HOUSE FINANCE COMMITTEE February 9, 2023 1:35 p.m. 1:35:09 PM CALL TO ORDER Co-Chair Johnson called the House Finance Committee meeting to order at 1:35 p.m. MEMBERS PRESENT Representative Bryce Edgmon, Co-Chair Representative Neal Foster, Co-Chair Representative DeLena Johnson, Co-Chair Representative Julie Coulombe Representative Mike Cronk Representative Alyse Galvin Representative Sara Hannan Representative Andy Josephson Representative Dan Ortiz Representative Will Stapp Representative Frank Tomaszewski MEMBERS ABSENT None ALSO PRESENT Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue. SUMMARY PRESENTATION: ORDER OF OPERATIONS - ALASKA'S OIL TAX REGIME 1:35:15 PM Co-Chair Johnson reviewed the meeting agenda. ^PRESENTATION: ORDER OF OPERATIONS - ALASKA'S OIL TAX REGIME 1:36:22 PM DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE, introduced the PowerPoint presentation titled, "Order of Operations Presentation House Finance Committee," dated February 9, 2023. He briefly addressed slide 2 which included a list of acronyms associated with the oil industry. Mr. Stickel continued on slide 3 and went through the agenda of the presentation. He would start by looking at the sources of revenue from the state. The focus of the presentation overall would be on North Slope oil. Mr. Stickel moved to slide 4 and offered a disclaimer that the presentation would be taking a complex tax system and simplifying it for the purpose of palatability. He emphasized that anything he said was not tax advice nor an official tax interpretation. He advanced to slide 5, which touched on the four sources of oil and gas revenue for the state. The state received a royalty based on the gross value of production on state land. The rates varied but were typically around 12.5 percent of 16.67 percent in Alaska. The state had a corporate income tax that applied to most, if not all, oil and gas companies. The state received a property tax based on the value of oil and gas property. The tax as 2 percent of assessed value or "20 mills." Any property tax paid to municipalities was allowed as a credit to offset the state tax paid. The final source was the production tax, which would be the focus of the majority of the presentation. 1:40:26 PM Co-Chair Johnson asked if 2 percent property tax was the rule across the state. Mr. Stickel responded that the property tax was levied at the 2 percent rate and any municipal tax up to 2 percent was allowed as a credit against the state tax. The owner of the property would pay the 2 percent tax regardless of the municipal tax rate. Co-Chair Johnson asked if in the state received the full 20 mills in unorganized areas of the state. Mr. Stickel responded the state received the full 20 mills tax when there was no borough. The state received a smaller portion in areas where there was a borough. Representative Hannan understood there were three main municipalities that received the property tax: Fairbanks, Valdez, and the North Slope. She asked if any area was receiving the full 20 mills. Mr. Stickel responded that the city of Valdez was leveling at the full 20 mills and the state was not receiving any state property tax for the City of Valdez. All of the other municipalities were levying less than the full 20 mills as of FY 22. Representative Josephson asked whether occupying the full tax availability was entirely at the discretion of the municipality. Mr. Stickel responded that it was up to the municipality to set the rate, but the municipality was limited in that it could not tax oil and gas property at a higher rate than other properties were taxed. Mr. Stickel continued on slide 6, which showed five years of revenue data from various oil and gas revenue sources. The slide included a chart showing two years of historical data, the status of the current fiscal year, and two years of future projections. The property tax on the chart was the state share only. The municipalities received about $450 million above the state share in FY 22. There were some temporary impacts in FY 21 related to refunds paid out due to losses in 2020 due to the pandemic. Production tax was comprised entirely of general fund revenue. Another revenue source was royalties, though a significant share of royalties were dedicated to the Permanent Fund and the school fund. A smaller source was any settlement as a result an assessment or dispute, which was deposited in the Constitutional Budget Reserve (CBR). The state also received a small share of revenue from the National Petroleum Reserve - Alaska (NPR-A). Additionally, the Willow project would significantly increase the revenue source. 1:45:51 PM Representative Hannan asked if the NPR-A was set in federal statute or if there were opportunities for negotiation. Mr. Stickel responded that he believed it was set by federal statute. The NPR-A was a 50 percent share of revenue back to the state and there were specific provisions around how the resulting revenue could be used. The state was required to use the revenue for the benefit of communities impacted by the oil developments. Representative Hannan asked if the entirety of the 50 percent share was required to be distributed to the impacted communities. Mr. Stickel responded in the affirmative. Representative Hannan asked if any of the revenue would be distributed to the state general fund. Mr. Stickel responded, "Correct." Representative Stapp understood that Mr. Stickel was using the fall revenue forecast for the projections. He asked how much of a discrepancy there was between the FY 22 oil price projections and the current price of oil. Mr. Stickel responded that the Department of Revenue (DOR) compiled a monthly cash flow update and it would be finalized in the following week. The projections for 2023 and 2024 were accurate based on the January 2023 update and did not meet the 10 percent threshold requiring that an official notification be released. The oil prices and revenues were tracking close to the revenue forecast. Representative Galvin asked for more details on the Willow projections. She understood that the oil companies Santos Limited and Conoco Phillips might differ in regard to production and the ways in which the state provided credits. She asked how the potential differences might impact the revenue returning to Alaska. Mr. Stickel responded that Santos was the manager of the Pikka Unit project on the North Slope and Conoco was the manager of the Willow project. Both projects would be subject to property tax, production tax, and corporate income tax. The two differed in the ways royalties would apply and he had a slide later in the presentation that went into detail on the topic. 1:49:20 PM Representative Josephson understood that the severance tax structure for the Willow project and Pikka project was identical, but the royalty revenue was not identical. Willow had great economic value, but it was located on federal land; therefore, the Pikka project would have more value to the state. Mr. Stickel responded that the state would receive relatively more revenue from Willow than it would from Pikka. Representative Josephson commented that royalties in the 2014 and 2015 time frame were significant and a larger part of the revenue picture. He understood that royalties were now occupying the most traditional second share position in terms of its value to the state. He asked if he was correct. Mr. Stickel responded that whether royalties or production tax brought in more revenue to the state was largely a function of the price of oil. Production tax was based on net tax and was progressive to price whereas royalties were based in gross value. Relatively lower oil prices generally meant that royalties would exceed production taxes. There were several years in the 2010s during which production tax generated more revenue than royalties, but royalties had generated more revenue than production tax in the last several years. Mr. Stickel advanced to slide 7, which showed the overall order of operations for the state's fiscal system. The order was as follows: royalties, property tax, production tax, state corporate income tax, and federal corporate income tax. He would go into detail on each step. Firstly, he explained that landowners received their share of oil before any other entity. The second step was property taxes, which were considered lease expenditures for the purpose of calculating the production tax and were also deductible against corporate income taxes. The third step was production tax, which was calculated after royalties had been deducted and property taxes had been considered. The production tax would then become an allowable deduction in calculating corporate income tax. Finally, the state corporate income tax acted as a deduction when calculating the federal corporate income tax. Representative Galvin understood that investment dollars for Conoco could receive a different tax treatment than investment dollars for Santos. She asked if Mr. Stickel could provide more detail. Mr. Stickel responded that he could not speak to specific companies. However, it was true that an incumbent producer that had existing production and revenue on the North Slope could offset revenues with investments in new production. Investments by a company that did not have existing production were treated differently. 1:54:19 PM Representative Cronk asked about the revenues for FY 21 and FY 22 on slide 6. He asked for confirmation that the state received $1.6 billion in FY 21. Mr. Stickel responded in the affirmative. Representative Cronk understood that the state was collecting about 20 percent of the value of a barrel of oil. He asked if he had made a correct assessment. Mr. Stickel responded that DOR had provided the Senate with some information about how the cash flowed from a typical barrel to the producers. He would be happy to provide the committee with the same information. He noted that a significant share of the value of a barrel was dependent upon transportation costs of getting the oil to market, which averaged around $10 per barrel. When assessing the distribution of the value of a barrel, it was important to look at the distribution of the production tax value and how the profit would be shared between the various entities. Co-Chair Johnson thought that it would be helpful to get the information about cash flow. She suggested holding questions until later on in the meeting. 1:57:10 PM Mr. Stickel moved to slide 8, which was the basic calculation of the production tax on the North Slope. The calculation was based on the income statement presented in Appendix E of the Revenue Sources Book released by DOR. He noted there was an error in the original book because the leap year in FY 24 was overlooked. The FY 24 forecast was for $81 per barrel and 503,700 barrels in production, which gave a total value of about $41 million per day of North Slope oil production. Mr. Stickel advanced to slide 9, which was royalty barrels and taxable barrels. Royalty barrels were subtracted before accounting for taxes, which included any state, federal, or private royalty barrels. There was also a small portion of production that was outside of state jurisdiction. After subtracting the royalties, the total was around 160 million barrels of production in FY 24 that were considered taxable with a $13 billion taxable value. Mr. Stickel moved to slide 10. The next step in the calculation was subtracting the transportation costs to arrive at the gross value at the point of production. The transportation costs included the price of getting the oil to market. The price for North Slope oil was priced at market in Long Beach, California. The marine transportation costs were then subtracted, such as the Alaska Pipeline tariff and any other tariffs, and other minor adjustments were made. For FY 24, the average transportation cost estimate was $9.37 per barrel. The average gross value at the point of production was $71.63 per barrel with a total gross value of about $11.5 billion. Mr. Stickel continued to slide 11 and lease expenditures. The production tax was essentially a modified version of a net profits tax. Deductions of both capital and operating expenditures were taken in order to calculate the production tax. The department used guidelines from the Internal Revenue Service (IRS) to determine what was considered a capital expenditure. There was no depreciation provision in the production tax which meant that a company was permitted to deduct its entire capital expenditure in the year incurred. There were two terms to understand: allowable lease expenditures and deductible lease expenditures. Allowable lease expenditures were any costs in the unit directly associated with producing oil and gas. Deductible lease expenditures were developed within DOR to represent the share of allowable lease expenditures that could be applied against the value of production in the year incurred. He added that lease expenditures were treated differently depending on the company. Any lease expenditures that were not deducted in the year incurred became carried forward lease expenditures, which could be used as deductible lease expenditures in a future year's tax calculation. There was a provision in the tax code in which the lease expenditures lost value after a certain amount of time. If a company had not achieved enough production to use the lease expenditures, they would begin to decrease in value. 2:04:06 PM Mr. Stickel moved to slide 12 showing the calculation of production tax value. The calculation was gross value minus lease expenditures. For FY 24, the total production tax value was estimated at about $7.1 billion. The value would be different for every company. Mr. Stickel advanced to slide 13 and detailed the tax calculations once the production tax value had been determined. There were two tax calculations involved: a gross minimum tax floor calculation and a net tax calculation. The minimum tax floor calculation was 4 percent of the gross value at the point of production. For FY 24, the minimum tax floor would be about $460 million. Representative Stapp asked if the minimum tax could be offset using operating expenditures or capital expenditures. Mr. Stickel responded that the operating and capital expenditures were part of the calculation for the net tax only. The minimum tax floor was based on the gross value and there was no allowance for operating and capital expenditures. Representative Josephson commented that prior to HB 247, there were ways for a company's tax rate to be less than 4 percent of gross. He understood that it was no longer allowable. Mr. Stickel responded in the affirmative. In the past, companies had been able to use tax credits to reduce their tax liability below the minimum tax floor. Currently, there was one credit that could be used to take the liability below the minimum tax floor. He would discuss it in more detail later on in the presentation. 2:07:59 PM Mr. Stickel continued on slide 14 which looked at the net tax and gross value reduction (GVR). He explained that GVR was an incentive for new development and provided a temporary incentive by excluding 20 or 30 percent of the gross of qualifying new production. The 30 percent applied if there was a unit with qualifying new production and the unit was an entirely state issued lease with greater than 12.5 percent royalty. Any other qualifying new production would get the 20 percent benefit. The GVR was taken out of the production tax value before applying the tax rate. Additionally, any of the oil that qualified for the GVR provision received a flat $5 per taxable barrel credit rather than the sliding scale credit that applied to all other production. The GVR was a temporary benefit and expired after seven years or after any three years in which oil prices had exceeded $70 per barrel. In FY 24, the production tax value was about $6.9 billion after the GVR. The statutory tax rate was 35 percent of the value, which resulted in a production tax of slightly over $2.4 billion before credits. Mr. Stickel moved to slide 15 which compared the net profits tax and the minimum tax floor. The higher of the two calculations would become the starting point for the tax before credits. In FY 24, the $2.4 billion net tax was expected to prevail over the $460 million minimum tax floor. The major tax credits in place were the per taxable barrel credits. One of the credits applied to the GVR eligible oil and was a flat $5 dollar per barrel tax credit, and the other credit applied to all other oil. The second credit was a sliding scale ranging from $8 per barrel when the wellhead value was less than $80 per barrel. The gross value at the point of production for FY 24 was expected to be $71.63, which meant than an $8 per taxable barrel credit would apply. He explained that the credit phased out in $10 increments of wellhead value. If the wellhead value exceeded $150 per barrel, the sliding scale credit would phase down to zero. If any of the per taxable barrel credits were not used in the year incurred, the credit would be forfeited as there was no provision for state purchase or carry-forward of the credits. The sliding scale per taxable barrel credit could not reduce tax liability below the minimum tax floor. He noted there were a small number of other tax credits against liability, primarily including the small producer credit. The small producer credit was being phased out, but a couple of small companies were still able to claim the credit. If a company did not use any of the sliding scale credits, it could potentially use the $5 per barrel credit to reduce its tax below the minimum tax floor. After deducting all of the credits, the total tax was about $1.2 billion for FY 24. 2:13:02 PM Representative Josephson commented that around FY 12, the $1.2 billion number was around $6 billion. He highlighted the difference because constituents wanted legislators to spend within the means of the state and the state's means were much less than they were in FY 12. Mr. Stickel responded that it was correct that production tax had been very volatile. In FY 13, the production tax was around $4 billion, then in FY 17 it was $126 million. The production tax varied significantly depending on oil prices. Representative Stapp understood that the transportation costs were factored in prior to factoring in the wellhead value. He asked if it would be $90 per barrel and not $80 per barrel because the transportation costs were taken out before the wellhead value was calculated. Mr. Stickel responded that when there was a quote of $80 per barrel, it was typically the destination value. The transportation cost would need to be subtracted to approximate the wellhead value in Alaska. The sliding scale calculation in statute specifically referenced the wellhead value, not the destination value. Mr. Stickel moved to slide 16. There were some other items that would be added to the tax calculation to determine the total tax revenue that was received by the state in a given fiscal year. The items included things like payments of prior year taxes, refunds of prior year taxes, taxes on private landowner royalties, taxes on gas production on the North Slope, surcharges, and any adjustments for company- specific differences. In FY 24, it was estimated that the adjustments would add up to about $16.9 million with a total tax paid to the state of a little over $2 billion. All but $8 million of the total was considered unrestricted general fund revenue. After the calculation of the taxes, the department had estimated that there was about $880 million of lease expenditures in FY 24 that would be earned by companies making investments in the North Slope that could not be applied to production taxes in FY 24. The $882 million would carry forward and be available to offset future tax liabilities. 2:17:32 PM Representative Josephson was confounded by Mr. Stickel's last comment because the treasury received a total of $1.236 billon. He thought it would be difficult to make accurate predictions for future years assuming that the carry-forward lease expenditures could be utilized in the out years. Mr. Stickel responded DOR maintained a company-specific modeling of production tax liabilities and was keeping track of which companies were earning the credits and estimating each company's production tax liability. The department assumed that the companies would utilize the carry forward lease expenditures to the maximum extent possible. The uncertainty around the lease expenditures had to do with the possibility that the expenditures could decrease in value after eight or ten years if it was not utilized. 2:19:05 PM Mr. Stickel moved to slide 17 which took the same analysis that had been performed for FY 24 and projected it out across five years from FY 21 through FY 25. It was estimated that production tax value ranged from about $3.5 billion in FY 21 to $8.8 billion in FY 22 and slight decreases were predicted year over year based on the lower oil prices. The net tax paid to the state followed along with $389 million of production tax in FY 21 and over $1.8 billion in FY 22 and decreased to a projection of a little over $1 billion in FY 25. There were two new rows at the bottom of the slide in response to the feedback in the prior year's presentation. The first new addition was an estimate of the total ending value of the carried forward lease expenditures, which were expected to be nearly $3.3 billion at the end of FY 25. The lease expenditures would be available to offset future taxes for companies. The second addition was a calculated effective tax rate, which depended upon production tax value and evaluated the total amount of tax paid to the state as a result of North Slope production tax value for oil. The effective tax rate was 11 percent in FY 21 and 20 percent in FY 22 and FY 23. Representative Ortiz asked how Alaska's oil tax regime compared to that of other states. Mr. Stickel responded he was not prepared to speak on the topic. Representative Ortiz noted the overall general trend projecting a decrease in revenue in future years. He asked if the reduction was entirely due to projected price or if production had an impact as well. Mr. Stickel responded that the effective tax rate was a result of price and spending and the production had been fairly stable overall. However, higher prices would impact tax rates and lower lease expenditures. Representative Hannan asked about the carried forward lease expenditures and net lease expenditures at the bottom of slide 17. She noted that the carried forward expenditures were slightly more than the net expenditures in FY 21. However, the carried forward expenditures had nearly tripled by FY 24 and had increased fivefold by FY 25. She asked if it was due to there being less development and why it was increasing at such a fast rate. Mr. Stickel responded that the carried forward lease expenditures were a fairly new provision of tax law. The system changed from tax credits to the carried forward system, which became a deduction. The chart on slide 17 indicated that the net lease expenditures carried forward and represented the net earned in a given fiscal year. The total carried forward lease expenditures line on the chart referred to a cumulative calculation and would grow over time. It was expected that the net lease expenditures earned in a given year would increase each year. Representative Hannan asked if there was a risk to the new system. She supposed that if all expenditures were paid off, no tax would be earned due to the process of compounding. Mr. Stickel responded that the state would still receive a tax. The carried forward lease expenditures were limited to the specific company and the specific development that incurred the lease expenditures. They were also limited by the minimum tax floor. Companies with sufficient revenue could chose to reduce the tax liability down to the minimum tax floor. 2:25:50 PM Mr. Stickel moved to slide 18 which modeled a scenario of there being only a single taxpayer on the North Slope. The scenario assumed that there was only one company that operated all of the fields and made all of the investments. The primary difference with the current forecast was that there were some small companies that were not able to use the full $8 per barrel taxable credit. If there was a single producer, it would be expected that the producer would use the entire $8 per barrel credit to offset tax liability. In the scenario, the total production tax deposited into the treasury would be about $1.19 billion, as opposed to $1.24 billion in the official forecast. It was a small difference given the pricing expected in FY 24. The slide intended to highlight the impact of the economics of individual companies on the tax as well as the fact that each company had its own portfolio of operations and investments. Representative Galvin commented that she had read somewhere that a past governor was sorry that they had included worldwide investments in the tax structure as opposed to just Alaska. She was not familiar enough with the topic to discern what that meant, but she thought that Mr. Stickel's comments were related. Mr. Stickel responded that there had been some debate over corporate income tax in particular. The current corporate income tax structure involved taking a company's worldwide income and apportioning it to Alaska rather than calculating a separate income for corporate income tax. Representative Josephson stated he was struggling with the hypothetical scenarios on the carried forward lease expenditures. He thought there would be circumstances dependent upon the production tax value (PTV) in which the state might not make a lot of money for the treasury. However, once the costs had been sunk and paid for, "everyone would come out a winner" in the following year. He asked if he was understanding the concept correctly. Mr. Stickel responded in the affirmative. The idea with the carried forward lease expenditures was to give companies the opportunity to deduct lease expenditures against tax calculations. Incumbent producers could deduct the expenditures in the year that the expenditures were incurred, and new producers could deduct the expenditures in a future year. 2:30:36 PM Mr. Stickel continued on slide 19, which showed how petroleum revenues varied by land type. The concept behind the slide was that not all oil was equal and the amount of revenue the state would receive from oil depended on where the oil originated. There currently was no production beyond six miles offshore of state land. The state would not receive any revenue from intercontinental oil production; however, it could receive economic benefits and it could have a positive impact on the tariff. The state would not apply taxes to production three to six miles offshore, but the state would receive a 27 percent share of federal royalties. There was currently a small amount of production that fell into the three to six mile category. Within the three mile limit, property tax, corporate tax, and production tax was applied the same across all developments. State royalty applied to any production on state land. Any production within the NPR-A was on federal land and 50 percent of royalties were shared back to the state, but the proceeds were required to be used for the benefit of local communities. Additionally, any production within the Alaska National Wildlife Refuge (ANWR) was also on federal land, but the state received a 50 percent royalty with no restrictions. Other federal land would receive a 90 percent share back. Production on private land was primarily owned by Native corporations and a private royalty applied on the land in addition to a 5 percent gross tax as part of the production tax. Representative Hannan understood that the expectation of the amount that the state general fund would receive from the Willow project was limited. She asked if it was zero. Mr. Stickel responded that the revenue impact of Willow would be non-zero as production tax, corporate income tax, and property tax would all apply. Significant production from Willow would also reduce pipeline tariffs. 2:35:03 PM Mr. Stickel continued on slide 20 and briefly touched on the GVR. He explained that the GVR was an incentive program for new oil fields that was part of the SB 21 tax reform enacted in 2013. It was available for the first seven years of production and ended early if North Slope prices averaged over $70 per barrel for any three years. It also allowed companies to exclude 20 percent or 30 percent of the gross value from the net production tax calculation. Mr. Stickel moved to slide 21, which was a repeat of a chart from a previous presentation. The chart showed how unrestricted revenue for FY 24 would change with different oil prices. He relayed that each dollar change in oil price equated to about a $70 million change in UGF revenue. The production tax was progressive in that once the oil price exceeded $90 per barrel, the per barrel revenue increased. Similarly, once prices sunk below $70 per barrel, the companies started paying below the tax floor at a cost of between $50 and $70 per barrel. Mr. Stickel advanced to slide 22, which put the information on slide 21 in table form. The table was taken from Appendix A from DOR's Revenue Sources Book. Mr. Stickel continued to slide 23 which was added in response to a question from the Senate. The slide included a chart comparing the effective tax rate at a range of prices for FY 24 to the statutory net tax rate of 35 percent. The lowest effective tax rate was observed at about $52 per barrel, which was a 9.8 percent effective tax rate. Once the price exceeded $52 per barrel, the tax levy increased with the net profits tax. When prices were below the $52 threshold, the increase also occurred because the tax was governed by the gross minimum tax floor, which meant that a company's profits were decreasing faster than the gross value. He concluded his presentation. Representative Cronk asked how much of the transportation costs were the Trans Alaska Pipeline System (TAPS). Mr. Stickel responded it was about half of the transportation costs. For FY 24, transportation costs were forecasted to be about $9.37 per barrel with $4.88 of the cost being the estimated TAPS portion. Representative Cronk asked if the transportation costs would drop if the new oil fields were online. Mr. Stickel responded that the costs could be stable or potentially decrease. The department was forecasting fairly stable transportation costs due to expected moderate increases in production. 2:40:43 PM Representative Stapp asked for more detail about the use of the 50 percent royalty share from NPRA. Mr. Stickel responded that there was a provision by the federal government that required that the money be used for programs and communities that were impacted by the oil development. He understood that there was a grant program that the state used to distribute the funds. Representative Stapp understood that the funds would be going directly to people like those who had visited his office recently and spoke about the impacts that oil production had on their communities. He asked if he was correct. Mr. Stickel responded that it would be going to the impacted communities. Representative Tomaszewski asked about the disclaimer on slide 4 and read from it: Alaska's severance tax is one of the most complex in the world and portions are subject to interpretation and dispute. Representative Tomaszewski asked if the oil companies liked the tax regime in the state. Mr. Stickel responded that he would defer the question to the oil companies. He added that multiple consultants had reported that Alaska had one of the most complex tax systems in the world and the uncertainties could create difficulties. Representative Tomaszewski asked if the state and the department liked the tax regime. Mr. Stickel responded he would defer the question as well since it was policy related. From a personal standpoint, he acknowledged that the regime could be tricky and complicated. Representative Hannan asked if the tax was complicated due to the regulations surrounding surface ownership and subsurface ownership. In most other jurisdictions, the ownership was unified, but Alaska reserved the subsurface rights. An additional hurdle was the great distance oil needed to travel across the state. Mr. Stickel responded that it was definitely a contributing factor. An additional factor was that there had been many changes throughout the years which had complicated the process. Representative Cronk commented that he related the oil tax regime to the Base Student Allocation (BSA) because no one could explain how it worked. 2:45:22 PM Representative Tomaszewski asked if the forward lease expenditures were specific to a particular lease of if the expenditures could be used on other leases. Mr. Stickel responded that the carried forward lease expenditures were tied to a specific lease and a company needed to bring the lease into production and apply the lease expenditures in its tax calculation. Representative Tomaszewski asked if there was a time or value cap. Mr. Stickel responded that eight or ten years after the lease expenditures were earned, they started to decrease in value if they had not been used. There was not a dollar amount limit to how much a company could invest to earn the lease expenditures. Representative Josephson asked if it was true that using the carried forward lease expenditures was not prohibited for a taxpayer like Conoco. He understood that Conoco could use the expenditures when in profit near Prudhoe Bay or not in profit in another field. He thought whether or not they were in profit was a North Slope question. Mr. Stickel responded that if an existing producer like Conoco had sufficient gross revenue and made an investment in a new field, it would be able to apply the lease expenditures in the year in which the investment was made. Co-Chair Johnson reviewed the following day's agenda. 2:48:33 PM ADJOURNMENT The meeting was adjourned at 2:48 p.m.