Legislature(2019 - 2020)ADAMS ROOM 519
04/16/2019 01:30 PM FINANCE
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|Presentation: Spring 2019 Revenue Forecast|
* first hearing in first committee of referral
= bill was previously heard/scheduled
= bill was previously heard/scheduled
HOUSE FINANCE COMMITTEE April 16, 2019 1:30 p.m. 1:30:15 PM CALL TO ORDER Co-Chair Foster called the House Finance Committee meeting to order at 1:30 p.m. MEMBERS PRESENT Representative Neal Foster, Co-Chair Representative Tammie Wilson, Co-Chair Representative Jennifer Johnston, Vice-Chair Representative Dan Ortiz, Vice-Chair Representative Ben Carpenter Representative Andy Josephson Representative Gary Knopp Representative Bart LeBon Representative Kelly Merrick Representative Colleen Sullivan-Leonard Representative Cathy Tilton MEMBERS ABSENT None ALSO PRESENT Bruce Tangeman, Commissioner, Department of Revenue; Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue; Ed King, Chief Economist, Office of Management and Budget; Colleen Glover, Tax Director, Department of Revenue. PRESENT VIA TELECONFERENCE None SUMMARY SB 25 EXTEND BOARD OF DENTAL EXAMINERS SB 25 was SCHEDULED but not HEARD. PRESENTATION: SPRING 2019 REVENUE FORECAST Co-Chair Foster reviewed the meeting agenda. Co-Chair Wilson relayed the agenda for the afternoon meeting. ^PRESENTATION: SPRING 2019 REVENUE FORECAST 1:30:40 PM BRUCE TANGEMAN, COMMISSIONER, DEPARTMENT OF REVENUE, introduced the PowerPoint presentation: "Spring 2019 Revenue Forecast Update." He wanted to have Dan Stickel and Ed King to the table for back-up. Commissioner Tangeman turned to slide 2: "Overview." The presentation was an update to the fall forecast. The fall forecast was more robust and took several months to put together. He noted that the publication put out by the Department of Revenue (DOR) each year [The Revenue Sources Book] was a good resource for legislators to refer to. The presentation would not be as substantial as the department's fall forecast presentation. He would touch on the revenue forecast and the changes to it. The presentation would also cover the ANS oil price forecast, the oil production forecast, the North Slope lease expenditures forecast, and the oil credits forecast and tax credit bonding update. Commissioner Tangeman continued that in the fall forecast for FY 19 the department was forecasting just under $68 per barrel. In the spring forecast which was released on March 15, 2019, the department was estimating just under $69 per barrel. As of the previous Friday, the actual year-to-date price of oil was almost $70 per barrel - a month later the price of oil was out-pacing the spring forecast by about $1 per barrel. In the current price range $1 equated to about $70 million of the state's bottom line. He thought it reflected an uptick in oil prices. Although the state was not going to rely on oil prices to fix its financial woes, it was positive to see the increase. He reported that the average for the month of March was about $68 per barrel and the average for April at the current mid-point of the month was about $71.50 per barrel. The state was seeing some healthier prices for oil as it closed out the fiscal year. He hoped the price would stay at current levels. Commissioner Tangeman indicated that on the production side, the state was at about 100,000 barrels per day. The fall forecast reflected 526 and the spring forecast was 511. The state was about 2.5 percent under pace compared to the spring forecast. Commissioner Tangeman advanced to slide 4 which compared the Fall 2018 forecast to the Spring 2019 forecast. He pointed to the unrestricted general fund (UGF) petroleum revenue at the top without significant changes. The second section showed the UGF non-petroleum revenue. The total UGF revenue for FY 19 in the third section reflected a deficit of $90 million. He reminded members that the price was about $1 per barrel over the forecast which almost closed the gap. The department was forecasting a $40 million surplus for 2020. The last section at the bottom of the slide was the Permanent Fund transfer that the department pulled out of UGF to show as a separate line item. It had not changed much from fall to spring. Commissioner Tangeman would have Mr. Stickel walk the committee through some of the details of the changes from the previous slide. 1:35:12 PM DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE, explained that slide 5 walked through some of the key changes from the fall forecast to the spring forecast for FY 19 and FY 20. He conveyed that for FY 19 the department reduced the UGF revenue forecast by $89 million. The main component of the reduction was related to the oil and gas production tax. Higher oil prices would have increased the forecast by $25 million but was more than offset by some impacts that moved production tax in the other direction. He offered that the state had lower than expected cash payments from refiled tax returns related to some amended terra filings for the Trans Alaskan pipeline. He referred to them as Federal Energy Regulatory Commission (FERC) payments. The state had unexpected refunds for the calendar year 2018 and some other company-specific items. Altogether they reduced production tax by about $105 million for a net impact of an $80 million reduction. The state also had lower than expected income tax payments in the last quarter of 2018 which reduced the state's non-petroleum corporate forecast by $15 million. The state also had some miscellaneous revenues that were reduced by $2 million and an increase to the royalty forecast of $8 million based on the higher oil price forecast. Adding up the 4 items he highlighted equaled $89 million in reductions for FY 19. Mr. Stickel suggested that looking at FY 20 the department increased the forecast by $39 million. Production tax was the largest piece increasing by $45 million. Royalties were increased by $19 million. Both were offset by non-petroleum corporate income tax and some other miscellaneous non-petroleum revenues that pulled the revenue forecast in the other direction to get to the net $39 million increase. Representative Knopp asked for clarification about the revenue flow and whether it was based on the fiscal year or calendar year. Commissioner Tangeman clarified that the forecast was on a fiscal year basis. Vice-Chair Johnston noted that in Commissioner Tangeman's opening remarks he mentioned $71.50 per barrel and the ratio of $70 million for every $1 - which filled the deficit gap of $89 million. She was looking at the previous slide. She wondered if his statement held true looking at the extra revenue from higher prices. Commissioner Tangeman explained that the $71.50 per barrel price was the average in April thus far. Year-to-date the average was just about $70 per barrel. He furthered that the current forecast being reviewed was based on a forecast of $69 per barrel. The forecast was a month old and had already increased by about $1. He suggested that if oil prices stayed steady at $70 the state would realize about $70 million more. The state was showing a deficit of about $89 million. It would make up a big difference. Representative Carpenter was looking at the UGF non- petroleum revenue on slide 4, the projection was negative numbers continuing out to FY 28. He thought it reflected a continuation of a recession of some sort that was less than economic growth in the non-petroleum economy. He asked if he was accurate. Mr. Stickel responded that the reduction in the non- petroleum revenue forecast primarily had to do with an expectation of lower mineral prices. The department had reduced the non-petroleum corporate income tax forecast. The primary weakness was in the mining sector. The state had also reduced its forecast for mining license tax which was the severance tax on the mining industry. He reiterated that there was not a projection of lower activity in the industry. It was simply lower profitability due to the price forecast used. He would be turning the presentation over to Mr. King to address the following few slides on the oil price forecast. 1:40:47 PM ED KING, CHIEF ECONOMIST, OFFICE OF MANAGEMENT AND BUDGET, reviewed slide 7: "Price Forecast Summary." The slide showed a time series of the price forecast for the following 10 years starting in the current fiscal year and moving out to FY 28. He highlighted that only the first two years showed a change which reflected the fact that when DOR was putting the spring forecast together there was a recognition that current prices were exceeding the fall forecast. The department used the actual futures market price for the rest of FY 19 and a rounded number for FY 20. He concurred with the commissioner that since the March 15th release of the spring forecast, prices had been consistently higher. Oil prices were closing just under $72 per barrel at present. As the department moved forward and prices continued to increase the FY 19 number increased. It was difficult to tell whether the factors currently pushing up prices would hold and encourage a change in the following fiscal year or 10 years from now. It did not make sense to change the longer-term forecasts. Co-Chair Wilson asked how long the price increase had to stay static before the forecast was adjusted again. Commissioner Tangeman responded that the department only put out the forecast twice per year, once in the fall and again in the spring. Co-Chair Wilson asked if it was normal to only do the forecast for 2 years. Commissioner Tangeman replied that the department made a change to FY 20 because the numbers he was seeing in the range between $6 to $70 range were very accurate. The department was using half a year of actual oil prices. Dropping down to $64 did not seem realistic which was why the department brought the amount up to $66 and continued out with the previous fall forecast. The department was not seeing anything to justify making changes in years 3 through 10. Representative LeBon returned to slide 4. He wondered if the UGF non-petroleum revenue numbers included the elimination of the petroleum property tax share. Commissioner Tangeman responded in the negative. The forecast did not take into account any legislation in play. Vice-Chair Ortiz asked about the reasons for the bump in the month. Mr. King responded that what had been happening in the previous 30 days had much to do with what was going on in Venezuela. Venezuela was experiencing civil unrest, certain sanctions were applied, and there were some power outages that disrupted production of about 500,000 barrels per day. Currently, there were also sanctions on Iranian production. He reported that 6 countries had waivers. The waivers expired in the following month and there was some uncertainty about whether they would be extended. The uncertainty was driving some of the risk of price as well. Also, there was civil unrest in Libya threatening oil production, although it had not caused any disruptions thus far. The risk of disruption was driving the price up. The same thing to a lesser extent was happening in Nigeria. He continued that with Saudi Arabia and Russia both committing to cut production to hold prices up in the $70 target range, it had helped significantly with the price being above the $60 to $65 range that the market would otherwise support. The geopolitical factors and the intentional supply cuts were pushing up on prices. Mr. King noted some disruption in the mid-continent with shale production. There were some problems with cargo deliveries being rejected because the sulfur content was too high. Also, some capital investors were having a difficult time finding capital. However, now that the prices had been up higher, he starting to see the rig count increase. Presently, over the current week he had seen a flat line. Over the previous 2 weeks he had seen a steady increase in the price. It was starting to stabilize. As soon as the uncertainties were resolved, he would expect the prices to drop back down again. The department would not want what was going on in the current environment to influence the department's projections in the following year or 10 years into the future. 1:46:39 PM Representative Knopp asked if the department followed things such as Rampco going public or the Chevron and Anadarko merger. He wondered if fluctuations were included in the department projections. Mr. King responded that he monitored the news. However, the department did not have a price model to inject changes into. They were factors he was paying attention to and trying to understand. However, in the long-term the department focused on supply and demand. He noted that in the near-term price forecasting the focus was more on geopolitics, mergers and acquisitions, and access to capital. He paid attention to certain things that were not actually modeled. Vice-Chair Ortiz asked if Commissioner Tangeman would be talking about the production forecast. Commissioner Tangeman indicated they only touched on the issue on one slide. It was mostly a Department of Natural Resources (DNR) issue. Vice-Chair Ortiz asked if global warming would interfere with the production season and production. Mr. King indicated that the legacy fields such as Prudhoe Bay and Kuparuk did not use ice roads. The ice road season would not impact their production as much as it would for exploration activity. He continued that whenever there was not a permanent road for moving out West or East, a short ice road season would mean a shorter production window. In other words, it would take longer to get facilities into production which meant it would cost more. In terms of production inside Prudhoe Bay, it was true that the production facilities worked more efficiently when it was colder. However, it did not necessarily mean there would be a reduction in production. It meant that it would take more effort to produce the same amount of oil. Mr. King had already talked to all of the points on slide 8. 1:50:23 PM Mr. King moved to slide 9: "Potential Macroeconomic and Global Drivers of Price Change." One of the large factors that people were paying attention to was global demand and the long-term projections of global demand. There were concerns around global trade. He suggested there would be a call for a change in demand forecast. It was currently holding prices down slightly. If trade conversations resolved, he would expect that prices would increase as the demand forecast increased. There were also many conversations going on about whether the current growth pattern was sustainable globally and whether it would flatten out or correct. If it did, he expected prices would fall in line. China and other trade partners and what was going on in the European Region were very important to the future direction of prices. Mr. King brought up that new fields were being discovered everyday as exploration activities occurred. As new fields came online it would increase supply and push down on price. It was a matter of timing on the new resources as far as what they would do to the price. Also, technology was always changing. New technology that made production more efficient and less costly would likely push down on prices. The same was true with demand. If the need for fuels was reduced, demand would be reduced, and prices would likely fall. There were several things the department was paying attention to in the long-term that suggested it was unlikely the price would return to triple digits. He also noted that the geopolitical factors were more temporary in nature, and the world was seeing many of them presently. When the issues were resolved he expected prices to return to a fundamental level. Mr. King turned to slide 10. He reported that the slide was an illustration of the Energy Information Agency (EIA) forecast relative to DOR's. The black dashed line in the center represented DOR's forecast. He pointed out that they were in inflation adjusted terms which was why they looked much flatter than they would if the Revenue Sources Book numbers were inserted on a plot. He highlighted that the DOR forecast tracked fairly closely to the EIA's forecast. He also pointed out the wide range around what the EIA expected. All of the factors he talked about and mostly the geopolitical factors could push up on prices very quickly. as the market had to adjust there were situations where the prices could correct very severely in the other direction. There was a wide range of prices. He would not interpret the chart as EIA suggested that prices would run up to $120 and grow from there. Rather, the chart was saying that there would be volatility. The price would bounce around within the range. Co-Chair Wilson asked what EIA stood for. Mr. King responded that it stood for the Energy Information Agency. It was part of the administration of the federal government that tracked energy. Mr. King turned to the chart on slide 11: "Petroleum Analyst Consensus Price Forecasts." It compared DOR's revenue forecast to what other analysts were saying. He pointed out that the department's forecast was more-or-less in line with the midrange of forecasts of the other analysists at investment firms. There was a similar range of ideas in the near-term but not as wide of a range as what the EIA's long-term forecast suggested. He reminded members that prices were unpredictable. He could not determine what the prices would be but could explain what was going on and the range of possible outcomes the legislature could plan around. Co-Chair Wilson asked about the "Real Brent." She wondered if it had to do with actual prices. Mr. King responded that the term "real" for economists meant adjusted for inflation. Mr. King moved to slide 12: "Summary of Price Forecasts." The slide reflected all of the forecasts lined up. He pointed to the red line representing the New York Market Exchange (NYMEX). He explained that NYMEX was what people in the market were actually paying for the right for the option to buy at a future price. The Department of Revenue's forecast tracked the red line for 2 years into the future using those numbers as the forecast. He highlighted that the department's forecast was slightly higher than NYMEX which was normal. He elaborated that when commodity traders were purchasing options they were buying in some risks and opportunity costs. The long-term future prices were always lower with the NYMEX than analysists expected. They were not necessarily predictive of what future prices would be, rather, they were reflective of what people were willing to pay for future delivery. Co-Chair Wilson asked what NYMEX stood for. Mr. King indicated that it stood for New York Market Exchange. 1:56:22 PM Vice-Chair Ortiz queried about long-term forecasting and whether the department factored in the growth of alternative energies and them having an impact on long-term demand for oil. Mr. King responded that in the past when the department had its forecasting sessions many items were discussed. The department brought in experts to talk about what future demands might look like and how things were changing in the market place. Participants took the information and made judgements about how those factors would influence future prices. The department also looked at the forecasts generated by other entities. Several things were taken into consideration. Representative Josephson asked why the department compared its price to Brent crude as opposed to West Texas Intermediate (WTI) or something else. He wondered if had something to do with the type of oil being produced. Mr. King explained that it had to do with logistics surrounding crude oil. He explained that when a producer was putting oil onto a tanker and bringing it into a refinery, it was going to a refinery in Anacortes or Los Angeles. The proper way to value the crude was to look at what was being paid for other crudes coming into the same refineries. Brent crudes were coming in on ships that were competing with or augmenting ANS crude in the refineries. He continued that because there were no pipelines crossing the Rocky Mountains none of the WTI crudes entered into those refineries except occasionally by rail car. The two markets were bifurcated. The pricing was the opportunity cost of bringing a barrel of oil from Alaska. Representative Josephson was surprised that the Brent oil field area in the middle of the North Sea was much closer to Northern Europe than the North Slope was to Long Beach or Washington State. Mr. King replied that there were dozens of marker crudes in the world. However, the two largest marker crudes were Brent and WTI. He furthered that when a contract was signed for delivery, the contract might say Brent minus $1 or WTI plus $2. The benchmark crudes were how they were pricing delivery. 2:00:07 PM Commissioner Tangeman continued to slide 14 - the one slide in the presentation on the oil production forecast. He indicated the Department of Natural Resources was responsible for the forecast. Slide 14: "10-Year Production Forecast: Changes since Fall 2018 Revenue Sources Book" showed 2 years of actual productions and were above 500,000 barrels of oil per day. Production was fairly stable. The orange line represented the fall forecast. The blue line depicted the spring forecast. It accounted for the slight dip he had mentioned earlier from 526,000 to 511,000 as the department's forecast number for FY 19. The state was mostly back on track for the out years for production compared to the fall forecast. He highlighted that from FY 17 to FY 28 the state was at about 500,000 barrels of oil per day. He thought several years of flat forecasting was positive. He would never bank on a stable revenue stream for the State of Alaska because of the state's dependency on oil production and price. However, having the Earnings Reserve Account (ERA) draw was nice and stable equal to about $3 billion in the following year increasing to about $3.5 billion within 10 years. Price was also fairly stable with the potential to increase slightly. He did not think there were wide sidebars on the price, high or low. The production forecast seemed stable as well. He suggested that as far as stable revenues went, it was the best picture the department had seen in a while. Co-Chair Wilson commented that in order to remain flat new oil would have to continue to flow into Alaska's pipes. She did not think it was only about current production. It also encompassed new projects as they came online. Commissioner Tangeman agreed. He suggested there was a significant year-over-year decrease of 6 to 8 percent. He believed that when the state flattened out and there was a couple of years of increases, it was attributed to the legacy fields. Producers were investing more and getting more for less. He noted the legacy fields were still declining. However, new production was coming on to fill the void. There might be a bump in upcoming years when the new fields came online. Commissioner Tangeman turned the presentation over to Mr. Stickel to discuss the lease expenditure forecast. 2:03:24 PM Mr. Stickel reviewed the chart on slide 16: "Lease Expenditures Forecast: North Slope Capital Expenditures." He explained that lease expenditures were important for 2 reasons. First, they were a part of the production tax calculation. Monies that companies spent in their oil and gas operations directly impacted the revenue forecast. Second, they were an important indicator of investment and future production. The slide showed the state's forecast for North Slope capital spending in both the fall and spring forecasts. The state had about $1.7 billion in North Slope capital spending in FY 18 which was expected to increase slightly in FY 19 and increase significantly in FY 20 and FY 21 to over $3 billion per year. It represented investment in new fields which was exactly what was needed to bring the new oil into the pipe as Co-Chair Wilson had suggested. The state was seeing major spending beginning in FY 20 on fields like Moose's Tooth, Pikka, Willow, and other new developments. The slight increase from fall to spring had to do with some increased understanding of what the cost of the new projects would be. There was some uncertainty about what it would take to bring the new production online based on conversations with the operators and review of public information and information on tax returns. The department increased the forecast slightly from fall to spring. Representative Josephson referred to the $3.1 billion to $3.3 billion expenditure in FY 21. He wondered if the state would pay $0.35 for every dollar spent in the form of deducted taxes. Mr. Stickel replied that the expenditures would be deducted against the production tax to the extent that the company was paying at the net tax rate. They would receive a 35 percent benefit. It was not always the case depending on what company was making the expenditure. The net impact would likely be less than a full 35 percent. Representative Josephson asked, without the deduction, if they would be paying a flat tax of 35 percent assuming net rather than gross. Mr. Stickel replied that the statutory net tax rate before deductions and credits was 35 percent. Co-Chair Wilson asked how much of an investment a company would have to make before deductions could be applied against the 35 percent tax. 2:06:44 PM Commissioner Tangeman responded that he had heard it would take an investment of about $5 billion to get an oil field similar to Pikka or Willow to production. If the fields were being developed by a company already producing, there would be a different tax implication. For new investments, the monies were being invested up front and would not realize the true impact of the ax system until a field was brought into production. There were many moving parts in the tax structure that made it difficult to provide a number based on a question in a setting like the current hearing. The system was much more complicated. Co-Chair Wilson wanted the public to understand that there was a significant amount of risk that accompanied an investment. A company had to go beyond production to the point of making a profit before receiving a tax credit for the 35 percent. She emphasized the risks companies were taking by making investments. The tax structure had changed such that the state no longer gave the tax credits it used to provide for the initial $5 billion start-up costs. Commissioner Tangeman agreed with Co-Chair Wilson. He added that he was also seeing that the further away from Prudhoe Bay and the trunk line, mostly to the West and the East, it would get more and more expensive to explore and develop. The fields such as Pikka, Willow, and the Greater Moose's Tooth have confirmed the resource. However, the farther away the location was, the more expensive it was to develop. Co-Chair Wilson asked if additional pipeline was a portion of the investment made by new companies establishing new fields. Commissioner Tangeman responded that it was a huge portion of investment. Not only did a company have to reach the site for the development phase, but the product also had to be brought back to the main facilities and trunk lines. Representative Josephson asked if a producer like Conoco Phillips could offset their costs to the East and in Prudhoe Bay before a field in the West came into production. In other words, because they had profits and were in the black, they would be able to enjoy the deductions in the Eastern fields immediately and in the same year. He asked if he was correct. Commissioner Tangeman replied, "Yes, that's correct. He had already noted that it was very different for a company that was already developing fields, earning a profit, and reinvesting its profits to develop more oil further away from the infrastructure. A new entrant would not have any other production to offset the costs. Co-Chair Wilson thought more investment was a good thing for Alaska. Commissioner Tangeman responded in the affirmative. He reiterated that it was getting more expensive to develop further from the infrastructure. Co-Chair Wilson thought everyone wanted to see monies invested in Alaska rather than somewhere else. 2:10:51 PM Mr. Stickel had a comment to add to the previous discussion. The information presented on slide 16 and slide 17 represented allowable lease expenditures against the production tax calculation. There were certain costs, some of which were significant that were not included in the numbers. For instance, lease acquisition costs and financing charges were a major cost for a new company coming in and doing business that were not represented in the numbers. Mr. Stickel continued to slide 17: "Lease Expenditures Forecast: North Slope Operating Expenditures." The slide looked at the state's forecast of operating expenditures on the North Slope. In the fall and spring forecasts the department was seeing fairly stable operating expenditures of about $2.5 billion per year for the existing fields. There was a slight increase at the FY 23 to FY 24 timeframe. It represented the additional cost of operations for the new fields the state expected to come online. Vice-Chair Ortiz returned to the issue of taxes. He asked if the effective tax rate had been 8 percent rather than 11 percent. He wondered if there was a presentation that provided the information. Mr. Stickel responded that the department presented in the other body some analysis that showed that for FY 20 the estimated effective tax rate for North Slope oil was about 8 percent. It represented the department's revenue forecast to the state divided by the production tax value in that particular year. Vice-Chair Ortiz asked about the fluctuation of the tax rate per company. Mr. Stickel suggested that the tax rate would fluctuate. Some companies were small producers and were able to offset most or all of their tax liabilities. Some would pay zero and some might pay 8 percent. He clarified that 8 percent was the North Slope average. 2:14:02 PM Mr. Stickel scrolled to the chart on slide 18: "North Slope Transportation Costs Forecast." The slide examined transportation costs, the costs of getting oil from the fields on the North slope to market. The Trans Alaska pipeline tariff was the largest portion of the number. There was also marine transportation costs and feeder pipeline costs. He highlighted the drop from FY 18 to FY 19 from $9.5 per barrel to $8.40 per barrel in transportation costs. The primary reason for the drop was because there was an agreement on a new methodology for calculating the Trans Alaska Pipeline tariff implemented in FY 19. The transportation costs between the fall and spring forecasts had not changed much. Co-Chair Wilson asked where the tariff started for a company with a smaller line going into the larger pipeline. She wondered if the cost for the shorter line would be at the company's expense. Mr. Stickel responded that generally the cost for the pipeline within the unit would be a gathering line and would be deductible as a lease expenditure. The line outside the unit and connecting into the rest of the transportation line was called a feeder pipeline. The feeder pipeline costs were going to be included in the transportation cost number. Co-Chair Wilson asked for further clarification about transportation costs attached to oil. Mr. Stickel responded that generally for new fields the transportation cost was higher. Prudhoe Bay had no feeder pipeline costs. Oil was placed directly into the Trans Alaska Pipeline. The further away from Prudhoe Bay, the more significant the transportation costs were to get it to the line. Co-Chair Wilson asked if a company was required to share a feeder line. Mr. Stickel replied that her question was beyond his area of expertise. Commissioner Tangeman suggested that the question should be directed to DNR. Co-Chair Wilson was unsure whether there would be an advantage and costs would go down. She was curious about the potential for recouping costs. Commissioner Tangeman assumed there were agreements put into place with DNR on how feeder pipelines were handled. Co-Chair Wilson asked, "Through the lease agreement, most likely?" Commissioner Tangeman responded affirmatively. Representative Josephson thought a unified tax system for each tax payer meant that when a legacy field was largely paid for and additional investments were made outside of that field, they could apply their new investments against the profits derived from the established and paid for fields. He wondered if it was a consequence of having a unified tax system. Mr. Stickel suggested that to say a field was largely paid for was a debatable point. It was true that a company had a slope-wide production tax calculation for all of its oil and gas investment on the North Slope. Each company's specific production tax value would be based on the value of all of their oil sold, the value of their capital expenditures, and their operating expenditures pooled to make the calculation. Commissioner Tangeman indicated that the department's tax director would comment on the last few slides. 2:18:52 PM COLLEEN GLOVER, TAX DIRECTOR, DEPARTMENT OF REVENUE, began her portion of the presentation with slide 20 which showed the tax credits available for repurchase by the state. She clarified that it was the forecasted payoff assuming the state did not go forward with the bonding. The chart showed that by FY 24 all of them would be paid off. She reported that for FY 19 there had been about $100 million that was paid off leaving a current balance of about $740 million. There were no new oil and gas tax credits that were available anymore. The program ended with the passage of HB 111 [Legislation passed in 2017 - Short Title: Oil and Gas Production Tax; Payments; Credits]. Co-Chair Wilson asked what the statutory payment amount was for the current year. Commissioner Tangeman thought the amount was $170 million for FY 20. Co-Chair Wilson asked if it would be stretched out a little longer if the legislature did not pay that amount. Commissioner Tangeman responded in the affirmative. Ms. Glover turned to slide 21 which provided the current status of the tax credit bonding bill - HB 331 that passed in the prior year. There was open litigation concerning the bill and the department was on stand-by until the litigation was resolved. The official spring forecast assumed the bonding passed and all of the credits were paid off in FY 21. Commissioner Tangeman added that the plaintiff appealed the case to the Supreme Court in the previous February. The department was estimating another 12 months before the issue was resolved. In the following year, he hoped to be prepared to hit the market to sell the bonds soon after the litigation was completed. The department was not selling the bonds presently because of the risk of selling them while a legal issue was in a dispute. It was prudent to wait. He hoped there would be a positive resolution and the state would be able to bond for the balance. Co-Chair Foster asked if the commissioner had a sense about how much of the $740 million was expected to fall under the bonding. He wondered about the percentage. Commissioner Tangeman answered that the state would bond for the entire balance. If there was an appropriation made for the current year, the department would bond for the balance. 2:21:58 PM Co-Chair Foster commented that not all of the oil companies would choose to participate. He wondered if the companies had expressed enthusiasm about the bonding. He was hoping for an approximate percentage. Commissioner Tangeman did not know. The credits had been available for purchase on the open market, but there was no interest thus far. The department was proceeding on the assumption that the remaining amount would be bonded. Co-Chair Foster understood that the full amount would be bonded and that not all oil companies would decide not to participate. Instead of getting one lump sum they would get payments over a series of years. His second question was regarding the Supreme Court. It was his understanding that there was some expectation that they might decide the case by early October of the current year. He asked if that information was accurate. Commissioner Tangeman explained that DOR had asked for an expedited ruling. He was uncertain if the court would comply with the state's request. He was not optimistic, but the department would be prepared. In response to the representative's question, a company could choose either path. He thought companies realized that if they wanted to take the hair cut of close to 10 percent, it was their choice - but they would be paid immediately under the bonds. Alternatively, they could sit in the cue and wait subject to appropriation. Representative Josephson asked how much was appropriated in the February 13, 2019 budget for the payment of the cash bonds. Co-Chair Wilson interjected that the amount was $170 million in the governor's original budget paid out through other funds. Commissioner Tangeman answered that the statutory minimum was $170 million for FY 20 paid with Alaska Industrial Development and Export Authority (AIDEA) receipts. Representative Josephson thought there had been an additional amount. Commissioner Tangeman responded that there was an addition of $84 million for FY 19 from AIDEA receipts. The total was $254 million. Co-Chair Wilson noted there was also an additional $27 million that was left in the operating budget for the first payment in anticipation that the bonding would go forward. Commissioner Tangeman responded, "On the debt service, correct." 2:25:36 PM Representative Josephson suggested that because the bond package was not authorized or suspended pending litigation, the administration believed that the legislature underfunded in FY 19 in terms of the requirement noted in the footnote on the slide. He suggested that the $84 million was a catch-up amount. Commissioner Tangeman responded in the affirmative. He elaborated that the previous administration and the previous legislature appropriated $100 million as a backstop because everyone assumed the bonding issue would take affect the previous fall. Someone sued and currently things were delayed. He agreed it was probably appropriate for addressing the issue in the prior year. The amount of $84 million was a recognition that only $100 million was appropriated. He conveyed that $184 million would have been the number. It was a catch-up amount as Representative Josephson had suspected. Co-Chair Wilson noted that there was $70 million currently in the budget. She wondered how the money would be paid out. Ms. Glover explained that the state was still working against credits that were earned in FY 15 and applied for in FY 16. The state had been paying off a percentage of the remaining amount. The division was going back to FY 15 credits and taking the $70 million and allocated just as the division did for the $100 million. Anyone that had applied for tax credits more recently was in the cue for a later date. Co-Chair Wilson thought that the money would not be used for someone willing to take the haircut. It had to do with when the amount came in and when the projects were certified in terms of the state owing money. Ms. Glover responded that they were based on outstanding credits earned in FY 15. Co-Chair Wilson wanted to make sure her memory was correct. Representative Josephson suspected that the bonding agencies thought Alaska was off the rails. Commissioner Tangeman thought Representative Josephson's reference was an appropriate one. He reported that when the loans were being made in 2013, 2014, and 2015 payments were going out in whole year-after-year. At the time the state was in a much different revenue situation. The lenders were under the assumption that whole payments would continue to be made. The amount was vetoed and reduced to the statutory minimum, and lenders were trying to figure out what was happening. He thought it was clearer what the situation was at present. There had been a couple of years where only the minimum was paid out and a bond proposal idea was caught up in litigation. There was really nothing else to do. It was a waiting game. Representative LeBon thought the lenders were keeping a close eye on the situation and waiting. Commissioner Tangeman agreed. Co-Chair Wilson commented that the negative consequences of having the credits outstanding was that what could potentially be occurring on the North Slope was not happening because companies did not have access to funding. She asked if she was accurate. Commissioner Tangeman thought she was accurate. He believed everyone was looking closely at how and where they would invest their capital. Things that occurred in the prior year most likely affected their decision-making going forward. Vice-Chair Johnston mentioned that third parties were gravely affected from the state not honoring its agreements, even though statute allowed the state to do what it was doing. She thought it had a huge impact on investment in Alaska. 2:30:55 PM Representative Carpenter asked to return to macroeconomics on slide 9. He asked what factors were being considered when talking about the national economy. He wondered if the national economy was staying stagnant. He thought there was a deficit problem within the national government. As the state grappled with the issue over the following 10 years, he wondered how the solutions would impact prices of oil if there was a decrease in federal spending over the long- term. Commissioner Tangeman responded that he would have Mr. King responded. Mr. King relayed that the department did not have an explicit model to use to turn knobs on the economy in order to see how things flowed through it. The department had a prototype of a model but had not gone live with it. The reality was that all of the different factors created uncertainty which, in turn, created volatility. The volatility parameter was included in the department's model to understand how far prices could move. The department did not attempt to say that there would be a war that would raise the price. The department might say at some point in the future an event was likely to happen. The uncertainty parameters drove the range of possible outcomes. He thought that if deficit spending continued and resulted in a reduction in travel for vacation and other things, it would potentially drive the price down. All factors played into what happened in Alaska mostly through oil prices. Co-Chair Wilson indicated the committee would be recessing the meeting until April 17, 2019 at 9:00 AM. ADJOURNMENT 2:35:25 PM The meeting was adjourned at 2:35 p.m.
|Spring Forecast Slides.HFIN.pdf||
HFIN 4/16/2019 1:30:00 PM
HFIN - DOR Spring Revenue Forecast