate left of the black bar reflected DNR's expected case. The blue bar reflected an aggregate look at what different operators thought. He reported that the actual production came within DNR's forecasted range and was about 5 percent above the department's expected case. Mr. Umekwe touched on factors the department believed would shape the landscape for existing and upcoming projects. Factors included energy transition and strong environmental, social, and governance issues that impact the way companies looked at capital in the Arctic. He referenced statements made on the factors in the media and from Wall Street. He remarked that companies in Alaska were aware of energy transition and were taking steps to address their strategy and response. He noted there were multiple options available to companies and each company approached the transition in its own way, picking options that matched their long-term strategy. Mr. Umekwe stated that COVID-19 had really impacted the numbers and overall project climate. He remarked that the impacts beginning in 2020 continued to shape the way companies interacted and managed fields and redevelopment efforts. 1:48:46 PM Mr. Umekwe moved to slide 5 and addressed "FY 2021 Summary: North Slope." He considered what was expected from oil and gas fields that were past the point where significant development was occurring. He pointed to a chart on the bottom right showing production changes across North Slope assets and explained that he largely expected assets to show as red because fields generally declined on a year to year basis. He added that a green bar indicated that something was happening with the assets. He remarked it took a lot to stabilize decline let alone increase production in a given asset. Mr. Umekwe continued to address slide 5. The slide showed that North Slope production from FY 20 to FY 21 increased by 2 percent. The increase included activities in the Greater Prudhoe Bay Unit (GPBU) due to well/facility optimization efforts. He noted that when looking at historical data, it would be necessary to go back to 2005 to see facilities being run at their current level. He noted the prior operator set the groundwork for the optimization efforts and the current operator was moving their own strategy of cost reduction and looking across the fields for small opportunities. Additionally, the Milne Point Unit (MPU) had seen a 20 percent increase in production due to consistent drilling efforts. He relayed ExxonMobil's efforts, which had been taken over by Hilcorp, had resulted in a 40 percent growth in the Point Thomson Unit (PTU) due to improved facility reliability. Mr. Umekwe discussed decreases in production on slide 5. He reported that ConocoPhillips had held production at the Kuparuk River Unit (KRU) essentially flat at FY 20 levels. He noted there was a drop of 300 barrels, which was a phenomenal feat. The Greater Mooses Tooth Unit 1 (GMT1) had seen a 50 percent production drop due to persisting reservoir challenges. He highlighted the presentation would show good news for the asset resulting from the next phase of development: GMT2. He highlighted that the absence of drilling at Oooguruk since 2016 had led to declines shown on the slide. He stated that overall, it was good to see the growth in the amount that was being seen on the North Slope. The first effort was to stabilize decline and add to it. 1:52:47 PM Co-Chair Foster noted that Representative Rasmussen was online. Mr. Umekwe moved to an FY 21 summary on Cook Inlet basin. He highlighted the importance of the basin that produced much supply for in-state refineries as well as yielding revenues from royalty-in-kind sales. He stated that the basin production had decreased by 22 percent or ~3,000 barrels of oil per day. Some of the decreases for the basin included the Redoubt Shoal and McArthur River fields that were taken offline at the height of the pandemic in June 2020 as a result of the pandemic-related oil crash. He noted the two fields had been brought back online. 1:54:29 PM Mr. Umekwe turned to slide 7 and showed a snapshot of some of the North Slope projects that would be impacting the outlook over the next two fiscal years. He listed the Fiord nd West Kuparuk, CD5 2 expansion, and the Narwhal projects. He stated it was significant activity in the asset as the operator continued to deepen portfolio projects. He highlighted the first oil had been produced in the Narwhal unit in December 2021. The plan was to drill about 12 wells going forward, which would increase the amount of oil to a peak of around 32,000 barrels of oil per day. The first oil for the GMT2 project had been drilled in November 2021. He detailed that the wells had not all been drilled but there was consistent work to bring to its estimated level of production of a peak of around 30,000 barrels per day. Mr. Umekwe pointed out that production did not reach its peak right from the beginning. He discussed the Pikka field and noted a merger between Santos and Oil Search had been completed and the FID [final investment decision] was expected for phase 1 of the development. He noted phase 1 was expected to result in ~80,000 barrels per day. Production was anticipated to increase in 40,0000 barrel increments. He highlighted the Willow field and noted the operator was working on issues highlighted in a court decision. The project was expected to reach the second record of decision by the end of 2022 with construction to follow in the beginning of 2023. 1:57:31 PM Co-Chair Foster noted that Vice-Chair Ortiz had joined the meeting. Representative Josephson asked about the Willow field on the list shown on slide 7. He observed that the slide appeared hopeful that corrections could be made, and the project could move forward. He asked for the accuracy of his statement. He asked if the department followed the details of the litigation. Mr. Umekwe answered that much of the information shown on the slide was the publicly available information. JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, responded that DNR and the Department of Law (DOL) had been following the litigation and remand from the court. He detailed that the necessary record of decision and approval from the Bureau of Land Management (BLM) was back with BLM at present. He elaborated that DNR was participating in the group reviewing the identified deficiencies and corrections and supporting the federal agency to try to accelerate the review for completion in a timely way. The schedule shared with DNR would complete the review in 2022 and would allow construction to proceed in 2023. He noted that the timelines were always aspirational; however, the Willow timeline was incredibly important to the state. He explained the department was working very hard to do everything possible to support the federal review to keep it on schedule. Representative Wool asked if they were discussing the Natural Petroleum Reserve-Alaska (NPRA) fields that were in question. He looked at the estimate of 130,000 barrels of oil per day. He asked if the ultimate projection from DNR would include the 130,000 barrels per day. Mr. Crowther answered that the Willow field was in the federal leases within NPRA, while the Pikka project was located on state leases near the boundary on state lands. He verified that the numbers in the presentation reflected the volumes [projected on slide 7] in the outyears. 2:00:11 PM Representative Edgmon observed on slide 7 that the start of production in phase 1 of the Pikka project was scheduled for 2025 and a final investment decision was expected by 2024/2025. He asked if it was consistent with expectations a year ago and factored in the high profile dispute between Oil Search and ConocoPhillips in terms of construction easement permits. He asked if the impediment still existed and whether it had influenced the timeline for both phases. Mr. Crowther replied it was DNR's understanding the Pikka project was split from a single phase with a target of 120,000 barrels into two phases partially due to COVID-19 and a difficult period of low oil prices and tight market. The first phase had a peak of 80,000 barrels per day that may receive final investment decision in 2022. There would be a second phase with a subsequent final investment decision in the 2024 timeframe that would take total production to the original target of ~120,000 barrels per day. He relayed that DNR was very aware of the situation and was speaking with both parties about how to resolve the issues and enable development to proceed. He deferred to Commissioner Feige for additional detail. Commissioner Feige added that the Kuparuk River Unit needed to be crossed to access the Pikka field and both developments were state resources under state leases on state lands. The state was very engaged in the process. It was the state's desire to see the two parties come to a commercial agreement, which would be the fastest path. She elaborated it had always been the path that operators in Alaska and other places had been able to travel in sharing access across state lands. She relayed that the Pikka development was the first time on the North Slope where the operator and the owner of the field was not a working interest owner in one of the other fields operating on the North Slope. In the past, when third-party operators had needed access to facilities or needed to cross other producing fields, the parties had been able to come together in a commercial arrangement usually because there was oil processed through a facility or there was sharing of some other facility. In the Pikka case, Oil Search needed to construct its own seawater treatment plant to Oliktok Point, which was the easement dispute referenced by Representative Edgmon. Commissioner Feige explained the new seawater treatment plant was needed because of the chemistry required for water to optimize oil recovery from Pikka. The chemistry of the water coming out of the existing seawater treatment plant owned by ConocoPhillips was not the exact chemistry needed; therefore, Oil Search opted to construct its own plant. It was the department's understanding that ConocoPhillips would need to expand its seawater treatment plant at Oliktok Point for the Willow project. She explained it was not an area where the two companies could share a commercial arrangement. The department was currently working with both parties to encourage a commercial arrangement for a long-term road use agreement because access to the Pikka field required the Spine Road crossing the Kuparuk River field. The department was very engaged and was watching the timelines closely because it was in the state's interest for Pikka to continue on the stated timeline. 2:05:22 PM Representative LeBon thanked the commissioner for the summary. He asked if the state had the authority to mandate a settlement if there was not a settlement of the agreement between the two companies in a timely manner. Commissioner Feige replied in the affirmative. She informed the committee that none of the access provisions in any of the leases or unit agreements were exclusive. The state believed it had statutory provisions that would enable the state to help the companies come to an agreement. The state was hoping the parties came to a commercial arrangement on their own because it would be the shortest timeline. Mr. Umekwe moved on to discuss DNR's forecasting approach. 2:07:13 PM Mr. Umekwe turned to slide 9 and addressed the DNR forecast process including projects and pools within the forecast. He relayed that the forecasting process typically began with the public numbers published by the Alaska Oil and Gas Conservation Commission (AOGCC). He explained DNR looked at the pools online at a given date. He detailed that DNR did projections for pools going into the future using an industry norm. The department collaborated closely with the DOR to discuss projects in detail and get its questions answered. He relayed there were about 20 projects under development, evaluation, and/or review such as Pikka, Willow, and others. The department reviewed the projects and talked with explorers to gain insight into any gaps the department may have in its understanding of the projects. He explained that future production from the projects was adjusted and risked for scope of contribution, chance of occurrence, and start date. He elaborated that typically the expected rate was either exceeded or not met. He pointed out it was difficult to have a forecast that was 100 percent accurate. He stated that the department's approach was consistent over the years. Mr. Umekwe turned to slide 10 and addressed categories of production: ongoing/current vs future production. He began with production from existing fields including Prudhoe Bay, Kuparuk, and others. The department considered how facilities were managed, how base production had been maintained or managed, and the different enhanced oil recovery techniques that had been applied to give a good sense of future production. The department also considered future production including projects under development (planned to occur in the next fiscal year) and under evaluation. He stated projects under evaluation typically had substantial capital requirements and commerciality risk. 2:10:54 PM Mr. Umekwe advanced to slide 11 and addressed major projects considered in the fall 2021 forecast. He provided generalized characteristics. First, the projects included were not online as of the end of FY 21. The projects required significant investment to get started, they involved known discoveries with identifiable operators, and had higher risk factors. He pointed to a map on slide 11 and highlighted that yellow represented federal land, pink reflected Native land, and blue reflected state land. He pointed out that royalties the state took from the different slices of land differed greatly. He elaborated that the state received 100 percent of the royalties from state land, while 50 percent of the royalties from the NPRA area went to a firm handling the mitigation effects of development. He relayed that the state received about 27 percent of the royalties generated from projects located about three to six miles from the northern portion of the state. Mr. Umekwe relayed that all oil that went to the pipeline helped the state in some way. He elaborated that it helped other projects, reduced tariffs, and made other projects more economic. He reiterated that the slice the state received from the various locations differed. He relayed that chapter 6 of the Revenue Sources Book addressed taxes and royalties for different segments of land. 2:13:09 PM Representative Edgmon asked about the optimism level going forward. He referenced the oil price projection of $89 per barrel, which would suggest the tide may be turning toward more capital dollars being allocated to the North Slope. He asked about the outlook relative to oil companies deciding to put money into development. Mr. Crowther answered there were competing factors. He discussed that price drove investment in the sector both nation and worldwide. He remarked that Alaska had been blessed with some new understanding of its geology that made the state comparatively more attractive. There was tremendous potential in the eastern NPRA and western state lands that had not existed five years back. He believed the state had price and geology on its side, which were strong factors supporting investment in Alaska. He highlighted that there were sector-wide energy transition pressures that were making competition for capital - even in a high- price environment - very intense. He stated that the department liked to be optimistic, but the situation tempered the optimism. He shared that the commissioner had been traveling to tell the department's story and explaining why even as the sector-wide squeeze was taking place, Alaska was the place to make low carbon intensity, environmentally friendly, responsibly developed oil and gas. 2:15:40 PM Commissioner Feige believed it was a time of opportunity for state lands on the North Slope. She stated that companies on the NPRA and other federal lands around the country were facing strong headwinds toward any kind of lease activity and development. She elaborated that as there had been during the Obama administration, there was a reinvigorated interest in state lands, especially on the North Slope. She detailed there were large tracks of exploration acreage that had yet to be explored and tested located east of the haul road that were a continuation of the Nanushuk or Brookian play type, which was one of the hottest play types in the world. She shared that department members would attend the upcoming American Petroleum Expo to present and meet with industry. The department heard repeatedly that the Brookian plan or Nanushuk formation was shallow, onshore, and in large volumes. She highlighted that its location on state lands was another positive aspect. Commissioner Feige shared that she and the DOR commissioner had been meeting with capital providers across the country (in Houston and New York) and were highlighting that Environment, Society and Governance (ESG) was not just something new to Alaska. She continued that ESG had become trendy in the past year or so because of the change in the federal administration. She highlighted that the way Alaska leased its lands, captured revenues, and turned the revenues around into the Permanent Fund, into a dividend, and into taxes that went directly to local communities for schools, and new hospitals in Barrow, fell under the ESG box. She stressed that ESG was not a new initiative for Alaska, "it was in the DNA of how we do our business here" and was in Alaska's statutes and constitution. She pointed out that Alaska had anti-wasting statutes that prohibited the venting of natural gas, something that separated Alaska from places like Texas and the Permian Basin or North Dakota and the Bakken where venting of natural gas was commonplace. Commissioner Feige believed Alaska was positioned very well. Alaska faced some headwinds in ensuring it could bring capital to operators that were working and investing in the state. The state was doing its part to ensure the capital was available. While at the same time, the companies were working together to reduce their emissions at existing operations. The companies were making certain they were doing good well work and did not have venting or "fugitive emissions." She summarized there was work to do and the path was not easy, but she believed it was an opportunity and there was reason to be optimistic. 2:19:36 PM Representative Wool referenced testimony that the high [oil] price regime was attractive to investors. He highlighted that when price went up, producers (especially fracking, Permian Basin and other) wanted to produce, which caused supply to increase and price to go down. He stated it was a self-regulating cycle. He asked if the cycle was expected. He asked if there was a price point worked into projections at which there would be less development and production (if the price dropped below a certain number). Mr. Umekwe confirmed that price regulated supply. He explained that production in the U.S. followed high prices. Once supply increased, prices should level off. The expectation was for prices to remain in the $70 range and higher in the current year declining to the high $60 range or so in next year. He emphasized that many factors could change pricing. He referenced the pandemic and noted it was not possible to know what it would bring. He addressed how sensitive projects were to price. He looked at projects on slide 11 and explained that companies all had breakeven prices needed to make the projects happen. He relayed that very low prices would result in few projects, whereas high prices sustained significant activity. He added that the detail was incorporated into DNR's modeling. 2:22:22 PM Mr. Umekwe turned to slide 13 and addressed the Fall 2021 North Slope annualized forecast. The department was forecasting production to around 500,000 barrels per day. Some of the production would come from Cook Inlet and the majority would come from the North Slope. He reported that production was around 493,000 barrels per day in FY 21 and 492,000 barrels per day in FY 22. The department aggregated numbers provided by operators to determine whether the department's long-term numbers fell within the same ballpark. He pointed to a line graph on slide 13 and noted the gray lines reflected DNR's projections (the top line reflected the high case, and the bottom line reflected the low case). The black line reflected the department's expected case, and the blue line reflected the operators' long-term outlook. The department did not aim to have the black and blue lines match up because it would never be the case; however, the goal was to ensure the lines fell within the same ballpark. He pointed to the deviation shown beginning in 2029 going forward and explained that DNR included all 20 or so projects shown on the map [on slide 11], while the operators' information did not include projects that had not yet been brought online. He elaborated that the blue line excluded Pikka, Willow, and other projects under development. 2:25:06 PM Vice-Chair Ortiz asked for more detail on how the department arrived at the black line representing the expected case. Mr. Umekwe replied there was uncertainty surrounding how any project would perform for multiple reasons. For example, an operator may expect 130,000 barrels of oil per day; however, when the project actually happened, the number could be higher or lower. He elaborated the more an operator developed a reservoir, the better they understood it. He furthered there was a high chance the actual production numbers would not match initial projections. He explained that DNR incorporated that possibility in its numbers. He elaborated that for each given project, the department forecasted a range of rates including a mean case and a case where everything an operator anticipated came to fruition. Vice-Chair Ortiz looked at the blue line reflecting operators' projections on slide 13. He understood the line did not include some of the projects included in the DNR projections. He asked if the blue line reflected expectations that the projects would come to fruition and become a part of production in future years. He observed there was a significant difference in the line reflecting the operators' long-term projections versus the department's high case scenario. Mr. Umekwe responded that operators provided numbers for the projects with operational fields. The operators did not include production from future fields such as Willow and Pikka in the data used to generate the blue line. Once the fields were added, the numbers would start to increase. Vice-Chair Ortiz thought it seemed at some point the operators would include the fields in their projections as part of the forecasting process. 2:28:33 PM Representative Wool looked at the DNR expected case reflected by the black line on slide 13. He asked if the black assumed all 20 projects mentioned earlier by the department would come online. Mr. Umekwe answered that the black line expected that some projects would happen, and some would not. The black line averaged across the range of possibilities. Representative Wool asked for verification that the top line showing over 1 million barrels per day assumed the best case scenario. Mr. Umekwe confirmed that the top line reflected the department's optimistic case. He stated the department would provide an updated chart showing production at just under 1 million barrels per day around 2031. The top line showed a case where many of the projects took place and took place on time. Representative Wool surmised it was statistically unlikely. Mr. Umekwe replied that things would have to line up for the scenario to occur. Mr. Umekwe addressed slide 14 showing the fall 2021 statewide oil production forecast including categories of production. He directed attention to a chart and explained that some of the forecasted production came from assets that were already producing (reflected in blue). The rust colored portion of the chart reflected oil expected from wells to be drilled in FY 22. He noted that the rust color had been very small in the last forecast cycle because projections had been much different at the time. The gray portion of the chart reflected early stage projects under evaluation and development. He pointed to the outyears on the chart and noted an increased contribution from those projects. He relayed the chart was based on a snapshot in time based on factors that were subject to change including operators' plans, commercial climate, and the fiscal system. 2:32:19 PM Mr. Umekwe turned to slide 15 and addressed the production forecast summary. He relayed that DNR's work generating the forecast was a collaboration with DOR. The department worked to use the best information to generate the most realistic outlook for the state. He highlighted that DNR's fall 2021 outlook showed production of approximately 500,000 barrels per day in FY 22. Across the outlook period, production was projected to exceed the figure at times and fall below the figure at times. He added that companies' responses to the pandemic, including how they managed fields and what they deployed capital to, could add to the level of uncertainty in the outlook period. He turned to the last slide showing individuals who had worked on the presentation. Co-Chair Foster thanked the department for the presentation. 2:34:03 PM Co-Chair Foster introduced House Finance Committee staff. 2:34:43 PM AT EASE 2:44:33 PM RECONVENED ^Presentation: Fall 2021 Revenue Forecast 2:44:45 PM DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE, drew members' attention to an email notification sent from the Department of Revenue (DOR) earlier in the day. He explained that the department's Economic Research Group did a monthly revenue update for the current and next fiscal year. He detailed that the information was used for internal purposes. He elaborated that if the outlook for unrestricted revenue was more than a 10 percent deviation from the official revenue forecast, the department would begin sending out an email to all interested parties. As of earlier in the day, the updated futures market outlook for FY 22 suggested an oil price of slightly over $80 per barrel compared to $75.72 in the fall forecast. Likewise, the FY 23 outlook was just over $78 per barrel versus $71 per barrel [in the fall forecast]. The difference amounted to an expected additional unrestricted general fund (UGF) revenue of $281 million for FY 22 and an additional $467 million for FY 23. He noted the rest of the information reflected the official fall revenue forecast released in early December. Vice-Chair Ortiz asked if Mr. Stickel had said $400 million for FY 23. Mr. Stickel clarified the updated forecast was about $467 million above the fall forecast for FY 23. 2:48:15 PM Mr. Stickel provided a PowerPoint presentation titled "Fall 2021 Forecast Presentation House Finance Committee," dated January 19, 2022 (copy on file). He began on slide 2 of the presentation and addressed the agenda. The presentation included forecast background, economic indicators, and key assumptions, in addition to the fall 2021 forecast and petroleum forecast assumptions detail. Representative Wool referenced the revenue information Mr. Stickel had provided. He asked for the technical term of the price and how frequently it would change. Mr. Stickel answered that the forecast used for cash flow analysis purposes was based on the futures market for Brent Crude. He explained that Brent Crude was trading any day markets were open. The Economic Research Group looked at the prices once a month to prepare a cash flow update for internal purposes, which would be the basis for the notifications the department would send out going forward. Representative Wool asked if it was a daily price or average over the month. Mr. Stickel answered that the department published a daily price, and the futures market prices were monthly. 2:50:31 PM Mr. Stickel turned to slide 4 and provided background information on the fall revenue forecast, which had been published in December in the annual Revenue Sources Book (RSB). He noted the publication included information on historical and forecasted revenue. He elaborated that DOR gathered data from the tax accounting system, state accounting system, and various state agencies to report actual revenue for the most recent fiscal year. The department maintained models within the Economic Research Group for all of the major revenue sources to generate its 10-year revenue forecast. The RSB fulfilled the statutory requirement that the governor provide a revenue forecast for the current and next fiscal year. The book also provided the revenue information to fulfill the statutory requirement for a long-term fiscal plan out of the Office of Management and Budget. The revenue forecast became the basis for the governor's official budget proposal and was updated in a spring forecast in March or April. In addition to the basic data, the report included detailed narrative about each of the state's revenue sources and forecast variables. He relayed that all of the information was located on the Tax Division's website. 2:51:51 PM Mr. Stickel moved to slide 5 and discussed key Alaska economic indicators reflecting data as of January 12, 2022. He reported that state gross domestic product (GDP) was down slightly in the third quarter; there had been small modest growth since late in 2020. He reported the state GDP was still down 6.3 percent from the similar period in 2019. The data indicated the value of the economy was holding steady, but it was still not back to pre-recession levels. He noted it would be interesting to see what fourth quarter data [to be released in March] looked like with holiday shopping and higher oil prices. He stated that employment was up by 7,200 jobs compared to one year earlier but remained down over 13,000 jobs from the same month in 2019. Jobs were up by 26,000 from the COVID-19 lows in April 2020, but jobs were still down by over 51,000 jobs from pre-pandemic highs in July 2019. The biggest job losses had been in transportation, leisure and hospitality, and oil and gas. The industries had only recovered about half of the losses from the COVID recession. Mr. Stickel continued to address slide 5. Wages and salaries had recovered from pandemic woes, which DOR was attributing to a combination of a strong labor market and some recovery in the employment situation. Bankruptcies and foreclosures were still lower than the pre-pandemic levels. He detailed there had been various government and private industry policies that had helped people avoid bankruptcy and stay in their homes, as well as the strong labor market and extensive stimulus programs. Housing starts had increased from 2020 and would end around pre-pandemic levels at the end of 2021. As of the first quarter of 2021 (the most recent data available), average delinquency rates were lower than the prior year. He explained the low levels were a very good sign. He elaborated that between the strong labor market, strong housing prices, and lenders working with borrowers, there had not been a major uptick in mortgage delinquencies with the recession. 2:55:25 PM Representative Edgmon remarked that all data reflected a snapshot or picture in time. He observed that the numbers would look different were it not for a substantial influx in federal spending. He added that the state was on the cusp of receiving much more federal funding from the federal infrastructure bill. He remarked, "We live in a world of windows these days of pre, current, and post pandemic." He pointed out that the current picture could look much different in the future. Representative Rasmussen noted she had seen in the news recently that the Fed anticipated several rate hikes. She wondered if any analysis had been done on how it may impact the economy in Alaska. Mr. Stickel answered that he had not done any specific analysis on the issue. He pointed out that the current level of federal interest rates was historically extremely low. He reasoned that even if there were several rate increases over the course of the year, rates would be moving towards more of a normalization. 2:57:25 PM Representative Josephson referenced Mr. Stickel's statement that jobs were still down by 51,000 in comparison to pre- pandemic. He remarked that Alaska's population had grown somewhat. He thought some people were moving from a two income to one income household or they were getting by on savings or federal largesse or by some combination. Mr. Stickel speculated that all of the components mentioned by Representative Josephson were part of the story. He deferred to the Department of Labor and Workforce Development for details. Co-Chair Foster noted that Representative Thompson had joined the meeting at the start of the current presentation. 2:58:27 PM Mr. Stickel moved to slide 6 and discussed fall forecast assumptions. He noted that the forecast had been finalized in late November/early December just after the [COVID-19] omicron variant hit the news. He pointed out that COVID-19 was still a source of uncertainty. He explained that the approach DOR had taken with the pandemic was to develop a plausible scenario to forecast the impacts. The forecast assumed a 5.86 percent return for the Permanent Fund for FY 22 and a 6.2 percent return for FY 23 and beyond. The federal revenue forecast had incorporated all of the stimulus funding as of the end of November. The fall forecast included a preliminary estimate for state revenue from the federal Infrastructure Investment and Jobs Act (IIJA). He noted the spring forecast would include a refined estimate. Mr. Stickel continued to address slide 6. The oil revenue forecast was based on a $71 per barrel oil price for FY 23. The department followed the futures market and had prices at $68 per barrel by FY 31. The forecast assumed that underlying economic activity had largely returned to normal with the exception of tourism. The forecast assumed 1.5 million cruise ship passengers annually with a 75 percent adjustment for the summer of FY 22 to reflect uncertainty. 3:00:37 PM Mr. Stickel advanced to an illustration on slide 7 showing relative contributions to total state revenue for FY 21. He detailed that investment earnings, federal revenue, and oil and gas were the biggest sources of state revenue. He highlighted two windfalls in FY 21 including the extremely high returns on investments (the Permanent Fund returned 29.7 percent in FY 21) and significant federal revenues from stimulus packages. He noted that other revenue sources shown on the slide were meaningful and contributed to the economy and made up about 3.5 percent of total state revenue. Co-Chair Merrick asked what federal revenue would be on a normal year. Mr. Stickel answered that federal revenue would likely be similar in terms of magnitude. He noted that investment earnings, federal revenue, and petroleum were the top three [revenue contributors]. He relayed that the information was available in the RSB. Co-Chair Merrick thought the stimulus packages would increase the share of revenue significantly. Mr. Stickel responded that the stimulus packages did significantly increase federal revenue; however, in terms of the share of total revenue, the federal share was likely in line with historical numbers when factoring in the extremely large investment earnings. Representative Wool estimated the total federal money for the pandemic may have totaled $5 billion to $6 billion. He referenced the investment earnings and asked if it was the percent of market value (POMV) draw that went into state revenue or the total revenue inclusive of the Permanent Fund's total earnings. 3:03:37 PM Mr. Stickel answered that total state revenue on slide 7 included the full return of the Permanent Fund, which was nearly 30 percent for the year. The presentation would address unrestricted revenue later on, which only included the POMV draw. Mr. Stickel turned to slide 9 and discussed the total state revenue from all sources for FY 21 and the forecast for FY 22 and FY 23. He highlighted that total state revenue came from four broad sources including investment revenue, federal receipts, petroleum revenue, and non-petroleum revenues. He noted that revenues were further broken down into four categories of restriction in the forecast and budget documents. He began with UGF, revenues that could be appropriated for any purpose and most commonly discussed in budget discussions. Designated general funds (DGF) were technically available for appropriation but were customarily appropriated for a specific purpose. For example, half of the revenue from the state's alcohol tax was customarily appropriated to the alcohol and other drug abuse treatment and prevention fund. The use of the "other restricted revenues" category was dedicated for a specific use and generally the use of the funds was restricted. He highlighted examples including the constitutional dedication of royalty revenue to the Permanent Fund and school fund or motor fuel tax revenue that had to be used for a specific purpose for aviation per federal law. Mr. Stickel listed federal revenue as the fourth funding category on slide 9. He relayed that federal revenues had certain caveats around the way they had to be used and were shown as restricted revenue in the DOR forecast. He noted that sometimes designated, other, and federal funds were lumped together into a single category of restricted revenue. In FY 21, total state revenue from all sources was about $29.8 billion. The department was forecasting total revenue at $13.4 billion for FY 22 and $14.6 billion for FY 23. The UGF portion of the total was $4.8 billion in FY 21 and forecasted to be $5.7 billion in FY 22 and $5.9 billion in FY 23. He highlighted two columns on the right showing the percentage change from FY 21 to FY 23 and FY 22 to FY 23 in the forecast. Representative Josephson looked at FY 21 investment revenue of $16 billion [under the other restricted revenue category on slide 9] and asked why the number went to $1.4 billion in FY 22. Mr. Stickel replied that the primary reason for the difference was Permanent Fund earnings above and beyond the POMV draw. The POMV draw was considered as unrestricted general fund revenue and any additional earnings above the draw were counted as restricted revenue. He explained the $16.2 billion reflected the strong return of the Permanent Fund above and beyond the POMV draw. Representative Josephson surmised the $16.2 billion reflected that until July 1, 2021, the corpus of the Permanent Fund was generating more revenue than ever seen. He surmised DOR was expecting much less revenue in the current and following fiscal year. He stated his understanding that DOR believed the stock market could not sustain the growth seen in the last year. 3:08:58 PM Mr. Stickel answered that the Permanent Fund return was extremely high at just shy of 31 percent in FY 21. Callan Associates, the state's investment consultant, was projecting more modest returns going forward. The department was expecting a 5.8 percent total return on the Permanent Fund in FY 22 and 6.2 percent annual return for FY 23 and beyond. Representative Josephson stated that in a way it was not a surprise, but in another way, it was an enormous statement. He observed it was certainly the largest item on the table in terms of the delta from year-to-year. 3:10:11 PM Mr. Stickel turned to slide 10 and indicated the remainder of the presentation would focus primarily on the UGF revenue forecast because it had the most flexibility and discretion in the budget process. He communicated that investment revenue had become the largest source of unrestricted revenue for the state by far. The primary component was the POMV transfer from the Permanent Fund. He reported that investment revenue had contributed just over $3.1 billion in FY 21 and was estimated to contribute $3.1 billion in FY 22 and nearly $3.4 billion in FY 23. Petroleum revenue generated about $1.2 billion in FY 21 and was estimated to contribute $2.3 billion in FY 22 and $2.1 billion in FY 23. The non-petroleum revenue sources were estimated to contribute about $375 million in FY 22 and about $476 million in FY 23. Representative Wool asked why investment revenue was going down in FY 22. He asked if there was a negative year in the five-year averaging. Mr. Stickel replied that the POMV transfer was based on the average value of the first five of the last six fiscal years. Per statute, the FY 21 transfer had been 5.25 percent of the five year average and 5 percent for FY 22 going forward. He turned to slide 11 showing a summary of key changes to the unrestricted revenue forecast between the spring FY 21 and fall FY 21 forecast. The department's oil price forecast had increased by $14.72 per barrel to $75.72 for FY 22 and by $9.00 per barrel to $71.00 in FY 23. The increase was due to some of the stabilization and recovery in the oil markets as the economy continued to recover from the COVID-19 recession. Mr. Stickel continued to address slide 11. There was no change for the FY 22 projection for the Permanent Fund transfer. He explained it had to do with the transfer being based on the first five of the last six years. Based on strong returns, the Permanent Fund transfer estimate was increased by about $154 million for FY 23. For total unrestricted revenue, FY 21 came in about $120 million higher than expected in the spring forecast. The forecast had increased by about $1 billion for FY 22 versus the spring and by slightly over $800 million for FY 23. He noted that the figures did not reflect new information released by the department earlier in the day. 3:13:44 PM Mr. Stickel shared that next set of slides would provide more detail on the sources of unrestricted revenue. He began with investments on slide 12. He highlighted that the Permanent Fund transfer was expected to account for between half and two-thirds of UGF revenue for each year in the 10- year revenue forecast. He noted it really spoke to the importance of the Permanent Fund as an asset for the state and a major source of state revenue. The transfer had been about $3.1 billion in FY 21 and was expected to contribute a similar amount in FY 22 and about $3.4 billion in FY 23. There was also a small amount of other investment revenue, which primarily represented earnings on cash balances in the General Fund. Mr. Stickel advanced to slide 13 showing the estimated transfer from the Permanent Fund to the General Fund for the next ten years. The forecast estimated the transfer would increase to $4.6 billion by FY 31. He highlighted that the forecast was based on a long-term return assumption of 6.2 percent and a 5 percent of market value transfer to the General Fund annually. He stated that the Permanent Fund was a stable and growing revenue source with much of the stability coming from the trailing five-year average used in the calculation for transfer to the General Fund. Representative Edgmon referenced Mr. Stickel's previous statement that the Permanent Fund earnings could account for one-half to two-thirds of UGF. He asked if the range of one-half to two-thirds was primarily related to the volatility of oil revenue. He remarked that the Permanent Fund was growing over time, but the earnings would come down from the 30 percent returns in the past year. Mr. Stickel responded there were several variables involved. First, oil prices were expected to moderate over the coming years. Once the strong returns from the Permanent Fund were fully baked into the revenue forecast, DOR was expecting the transfer amount to increase. The estimate of one-half to two-thirds was intended to give an order of magnitude to illustrate the importance of the Permanent Fund. Representative Edgmon stated that all things considered, as long as the POMV draw was adhered to, the Permanent Fund was not really the source of the one-half to two-thirds fluctuations in other sources of revenue. He asked for the accuracy of his statement. Mr. Stickel answered it was a combination of Permanent Fund and oil revenue. For example, the department was expecting unrestricted petroleum revenue of $2.3 billion in FY 22, but the amount was expected to drop below $2 billion in future years, while at the same time there were expected increases for the Permanent Fund. He stated it was a combination of the two different revenue sources. All of the detail behind the calculations was included on page 11 of the RSB and factored in the 10-year revenue forecast for investment revenue, petroleum revenue, and non-petroleum revenue. 3:18:38 PM Representative Edgmon remarked that he had been on the committee long enough to remember when Permanent Fund earnings were nowhere near one-half to two-thirds of total UGF. He observed that things seemed to be changing quickly. He underlined the importance of the revenue stream from the Permanent Fund. He referenced the historic nature of revenue in the state and pointed out that Permanent Fund earnings were fairly steady. He stated the fund should be something the state could count on in perpetuity. He considered that oil had been the state's other source of mostly permanent revenue and noted it was holding its own but was nowhere near what it had been in the past. Representative Josephson was struck by the anticipated $4.6 billion draw in ten years. He commented it was a short period of time. He asked if it meant the department believed the total value of the fund would be $95 billion in 10 years. Mr. Stickel answered that he did not have the information on hand, but the number provided by Representative Josephson sounded in the ballpark. The department was forecasting the value of the Permanent Fund would continue to increase given the expectation of a 6.2 percent annual return and the trailing 5 percent draw, in addition to oil and gas and other mineral royalties. 3:20:49 PM Mr. Stickel turned to unrestricted petroleum revenue on slide 14. He relayed there were four main sources of petroleum revenue including property tax, corporate income tax, production tax, and royalties. He detailed that the state levied a property tax on all oil and gas property in the state as a fairly stable revenue source generating a little over $100 million per year in state revenue. He pointed out the number only reflected the state's share. There was additional revenue exceeding $400 million per year in property tax that went to municipalities annually. The state levied a corporate income tax on qualifying corporations doing business in the state. He noted the tax was on profits and because the recession was very difficult on the oil and gas industry, there had been net refunds paid out in FY 21. Based on the improved environment in the petroleum industry, the department was forecasting $145 million of corporate revenue in FY 22 and $240 million in FY 23. Mr. Stickel highlighted there had been a provision of the federal Coronavirus Aid, Relief, and Economic Security (CARES) Act that allowed corporations to carry back net operating losses for tax years 2018 through 2020 and corporations could receive refunds for certain previous taxes paid. He explained that Alaska's corporate income tax statute adopted the federal tax code by reference; therefore, the net operating loss provision had been automatically adopted into Alaska's tax. The estimated impact of the carry back refunds was about $2.4 million in FY 21 and just under $50 million in FY 22. Representative Wool stated that the legislature had heard about the carry backward tax the previous year and it had never been fixed. He asked for verification the situation meant the state had to write a check for the aforementioned amount. Mr. Stickel agreed. He confirmed the provision had remained in law and some companies were requesting refunds. Companies could request a refund check or could apply the amount in lieu of additional tax payments. The state was starting to see the refund requests come to fruition. Representative Wool asked for verification Mr. Stickel had stated the amount was $50 million for FY 22. Mr. Stickel answered that the department was estimating the refund impact to be $2.4 million in FY 21 and $49.6 million in FY 22. He noted there were some modest offsetting positive impacts in future years. 3:24:20 PM Mr. Stickel continued with slide 14. He discussed the oil and gas production tax, the state's severance tax on petroleum. For the North Slope, the tax consisted of a net profits tax with a gross minimum tax floor. Given the current oil price regime, the forecast anticipated most companies would be paying above the minimum tax throughout the forecast time horizon. The production tax was expected to bring in just under $1 billion in FY 22 and about $740 million for FY 23. Royalties were the largest source of unrestricted petroleum revenue and brought in about $729 million in FY 21 and were expected to bring in about $1 billion in FY 22 and FY 23. He noted the royalty was limited to the state's General Fund share. The table did not reflect additional royalty revenue going to the Permanent Fund and school fund. Mr. Stickel advanced to slide 15 and discussed unrestricted non-petroleum revenue for FY 21 to FY 23. The largest source of non-petroleum revenue was taxes. He stated that typically, corporate income tax was the largest non- petroleum tax type. The tax generated a little over $100 million in FY 21. He relayed that CARES Act related refunds and some of the economic difficulties impacted non- petroleum tax to the tune of $6.7 million, which was included in the FY 21 number. The department estimated about $76.7 million in FY 22. He noted the amount was imbedded in the $15 million [shown in the first row of the FY 22 column on slide 15]. Other significant taxes included mining license tax, insurance premium tax, fisheries taxes, and excise taxes. He pointed to the "other" category at the bottom of the slide, which included all other non-petroleum revenues such as licenses; permits; charges for services; minerals, rents, and royalties; and miscellaneous revenues such as state corporation transfers and dividends. In total the department was expecting non-petroleum revenue of about $375 million for FY 22 and $476 million in FY 23. Representative Josephson asked if the refined fuel surcharge amount [on slide 15] involved the sweep. Mr. Stickel answered that beginning with the FY 22 forecast, the department was showing the refined fuel surcharge as DGF. He explained the change had been made in consultation with the Legislative Finance Division (LFD) and the Office of Management and Budget (OMB) to match the way the information was shown in budget documents. He clarified the revenue source itself did not go away. The department was merely switching the way it was shown in the revenue forecast. Representative Wool asked why there was a significant increase in mining tax. 3:27:52 PM Mr. Stickel answered that the $9 million in mining license tax in FY 21 was an aberration due to low minerals prices and some difficulties with the COVID recession had impacted the mining industry, just like many other industries. The increase to nearly $50 million in FY 22 and FY 23 was a recovery to historical average levels. Representative Josephson noted that mining produced fantastic well-paying jobs but brought in little for the state. Compared to oil and gas, the revenue was low and unimpactful. He thought it was important to think about the issue for the future. 3:29:19 PM Mr. Stickel turned to slide 17 and provided petroleum detail and changes to the long-term price forecast. The slide showed the fall 2021 oil forecast for North Slope crude in comparison to the spring forecast. The department had made a change to the way it forecast oil prices in the fall forecast. Previously, DOR had looked at the futures market for two years and applied an inflation adjustment. The change in the fall forecast used futures market data for as many years as were available. He explained that the fall forecast used futures market data through FY 29. The change had been made to provide a more accurate projection of oil prices and to allow policymakers to focus on policy discussions instead of whether the forecast was correct or not. Mr. Stickel relayed that the department's Economic Research Group had prepared an analysis of historical prices and futures market projections and what would have happened had the forecast used additional years of futures markets. He explained the analysis made a compelling case that using more data from the markets provided a better forecast. The group had presented the findings internally and subsequently to LFD and OMB. He shared that all parties agreed the change would provide a more forthcoming and accurate revenue forecast. The price forecast on slide 17 had been generated on December 9 using futures market data at the time. The calculation resulted in an FY 23 oil forecast of about $71 per barrel, which was $9 higher than the spring forecast. The slide showed moderate declines in price with prices stabilizing in the mid to upper $60s. 3:31:46 PM Representative Rasmussen asked if there would be time to ask LFD Director Alexei Painter questions on the updated forecast. Co-Chair Foster stated his understanding of the question. Representative Rasmussen relayed she was interested in hearing from Mr. Painter on the updated forecast and new modeling highlighted by Mr. Stickel. Co-Chair Foster believed Mr. Painter would be presenting to the committee on Friday and there would be an opportunity to ask the questions then. Representative Wool looked at the dotted red line reflecting the spring forecast compared to the dotted blue line reflecting the fall forecast [on slide 17]. He stated his understanding that both lines included futures market data through FY 29. He asked why there was a difference between the two forecasts. Mr. Stickel answered that the futures market had been in a state of "backwardation" for some time. He explained it meant the futures market was expecting oil prices would show modest declines over the next several years. When the department prepared the spring forecast, it used the futures market to inform its FY 22 forecast and had applied an inflation adjustment beyond FY 22. He elaborated the department had assumed there would be modest increases in price after FY 22. Whereas the fall forecast used as many years as were available in the futures market for the fall forecast. He explained that DOR had incorporated the backwardation in the market through FY 29. Representative Wool stated his understanding the department had changed its modeling methodology between the spring and fall forecasts. Mr. Stickel answered in the affirmative. Representative Wool wondered if the futures market indicated the locked price a person could buy or sell oil for out through FY 27 or FY 29. Mr. Stickel agreed. He explained it was the price for oil in the future if someone wanted to trade the oil at present. 3:35:10 PM Mr. Stickel turned to slide 18 showing how the department's petroleum price forecast compared to other forecast sources. The department's forecast compared to Brent forecasts from the Energy Information Agency from current futures markets as of January 11, 2022, and from an average of analyst forecasts. He explained the department compared the ANS forecast to Brent because Brent was a global benchmark crude, which competed with ANS and typically priced at a very similar level. He highlighted the department's forecast was in the range of the other forecasts. He remarked that oil prices had increased over the last several weeks. He detailed the department's forecast was on the lower side for the next two years, but it moved back in the range of other forecasts after that time. He added that the difference in the next couple of years had been the justification for starting to provide monthly revenue updates. Mr. Stickel moved to a chart on slide 19 showing how revenue for FY 23 would change with different oil prices. He detailed that at the forecasted price of $71 per barrel, the estimated unrestricted revenue excluding the Permanent Fund transfer was about $2.6 billion. He explained that each $1 increase above the forecasted price would lead to a $60 million to $65 million change in the revenue forecast. Mr. Stickel provided a recap of information presented earlier by the Department of Natural Resources (DNR). The slide showed the 10-year outlook for oil production from the North Slope in addition to the high and low cases. In general, there was stable to slightly increasing oil production expected. He highlighted that the official production forecast was a reference case within a range of potential outcomes and production could be higher or lower than forecasts shown. 3:38:33 PM Vice-Chair Ortiz asked if slide 20 was an exact replica of information provided earlier by DNR. Alternatively, he wondered if the information was adjusted based on DOR input. Mr. Stickel answered that DOR incorporated additional months of actual production into the DNR information. The DOR forecast incorporated actual production through the end of November into the FY 22 number. Mr. Stickel addressed a chart on slide 21 showing a comparison of the fall production forecast to the spring production forecast. Over the near-term, the fall forecast increased above the spring forecast primarily due to increased drilling and activity at the major fields. In the long-term, there had been some reductions compared to the spring forecast given the increased uncertainty around legal and Arctic financing issues. Mr. Stickel discussed a chart on slide 22 showing the state's allowable lease expenditures on the North Slope, including how the numbers had changed over the past decade and the 10-year forecast. He noted the chart factored in average oil and gas employment and indicated a strong correlation between company spending and employment. The allowable lease expenditures were important in the production tax calculation because they were deductible from the net production tax. Company spending was also a very important measure of current and planned investment in Alaska. Mr. Stickel explained that the forecast on slide 22 related to a question asked earlier by Representative Edgmon about expectations for future spending. He detailed that in FY 21 the oil and gas industry had been hit hard by the COVID-19 situation. He elaborated that capital expenditures were about $1.5 billion and operating expenditures were about $2.4 billion, which reflected at $2.7 billion decrease year-over-year in company investment in the North Slope. The department was forecasting a rebound for FY 22 and FY 23. He expounded that as companies started to invest in major new developments like Pikka and Willow and resumed drilling at existing fields, capital expenditures would increase and stabilize at a little over $2 billion per year. On the operating expenditure side, it was expected that some of the cuts made over the last year would be permanent as companies adopted cost saving measures. Additionally, there were small increases in operating costs expected in several years associated with bringing new fields online. 3:42:00 PM Representative Josephson stated that pursuant to HB 111, non-producers baring wholly allowable expenses were required to come into production by a given number of years or they would lose the opportunity to deduct the expenses. He asked if his statement was correct. Mr. Stickel answered that companies currently in production were allowed to deduct allowable lease expenditures against the value of the oil they sold when calculating their net profits. He explained that a company was in a loss situation (whether it was a current producer with insufficient revenue or a new company developing a new field), any of the lease expenditures not applied in the production tax calculation would become a carried forward lease expenditure. There was a provision in statute that the carried forward expenditures decreased in value thth beginning in the 8 or 11 year after they were earned. Representative Josephson stated that if a person was just beginning a new lease hold and exploration work in 2022, they had to have confidence they would begin to produce oil by 2029 or the deductions would be lost over time. He asked if he was accurate. Mr. Stickel confirmed the provisions around the carried forward lease expenditures would be part of a company's investment decision making process. 3:44:19 PM Mr. Stickel stated that slide 23 showed a history and forecast of North Slope transportation costs (also known as netback costs). He explained the costs reduced the value of oil for tax and royalty purposes. Transportation costs included getting oil to market including the Trans-Alaska Pipeline System (TAPS) tariff, marine costs, and other smaller items such as feeder pipeline tariffs. In FY 21, the average transportation cost for North Slope oil was $9.19 barrel. The forecast was for $9.70 in FY 22 and $9.09 in FY 23. The department was expecting transportation costs would remain just under $10 per barrel throughout the ten- year forecast, given that any higher costs of transportation were generally offset by increasing oil production and throughput. Representative Wool asked why the costs in FY 19 and FY 20 were particularly low. Mr. Stickel replied that the three primary components were broken out. He explained that in FY 19 and FY 20 there had been some changes to the way the TAPS pipeline tariff was calculated that reduced tariffs. He elaborated that a new settlement methodology had been incorporated. Additionally, fuel was a major component in marine costs, which had been impacted by lower oil prices. 3:46:31 PM Mr. Stickel turned to slide 24 and discussed tax credits for purchase. He explained that prior to 2016 there had been various tax credits in state statute that could be applied against tax liability or turned into a tax credit certificate. He detailed that the state could then purchase the tax credits at face value. Changes made by the legislature in 2016 and 2017 implemented sunset provisions for all of the tax credits; therefore, there were no new credits being earned. He highlighted there was still a large outstanding balance of the tax credit certificates for activity performed prior to the sunsets. There was a formula in statute suggesting an annual appropriation for state purchase of the tax credits. He explained the formula was based on either 10 percent or 15 percent of estimated production tax levy before subtracting credits. Prior to 2016, the full amount of eligible tax credits was purchased by the state annually. Beginning in 2016, less than the full amount was purchased by the state. In FY 20 and FY 21, no appropriation was made, and a $54 million appropriation was made in FY 22, which was still below the statutory appropriation. Mr. Stickel stated that under the fall revenue forecast the statutory appropriation would be $199 million for FY 23. Slide 24 showed an estimated $587 million in outstanding tax credits available for state purchase at the end of FY 22. He explained that if the legislature were to make the statutory appropriation per the fall forecast, the entire balance of the certificates would be retired by FY 26. Representative Josephson asked if the FY 23 budget request was $199 million. Mr. Stickel believed Representative Josephson was correct that $199 million was the statutory appropriation. Mr. Stickel indicated there was one slide remaining that the Tax Division director would review. COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE (via teleconference), spoke to slide 26 related to an oil and gas production tax audit update. She relayed that DOR was still working to catch up and would like to be on a three-year audit cycle. She relayed that all of the division's other tax programs were on a three-year audit cycle in statute. She explained that oil and gas production tax was an outlier and there was a six-year statute of limitations for the audits. In the past, the department had been at the late date of getting the audits completed. She reiterated the division was working to catch up and get on a three-year cycle. She reported that the progress had slipped a bit from the previous year, but she believed the work was still on track. She relayed departures in personnel had contributed to the delay. She believed the division was in the same situation as many employers across the nation and it was struggling to recruit new employees. She noted that the division's teams were small and even several vacancies hindered its ability to get work done. 3:50:56 PM Ms. Glover continued to speak to slide 26. She referenced how COVID had resulted in the state embracing telework. She lauded the oil and gas production audit team for being the leading team on embracing technology. She remarked that the team had used little paper prior to COVID; therefore, teleworking had not hindered the ability to get audits done. The division continued to try to leverage its technology and used [Microsoft] Teams meetings to stay connected. She noted that audits were done by teams, not individual people. The division had been working to have consistency in its audits. She highlighted improvements made by a risk-based approach. She detailed that instead of doing labor intensive audits that may not generate significant findings, the division looked at past audits and high risk areas to perform targeted audits in order to leverage its resources. She summarized that work had slipped by one or two quarters, but she believed the division was on track to be on the three-year cycle by the time it completed its 2018 and 2019 audits in 2023. Representative Josephson looked at the petroleum revenue projection of $2.082 billion in FY 23 on slide 10. He asked if the money was paid from the producers and uncontested. Alternatively, he asked if some of the funding was possibly litigated. Ms. Glover answered that the unrestricted revenue shown under the production tax revenue reflected monthly estimated payments. She clarified the data did not include any settlements or litigation amounts. Representative Wool asked if it was fair to say that many of the audits would end up being settled for less than the face value. Ms. Glover replied that every audit and result was different. She would not say audits were typically settled or negotiated for less. There were audits that got litigated all the way up to the supreme court. Much of it related to the state's confidence in its ability to litigate and how strong the Department of Law's opinion was. 3:55:26 PM Co-Chair Merrick thought a couple of tax auditors had been added the last year. She asked if it was within the DOR budget. Ms. Glover answered that the two corporate income tax auditor positions had not been included in the final FY 22 budget. Co-Chair Merrick reviewed the schedule for the following day. ADJOURNMENT 3:56:24 PM The meeting was adjourned at 3:56 p.m.
|HFIN Fall 2021 Revenue Forecast Presentation 2022.01.19.pdf||
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|DNR Fall 2021 Production Forecast_House.pdf||
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|DNR Production Forecast_HFIN_Replacement slide 011922.pdf||
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