ALASKA STATE LEGISLATURE  HOUSE RESOURCES STANDING COMMITTEE  March 20, 2019 1:10 p.m. MEMBERS PRESENT Representative John Lincoln, Co-Chair Representative Geran Tarr, Co-Chair Representative Grier Hopkins, Vice Chair Representative Sara Hannan Representative Ivy Spohnholz Representative Dave Talerico Representative George Rauscher Representative Sara Rasmussen MEMBERS ABSENT  Representative Chris Tuck COMMITTEE CALENDAR  PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION FORECAST UPDATE - HEARD PREVIOUS COMMITTEE ACTION  No previous action to record WITNESS REGISTER PASCAL UMEKWE, PhD, Commercial Analyst Division of Oil and Gas Department of Natural Resources Anchorage, Alaska POSITION STATEMENT: Provided a PowerPoint presentation entitled, "Spring 2019 Production Forecast," dated 3/20/19, and answered questions. BRUCE TANGEMAN, Commissioner Designee Department of Revenue Juneau, Alaska POSITION STATEMENT: Provided a PowerPoint presentation entitled, "Spring 2019 Revenue Forecast Update," dated 3/20/19, and answered questions. DAN STICKEL, Chief Economist Tax Division Department of Revenue Juneau, Alaska POSITION STATEMENT: Answered questions during the presentation entitled, "Spring 2019 Revenue Forecast Update." ED KING, Chief Economist Office of the Governor Juneau, Alaska POSITION STATEMENT: Answered questions during the presentation entitled, "Spring 2019 Revenue Forecast Update." ACTION NARRATIVE 1:10:59 PM CO-CHAIR GERAN TARR called the House Resources Standing Committee meeting to order at 1:10 p.m. Representatives Hannan, Talerico, Spohnholz, Rauscher, Rasmussen, Hopkins, Lincoln, and Tarr were present at the call to order. ^PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION FORECAST UPDATE PRESENTATION(S): SPRING REVENUE FORECAST AND PRODUCTION  FORECAST UPDATE    1:11:39 PM CO-CHAIR TARR announced the only order of business would be presentations on spring production and revenue forecasts by the Department of Natural Resources and the Department of Revenue. 1:12:03 PM MADUABUCHI PASCAL UMEKWE, PhD, Commercial Analyst, Division of Oil and Gas, Department of Natural Resources, provided a PowerPoint presentation entitled, "Spring 2019 Production Forecast." The committee took a brief at-ease. DR. UMEKWE explained the presentation is an update from the Fall 2018 Forecast. The Division of Oil and Gas (DOG) has been providing production forecasts since 2016 to support the work of the Department of Revenue (DOR) that generates the revenue forecast. Slide 2 was an outline of the presentation and he noted there are no significant long-term differences between the fall and spring forecasts. Slide 3 illustrated that actual daily production was less than predicted for the first six months of fiscal year 2019 (FY 19). 1:16:07 PM DR. UMEKWE continued to slide 4 which listed contributing factors for lower than expected production: warmer winter thus lower production; operational differences such as slower well work repairs and underperformance from one well in the Greater Mooses Tooth 1 field. REPRESENTATIVE SPOHNHOLZ asked how warmer winter weather contributes to lower production. DR. UMEKWE explained on most of the North Slope fields, high volumes of gas are used for gas injection, and for gas lifting, to facilitate production. In colder temperatures the gas is denser thus it is significantly easier for compressors to handle, inject, and move gas. REPRESENTATIVE SPOHNHOLZ asked whether compressors overheat in summer. DR. UMEKWE further explained the compressors do not achieve their nameplate [rated maximum] capacity in warmer months due to the density of the gas; in winter months the gas is denser, and it is easier to compress the gas and move the gas to the wells. 1:21:01 PM REPRESENTATIVE RASMUSSEN inquired as to the timeline of the aforementioned production. DR. UMEKWE clarified said production was over the period from July through December [2018]. REPRESENTATIVE RASMUSSEN restated her question: The production process, like from where the oil is to, does it go to [the Trans-Alaska Pipeline System (TAPS)] in this projection, or how far along is it going in the process? DR. UMEKWE said what is projected is produced from the wells, which is a combination of oil production and [natural gas liquids (NGLs)]. In further response to Representative Rasmussen, he said the projection reflects what goes to TAPS with the exception of NGLs that are moved from one field to another. REPRESENTATIVE RASMUSSEN questioned whether the flow of oil through TAPS is also affected by temperature. DR. UMEKWE advised warmer fluids generally reduce impediments to the flow. REPRESENTATIVE HANNAN returned attention to slide 3 that indicated a variance [between actual production and forecast production] of 1.25 percent and surmised predictions are rarely without a range of variance. DR. UMEKWE recalled in the last decade on a one-year basis, the state's forecast variance has been 1-2 percent, and on a monthly basis, could be as high as 4-5 percent. 1:24:01 PM REPRESENTATIVE HANNAN returned attention to slide 4 and asked whether industry provides the data related to the expected production from a specific well or field. DR. UMEKWE said companies provide forecasts for the wells they drill and announcements describing the actual production from wells and fields; DOG generates an inhouse forecast and an estimate for each new well, based on a range of production from similar wells, and creates forecasts for each well. CO-CHAIR TARR questioned whether changing climate data is compiled and integrated into DOG forecasting. 1:26:52 PM DR. UMEKWE said no, DOG does not forecast changes in temperatures; however, DOG looks at several months which can reveal a trend over a long period of time. He confirmed that historical data for temperature exists and data on heating degree days can be compared as one part of the equation of impacts to production. 1:28:23 PM CO-CHAIR TARR expressed her interest in reviewing and understanding temperature analysis because there may be impacts to ice roads from shorter winter seasons; further, she asked Dr. Umekwe to provide specific analysis of year-to-year production on a monthly basis. 1:29:14 PM DR. UMEKWE continued to slide 5 which showed a comparison of Fall 2018 and Spring 2019 forecasts. He pointed out there is a downward revision of approximately 8,000 barrels of oil for total state production in FY 19, despite a slight upward revision for Cook Inlet production. Slide 6 illustrated that the long-term production forecast is essentially unchanged. Slide 7 was a summary: for the near term, there is a slight downward revision; for the long term, the outlook is unchanged based on information from industry and field observations. CO-CHAIR TARR returned attention to slide 6 and DOG's long-term production forecast. DR. UMEKWE explained slides 9 and 10 are informational. Slide 9 indicated the land ownership and location of projects on the North Slope. Projects illustrated have been evaluated; forecasts for the projects 5-6 years from production are unchanged. REPRESENTATIVE HOPKINS asked for the timeframe for the Smith Bay development. 1:33:59 PM DR. UMEKWE was unsure and could not recall announcements by the explorers as to a specific date. He described slide 10 as follows: So the next slide just shows all these projects that I just showed you in the previous slide, rolled up together, including the different risk, or layers of risk, that we applied to those projects and the essence of that is just to ensure that for planning purposes, the state is not, DOR is not providing the state with a revenue outlook that is overly optimistic. ... So, what you see here is not a summation of the promised rates for each of these projects, all you see is a product generated from applying the appropriate - what we think [are] the appropriate - levels of risk to each of the projects. And these volumes will be adding to, you know, legacy production, and we know that legacy production generally declines over time. CO-CHAIR TARR asked whether slide 10 included the effect of less oil production on the North Slope if gas were diverted to the ALASKA LNG gas pipeline project. DR. UMEKWE said no. In response to Representative Rasmussen, he confirmed the production shown on slide 10 is in addition to existing oil production. 1:37:10 PM The committee took an at-ease from 1:38 p.m. to 1:42 p.m. CO-CHAIR TARR invited Commissioner Designee Tangeman to continue the presentation. 1:42:24 PM BRUCE TANGEMAN, Commissioner Designee, DOR, provided a PowerPoint presentation entitled, "Spring 2019 Revenue Forecast Update," dated 3/20/19, which was an update to the Fall [2018] Forecast. He pointed out forecasts are based upon information at hand thus changes in well performance, oil price, and the "down time" of wells affect forecasts. Currently, DOR is forecasting about $69 per barrel - approximately $1 higher than the Fall [2018] Forecast - and about $5 higher than anticipated last spring. For FY 20, the oil price for the Fall [2018] Forecast of $64 per barrel has been increased to $66 per barrel. Commissioner Tangeman outlined the presentation (slide 2); on slide 4 he pointed out total unrestricted general fund (GF) revenue is down by $89 million dollars for FY 19, and up by $39 million for FY 20. He said details will be provided but generally, prices were up, and production was down in FY 19. Also shown was that fall and spring forecasts for the next several years are generally unchanged. CO-CHAIR TARR asked Commissioner Tangeman to review other sources of unrestricted GF revenues such as corporate income tax. 1:48:01 PM DAN STICKEL, Chief Economist, Tax Division, DOR, explained unrestricted nonpetroleum tax revenue included: corporate income tax, mining license tax, excise taxes; a variety of licenses and permits; charges for services, fines, and forfeitures; nonpetroleum rents and royalties; miscellaneous revenues. CO-CHAIR TARR recalled corporation income tax represents the highest percentage of nonpetroleum tax revenue, followed by sin taxes, gas tax, and other sources that provide the final modicum. MR. STICKEL referred to the Spring Revenue Forecast Update, page 6, that indicated of unrestricted nonpetroleum revenues, the taxes portion is forecast to be approximately $350 million per year out of a total of $550 million [document not provided]. REPRESENTATIVE HANNAN clarified that the aforementioned gas tax is [motor fuel tax, not a production tax on gas]. MR. STICKEL, in response to Representative Hopkins, restated corporate income tax is estimated to bring in $120 million in FY 19, and $135 million in FY 20, from nonpetroleum companies. REPRESENTATIVE HOPKINS asked which nonpetroleum revenues are decreasing. MR. STICKEL explained the decreases in nonpetroleum income tax are based on weakness in payments and lower minerals prices (slide 5). REPRESENTATIVE HOPKINS questioned whether [the decrease in nonpetroleum revenue] is related to other extraction industries or industries that are not related to mineral extraction. MR. STICKEL said nonpetroleum corporate income tax includes revenue collected from any corporations that are not oil and gas; the largest sector contributing to nonpetroleum income tax revenue is mining and mining-related industries. REPRESENTATIVE HOPKINS surmised nonpetroleum revenue is expected to continue to decrease over the next ten years. MR. STICKEL said DOR is forecasting fairly stable revenue from nonpetroleum sources. In further response to Representative Hopkins, he advised DOR has some economic growth built in to the forecast, along with inflation. 1:52:39 PM COMMISSIONER TANGEMAN remarked (slide 4): If you were showing a decreasing revenue stream, you'd see those numbers getting larger and larger to the red. As you can tell, they've just kind of reset to a lower number but they're steady still. So, this is just a ten-year forecast based on the information that we currently have, and we currently know. Any policy changes, or political issues, we don't put into these forecasts ... so this is purely just what we know that is in front of us at the time. REPRESENTATIVE HANNAN questioned whether oil and gas industry corporate income taxes are not included because oil and gas companies can use corporate income tax deductions when calculating the amount of tax owed. MR. STICKEL explained DOR has two statutes for corporate income tax: one statute applies specifically to oil and gas extraction and pipeline companies, and has the same tax rate table, but a different apportionment factor, and is reported separately. In further response to Representative Hannan, he said for the purpose of corporate income tax, petroleum corporations report worldwide income apportioned to Alaska based on Alaska's share of their worldwide production, property, sales, and tariffs; nonpetroleum corporations report their U.S. water's-edge income apportioned to Alaska based on Alaska's share of their U.S. property, payroll, and sales. CO-CHAIR TARR recalled past proposed legislation that was related to the difference [in apportionment] which she characterized as "a multi-billion-dollar distinction and has been a significant point of contention in the past." 1:55:48 PM MR. STICKEL affirmed at one time Alaska utilized separate accounting for oil and gas. REPRESENTATIVE RASMUSSEN asked whether mining prospects, such as Donlin [Gold Project], are included in nonpetroleum revenue. MR. STICKEL said Donlin or Pebble mine projects are not included at this time. He continued to slide 5, which listed some of the reasons for changes in the FY 19/FY 20 unrestricted revenue forecast. Although oil price has slightly increased, the FY 19 forecast was reduced by $89 million primarily due to a reduction in the oil and gas production tax of $80 million, and he elaborated. Also, nonpetroleum corporate income tax was reduced as previously discussed: royalties increased by $8 million and a variety of smaller changes accounted for a reduction of $2 million. The FY 20 forecast was increased by $39 million, primarily due to an increase in production tax, and by an increase in royalties that was offset by a $15 million reduction in nonpetroleum corporate income tax [as previously discussed], and reductions to a wide variety of sources. 2:00:28 PM CO-CHAIR TARR asked what sources are used by DOR to forecast prices for mineral commodities. MR. STICKEL explained DOR references the futures market; at the time of the fall forecast, the futures market indicated stable or increasing prices for minerals such as zinc. CO-CHAIR TARR questioned whether there is a "true-up" of mineral prices. MR. STICKEL said not on a regular basis. COMMISSIONER TANGEMAN directed attention to slide 7 which was a price forecast summary; the Fall 2018 Forecast was about $68 per barrel for FY 19, $64 per barrel for FY 20, and $77 per barrel for FY 28. He recalled a period of fluctuating prices during the winter of 2018 and cautioned that lawmakers must make budget decisions based on a responsible revenue forecast. Because of DOR's work in the fall, he noted the administration and DOR decided to base its Fall 2018 Forecast on the Spring 2018 Forecast. Commissioner Tangeman stressed the importance of supporting each forecast with history. Therefore, the Spring 2019 Forecast is based on eight or nine months of actuals, which year-to-date are around $69 [per barrel], and to align with the current futures market price from [New York Mercantile Exchange (NYMEX]). He advised NYMEX has been shown to be one of the better methods to gauge short-term oil prices; however, additional sources are included for long-term decisions (slide 8). 2:07:15 PM REPRESENTATIVE HOPKINS asked how accurate forecasts were from 2009-2019. COMMISSIONER TANGEMAN said DOR would provide the requested information. REPRESENTATIVE HOPKINS returned attention to slide 8 and asked how Alaska North Slope (ANS) price "tracks" with [Brent Europe crude oil (Brent)], [West Texas Intermediate (WTI)] and the refining market for oil from TAPS. COMMISSIONER TANGEMAN explained ANS tracks fairly well with Brent [the price for oil that is also transported by tankers] and has shown a "significant [performance] delta" to WTI for several years. [Lower WTI oil price] is due primarily to the amount of oil that is constrained by how the oil must get to the market, for example, in North Dakota companies were transporting oil by railcar. However, ANS [oil price] compares fairly closely to Brent [oil price]. He opined if a pipeline system opens in the Lower 48, WTI [price] will increase closer to ANS [price] as opposed to ANS going down to WTI. Another factor is the amount of shale oil that is currently affecting price fluctuations; in fact, there are no expectations of $90-$100 oil price, and the realistic price is expected in the $50-$70 range. REPRESENTATIVE HOPKINS remarked: With ANS tracking at Brent, being higher than WTI, we sell our ANS into the WTI refining market, right? Or is that wrong? And then how does that price discrepancy compare to each other when we're trying to sell our ANS in competition with a lower price oil. 2:11:02 PM ED KING, Chief Economist, Office of the Governor, further explained oil produced in Alaska is shipped from Valdez primarily to Los Angeles, California, and Anacortes, Washington, for refining. The West Coast refineries only accept oil from other water-borne sources because there are no pipelines that cross the Rocky Mountains; thus, WTI oil does not enter the West Coast market, which explains why ANS is closer in price to Brent. Recently, the amount of shale oil available has reduced the volume of imported oil and the WTI market "stands on its own, so it's not reacting as much to the rest of the world market." However, when the pipelines open, the WTI market will move up to the global market for crude. For the most part, the ANS and WTI markets are separate. REPRESENTATIVE RAUSCHER asked whether industry agrees with DOR on its oil price forecast. COMMISSIONER TANGEMAN declined to speak for industry. MR. KING related BP, ConocoPhillips Alaska, Inc., and ExxonMobil Corporation publish an annual outlook of supply and demand factors from which one can ascertain their expectations; however, the oil price companies use as a hurdle price to sanction a project differs from a price prediction. The Department of Revenue studies the marketplace each day to see what the actual price is as reflected by NYMEX. REPRESENTATIVE SPOHNHOLZ returned attention to slide 4 and pointed out unrestricted GF for nonpetroleum revenue [shown as $548 million] differs from that of the Revenue Sources Book, which shows mid-$350 million. 2:15:34 PM MR. STICKEL explained unrestricted nonpetroleum revenue shown on slide 4 includes funds for total unrestricted nonpetroleum revenue, except federal investment of $469 million - forecast for FY 20 -, of which $344 million is tax revenue; in addition, the tax division adds unrestricted investment revenue other than the Permanent Fund draw of $79.6 million. CO-CHAIR TARR asked whether [unrestricted investment revenue] accounts for the constitutional budget reserve (CBR) earnings. MR. STICKEL said no; CBR is designated revenue. The amount in FY 20 of $79.6 million represents earnings on the general fund (GF). In further response to Co-Chair Tarr, he clarified the general fund maintains a balance of approximately $2 billion, which is invested in liquid investments and earns a small return. MR. KING directed attention to slide 9. He said the information presented was intended show different factors that can influence oil market prices, such as future demand or a recession. In the case of a recession, there is a decrease in demand and oil prices would go down. Currently, prices are depressed because of the uncertainty about the trade dispute with China. Other near-term factors include new energy resources and the production of shale oil. In the long term, factors include more efficient technology, which reduces demand, increases supply, and lowers price. Mr. King said, " And then there's the things that we just don't know, and they're on the radar, but you can't predict what's going to happen when you're talking about ... geopolitical factors that are going on - those things disrupt the market in a very meaningful way ... but you can't predict when ...." He characterized DOR's forecast as the average of all the possible futures. 2:20:59 PM REPRESENTATIVE RASMUSSEN asked whether the projections have a margin of error. MR. KING explained forecasts are driven by two types of uncertainty: (indisc.) risk that cannot be reduced because it is unknowable; uncertainty that can be reduced by measurement. He said in the oil, commodities, and stock markets, a portion of the amount of uncertainty cannot be reduced; in fact, the error for predicting the price of oil can be 40 percent. REPRESENTATIVE RASMUSSEN pointed out in 2009, the predicted oil price for 2019 was $90-$100 per barrel, which was off by about 40 percent. REPRESENTATIVE HANNAN directed attention to the potential microeconomic driver of vehicle efficiency and asked how much petroleum is produced for gasoline and diesel [fuels] (slide 4). 2:24:14 PM MR. KING acknowledged the biggest use of petroleum is for transportation fuel including vehicle fuels and aviation fuels; however, the effects of vehicle efficiencies and possible conversions to electric vehicles may be offset by the possibility of a growing demand in certain areas of the world, and both situations are unknown. Mr. King continued to slide 10, which illustrated a range of potential oil prices forecast by the U.S. Energy Information Administration (EIA). The high case of prices at $120 and above reflected prices as a result of a possible catastrophic event. The low case of prices at $40 reflected prices as a result of overcapacity following a disruption. He said DOR's spring revenue forecast has taken a weighted average of prices - close to EIA's reference case, albeit a slightly different interpretation. Referring to Representative Rasmussen's comment, he pointed out marketplace indicators such as NYMEX tend to overemphasize the effect of short-term current events, thus DOR seeks to avoid the effect of current events and focus on long-term factors. MR. KING continued to slide 11, which illustrated projections and forecasts by investment analysts. A group of analysts forecast a range of oil prices from high to low and the DOR Spring 2019 forecast falls in the center. Slide 12 illustrated short-term forecasts by NYMEX, analysts, and EIA Short-term Energy Outlook, adjusted for inflation. 2:30:54 PM REPRESENTATIVE HOPKINS noted production projections were off by 1.65 percent and asked whether that is an average [deviance](slide 14). COMMISSIONER TANGEMAN deferred to DNR. In response to Co-Chair Tarr, he confirmed DNR provides DOR production forecast information. COMMISSIONER TANGEMAN explained in a net tax structure, operating costs, capital costs, and transportation costs are deductible thus it is important to understand the effect of the range of potential investment. He opined east and west of Prudhoe Bay, there are resources, but resources away from the main trunk pipeline are more expensive to explore, produce, and transport. Alaska's current stable oil tax system has brought private sector investment to the state to explore and produce new fields. MR. STICKEL continued to slide 16 which illustrated ten-year forecasts of capital expenditures on the North Slope for spring FY 19 and fall FY 18. For existing production, producers are maintaining fairly stable capital spending; however, the spending increase forecast from FY 18-FY 21 is indicated due to costs associated with several new fields, such as Greater Mooses Tooth, Pikka, and Willow. He advised the additional production will require billions of dollars of industry investment; the change from [the fall forecast to the spring forecast] was after DOR further examined the producers' reports and tax filings. Slide 17 illustrated operating expenditures are stable up to FY 23-FY 24, at which time there is an increase. 2:35:54 PM REPRESENTATIVE HANNAN asked whether all capital expenditure costs are deductible from a producer's net tax structure. MR. STICKEL said yes, in the year earned; unlike an income tax with a depreciation schedule, producers are able to deduct their entire capital cost in the year earned. If a company does not have enough offsetting production, it earns a carryforward lease expenditure. REPRESENTATIVE HANNAN surmised a well may be expensive to bring online, but if it underproduces, the state earns nothing. MR. STICKEL explained production tax on the North Slope is assessed on a company-wide basis; for example, if a company drills a new well it would use the cost of developing the new well to offset against production [taxes] elsewhere. REPRESENTATIVE HANNAN concluded there is no risk to a producer [to develop a marginally profitable well] because an existing producer has other wells that are profitable. COMMISSIONER TANGEMAN cautioned there is always an investment risk to a company's return on investment, especially when there are other opportunities. He said, " ... I don't think anybody's looking to invest a dollar hoping to break even." MR. KING pointed out if a company [in the aforementioned example] doesn't have any other production and it invests a dollar for a loss, the state doesn't make any money and the company loses its investment; if the company has other production in Alaska, the state loses 35 cents and the company loses 65 cents. 2:39:19 PM CO-CHAIR TARR suggested the oil tax equation should be reviewed and remarked: The oil tax equation ... [is] the wellhead price minus the transportation cost then, minus the capital expenditures, minus the operating expenditures. The capital and operating are considered the allowable lease expenditures. Then the total after that is the PTV, or production tax value and then you apply the tax after that you take the PTV times 35 percent. And then, that remaining value would be the tax that's due to the state except you apply the per barrel credit after that, and right now the per barrel credit ... is $8.00, which once you apply the per barrel credit, makes that number negative. And so our tax system is set up so you do [an] either/or, so the alternative is the minimum tax ... if you do the minimum tax you do it by that number that comes after transportation, the wellhead minus transportation is the GVPP, the gross value at the point of production, and so you do that number times 4 percent ... that's what our minimum tax is right now, and so we're mostly paying at the 4 percent ... which is about $2 per barrel in production tax. ... Slide 16, was, you know, capital lease expenditures, that's one section of that deduction, and the next one is operating lease expenditure, that's another section of that deduction, and then the third one is transportation costs, that's the other deductible amount. And one of the challenges is ... those transportation costs to get from the point of development into the TAPS line, are going to become more, right, as the developments are farther away. CO-CHAIR TARR posited the example of transportation costs for the Smith Bay development, which is approximately 124 miles from TAPS. 2:42:11 PM REPRESENTATIVE HANNAN inquired as to what price per barrel would cause a change from the minimum 4 percent tax to the production tax. MR. STICKEL observed the "crossover point" varies between $60- $65 per barrel. COMMISSIONER TANGEMAN continued to slide 20 which illustrated cashable credits liability and appropriations for payment. The state is no longer accruing cashable credits as a liability due to changes in oil and gas tax law. In FY 19, there was a $100 million appropriation to pay tax credits, and for FY 20, DOR estimates an appropriation of $175-$185 million. CO-CHAIR TARR recalled there has been a discrepancy in how to calculate the statutory amount needed to pay tax credits. Previously the allocation was calculated including the application of the per barrel credit; however, during former Governor Bill Walker's administration, the allocation was calculated without including the per barrel credit, which changed the overall formula. This change resulted in an increase in the statutory appropriation from approximately $70 million to $128 million. 2:46:04 PM COMMISSIONER TANGEMAN returned to slide 21, which described House Bill 331 [passed in the Thirtieth Alaska State Legislature]. House Bill 331 established a mechanism to issue bonds so the state could pay off the tax credit liabilities and pay the bonds through debt service. In FY 19, $100 million was appropriated in anticipation of the beginning of the bonding procedure; however, a pending lawsuit has slowed the procedure thus the state awaits an Alaska Supreme Court decision. Until there is a final favorable court decision, DOR will wait to issue bonds, and therefore has requested $184 million for a statutory payment in the FY 20 budget. CO-CHAIR TARR questioned how a favorable decision would affect the timeline of payments. COMMISSIONER TANGEMAN anticipates a court decision within 12 months and a return to the bonding schedule this time next year. CO-CHAIR TARR surmised payments of $100 million in FY 19 and $184 million in FY 20 would reduce the liability by about one- third. COMMISSIONER TANGEMAN said yes, the remaining liability would be approximately $600 million. CO-CHAIR TARR recalled the Walker Administration plan was that [companies that are owed tax credits] would accept a smaller payment now, rather than wait for a full payment later. COMMISSIONER TANGEMAN said yes, the state would be held harmless. REPRESENTATIVE HANNAN asked if the $184 million appropriation is in DOR's budget. COMMISSIONER TANGEMAN said the appropriation is in the operating budget. CO-CHAIR TARR asked to be notified if the administration considers any changes to the current plans on how to address the tax credit liability. 2:51:51 PM ADJOURNMENT  There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 2:51 p.m.