Legislature(2019 - 2020)SENATE FINANCE 532
03/22/2019 09:00 AM FINANCE
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|Presentation: Severance Tax - Order of Operations|
* first hearing in first committee of referral
= bill was previously heard/scheduled
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SENATE FINANCE COMMITTEE March 22, 2019 9:02 a.m. 9:02:04 AM CALL TO ORDER Co-Chair Stedman called the Senate Finance Committee meeting to order at 9:02 a.m. MEMBERS PRESENT Senator Natasha von Imhof, Co-Chair Senator Bert Stedman, Co-Chair Senator Click Bishop Senator Lyman Hoffman Senator Peter Micciche Senator Donny Olson Senator Mike Shower Senator Bill Wielechowski Senator David Wilson MEMBERS ABSENT None ALSO PRESENT Senator Cathy Giessel; Senator Chris Birch; Senator Mia Costello; Bruce Tangeman, Commissioner, Department of Revenue; Dan Stickel, Chief Economist, Economic Research Group, Tax Division, Department of Revenue. PRESENT VIA TELECONFERENCE Colleen Glover, Director, Tax Division, Department of Revenue. SUMMARY PRESENTATION: SEVERANCE TAX - ORDER OF OPERATIONS Co-Chair Stedman informed that the committee would consider the order of operations dealing with oil production tax and would receive a tax audit update. Co-Chair Stedman asked for the presenters to stay on topic. He stated that the purpose of the meeting was to walk through the mechanical operations of the severance tax. He reminded that the state's oil revenue came from four major categories: royalties, severance tax, income tax, and property tax. The severance tax was considered to be complex. He emphasized that the state's oil and gas tax structure was very complex. He thought it would not be possible to conclude if the state's tax structure was high or low, as the analysis was not comparative. Co-Chair Stedman continued his opening remarks. He mentioned that cost structures around the world had changed when the price of oil dropped; including in Alaska and significantly in the Permian Basin in East Texas, in North Dakota, and other areas. He cautioned that the severance tax information should not be compared without additional analysis. He asked that people take the presentation with a grain of salt. ^PRESENTATION: SEVERANCE TAX - ORDER OF OPERATIONS 9:06:27 AM BRUCE TANGEMAN, COMMISSIONER, DEPARTMENT OF REVENUE, reiterated that Alaska had one of the most complex oil and gas tax structures in the world. He relayed that the presentation would give a glimpse of a small piece of the audit process. He affirmed that he was not going to talk about oil policy or comparisons, rather to explain how the state's tax structure worked. He recalled that since 2011 or 2012 the State of North Dakota thought its break-even point was in the 70s, and now it was in the 30s. He commented that the world had changed quite a bit, especially with regard to shale. 9:07:57 AM DAN STICKEL, CHIEF ECONOMIST, ECONOMIC RESEARCH GROUP, TAX DIVISION, DEPARTMENT OF REVENUE, discussed the presentation "Alaska Oil and Gas Production Tax Calculation ("Order of Operations")" (copy on file). Mr. Stickel turned to slide 2, "Acronyms used in this presentation": ?ANS Alaska North Slope ?Avg -Average ?Bbl Barrel ?CBRF Constitutional Budget Reserve Fund ?CIT Corporate Income Tax ?DOR Department of Revenue ?GVPP Gross Value at Point of Production ?GVR Gross Value Reduction ?Min Minimum ?NPR-A National Petroleum Reserve Alaska ?PTV Production Tax Value ?Ths Thousands ?FY Fiscal Year Mr. Stickel acknowledged that there was a great deal of jargon used in oil and gas industry, and in production tax policy in particular. Co-Chair Stedman was optimistic that the presentation would be shorter than what was expected. He asked the testifiers to avoid using acronyms in order for people to follow along. Mr. Stickel agreed. Mr. Stickel discussed slide 3, "Overview": ?Oil and Gas revenue sources how production tax fits in o FY 2017 FY 2021 oil and gas revenues ?Production tax calculation "order of operations" o Detailed walk-through of each step of tax calculation o Defining commonly used jargon o Focus on North Slope oil o FY 2017 FY 2021 comparison Mr. Stickel affirmed that the purpose of the presentation was to explain the production tax and how it fit into the overall oil and gas fiscal system. He noted that North Slope oil was the main revenue source to the state from the petroleum industry. 9:10:06 AM Mr. Stickel referenced slide 4, "Disclaimer": ?Alaska's severance tax is one of the most complex in the world, and portions are subject to interpretation and dispute ?These numbers are rough approximations based on public data as presented in the spring 2019 forecasts and other revenue forecasts. ?We are economists, not auditors. This presentation is not an official statement of the Department as to any particular tax liability, interpretation, or treatment. This is not tax advice or guidance. This presentation is solely for illustrative general purposes. Co-Chair Stedman asked for the testifiers to address the aggregation issue. He referenced the Revenue Sources Book (copy on file), which was published the Department of Revenue (DOR) in the fall and updated in the spring. He asked Mr. Stickel to discuss aggregated numbers. Mr. Stickel explained that oil and gas tax was levied for each separate company. There was a handful of major taxpayers on the North Slope, and numerous small producers; each with a different portfolio of fields, exploration, or development activities. Each company would have a different cost structure and tax. Proprietary company information was not allowed to be shared, so the department aggregated total spending and production for the North Slope to illustrate the tax calculation for the purposes of revenue forecasting. Co-Chair Stedman summarized that Mr. Stickel compiled monthly data from multiple companies to combine into an annual calculation. He emphasized that the Revenue Sources Book was working with rounded numbers rather than exact dollar amounts. Mr. Stickel explained that the historical revenue numbers were "cash in the door" to the treasury. When reporting company lease expenditures and tax rates, there was an aggregate calculation. Mr. Stickel spoke to slide 5, "Oil and Gas Revenue Sources": ?Royalty - based on gross value of production o plus bonuses, rents & interest o Paid to owner of the land: State, Federal, or private o Usually 12.5% in Alaska, but rates vary ?Corporate Income Tax based on net income o Paid to State (9.4% top rate) o Paid to Federal (21% top rate, used to be 35%) o Only C-corporations pay this tax * ?Property Tax based on value of oil & gas property o Paid to State (2% of assessed value or "20 mills" o Paid to Municipalities credit offsets state tax paid ?Production Tax based on "production tax value" o Paid to State calculation to follow * "C-corporation" is a business term that is used to distinguish the type of business entity, as defined under subchapter C of the federal Internal Revenue Code. Mr. Stickel clarified that the terms "production tax" and "severance tax" were sometimes used interchangeably. He explained that production tax applied to all production anywhere in the state regardless who the landowner was. 9:14:31 AM Mr. Stickel showed slide 6, "Oil and Gas Revenue Sources 5 year comparison of state revenue," which showed a table that enumerated different revenue sources. He pointed out that the table looked at all state revenue, regardless of which fund the monies went to. Property tax included only the state portion and not the municipal portion. The table illustrated the entire revenue to the state treasury from the oil and gas industry. Mr. Stickel discussed settlements to the state's Constitutional Budget Reserve Fund (CBR), based on settlements of disputes on past years' taxes and royalties. Many of the settlements were several years old. Under the constitution, any mineral assessments or settlements were deposited to the CBR. He furthered that shared revenue from the National Petroleum Reserve was a fairly small revenue source shared with the federal government that was forecast to grow up to $100 million per year in FY 28. Senator Wielechowski asked about FY 17 corporate income tax as listed on the table. Mr. Stickel explained that in FY 16, FY 17 and FY 18; corporate income tax had been artificially reduced due to refunds of prior years' taxes. Co-Chair Stedman asked for Mr. Stickel to elaborate on the matter. He reminded that there had been a reduction in oil price. Mr. Stickel agreed that there was an aggregated number. Within corporate income tax law, there was a provision for a five-year carry back for a net operating loss (NOL). When there was a very low oil price in 2016 and 2017, companies with a NOL were able to offset current year corporate income tax liability as well as carry it back to the five preceding years for tax refunds. The refunds worked through the system, oil prices recovered, and major producers were paying positive tax. He added that the department expected around $200 million per year to be a more stable long-term corporate income tax number around current prices. 9:18:04 AM Co-Chair Stedman asked for further definition of corporate income tax. He thought corporate income tax was controlled by federal law rather than the state and was a different mechanical issue than production tax that was controlled by the state. Mr. Stickel explained the corporate income tax applied to C corporations, which was a term defined under the Internal Revenue Code. He furthered that corporations that were involved in oil and gas production or transportation in the state were subject to oil and gas corporate income tax. The corporations' worldwide net income was calculated, then the amount was apportioned to Alaska based on the state's share of production, sales, and property. He continued that the 9.4 percent was the top marginal tax rate that applied to corporations' Alaska net income. Senator Wielechowski thought hypothetically of a company that made billions of dollars in the State of Alaska, then had a huge oil spill in the Gulf of Mexico which cost billions of dollars. He asked if the company could theoretically pay nothing or very little of corporate income taxes because of worldwide apportionment. Commissioner Tangeman could not speak hypothetically regarding how a tax might be treated. He did not want to make a hypothetical assumption. Senator Wielechowski considered FY 20 and looked ahead at slide 7. He made note of $12.7 billion in production value, with a gross value of the point of production of $9.8 billion. He asked what the 9.4 percent marginal corporate income tax rate was based on. Co-Chair Stedman wanted to bifurcate the subject for further understanding. He explained that corporate income tax was a different structure than the petroleum profit or severance tax. The corporate income tax structure was not controllable by the legislature. 9:22:21 AM Commissioner Tangeman commented that companies had different interests in different parts of the world. He understood Senator Wielechowski's question but did not think it was appropriate to put a percentage to a hypothetical company. Senator Wielechowski thought the state did have a lot of say on the issue and pointed out that the state had made a policy choice to use worldwide apportionment. He was trying to establish what the 9.4 percent income tax was taken from. Co-Chair Stedman asked for definition of the apportionment issue on a broad scale, as well as the alternative. He considered that there had been a policy decision to use apportionment. He asked for historical information. Mr. Stickel stated that the 9.4 percent marginal tax rate was applied to Alaska net income for corporate income tax purposes. The Alaska net income was derived by taking the worldwide net income for a company and apportioning it to Alaska based on the Alaska's share of the company's worldwide production, sales, and property. The concept was known as apportionment methodology. He added that there were a few years in which the state switched to a separate accounting methodology, where a company attempted to calculate its Alaska net income directly. The methodology had been repealed. He thought it would be easy to fill the time of a committee hearing discussing the various provisions of corporate income tax, but that the current presentation was focused on production tax. Senator Micciche asked if the apportionment was only for oil and gas companies, or if it was for any C corporation companies. Mr. Stickel answered in the negative. He stated that oil and gas companies had a different apportionment methodology than for other companies. Other companies calculated its United States "water's edge" net income and then apportioned the amount based on the Alaska share of property, payroll, and sales. 9:25:53 AM Mr. Stickel displayed slide 7, "Production Tax "Order of Operations" FY 2020," which showed a table presenting the income statement table which could be found in the back of the Revenue Sources Book. He specified that the following several slides would address the table. The income statement started with a forecast price of $66/bbl and a daily production forecast of 529.5 thousand barrels per day. He pointed out that FY 20 had 366 days as a leap year, which was reflected in the calculations. The total expected value of all oil produced on the North Slope in FY 20 would be approximately $12.8 billion. The next several slides would focus on where the money went and how it was taxed. Mr. Stickel noted that the table was an aggregation and would not reflect any specific companies' economics or cost structure. He reminded that the data was only for North Slope oil, which was the largest source of production tax revenue in the state. Co-Chair Stedman explained that the table on the slide could be found at the back of the Revenue Sources Book, which could be found on the DOR website. He furthered that the Senate Finance Committee had requested the format to help members and the public keep track of the operation and monies when the state converted to a net profits tax. Mr. Stickel addressed slide 8, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting royalty and taxable barrels. He explained that in calculating production tax, any royalty barrels were subtracted regardless of the ownership of the barrels. The typical rate in the state was one-eighth, which was a 12.5 percent royalty, but the rates varied by unit. In addition to state royalty, federal and private land was subtracted from the taxable barrels. Additionally, the state subtracted any barrels not subject to tax due to being produced in federal waters beyond the state's three-mile limit. A portion of the North Star field, and production from the Liberty field would fall into the category. After subtracting royalty, there was about 172 million taxable barrels in FY 20, for a total value of $11.36 billion. 9:30:00 AM Mr. Stickel highlighted slide 9, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting the calculation of gross value at point of production (GVPP). He mentioned the term "well head value," which was used interchangeably. He noted that GVPP was an important term in the production tax calculation. He explained that to arrive at GVPP, transportation costs (net back costs) were subtracted from the total taxable value. The sales value of the oil (on the West Coast) was established when the oil was delivered, and then the various transportation items were "netted back" to achieve the value at the wellhead. Transportation costs per barrel (or "net back) included marine costs for transport, Trans-Alaska Pipeline System (TAPS) tariffs, any feeder pipeline tariffs were subtracted, and a quality bank differential. He estimated that for FY 20, after subtracting transportation costs, there was a GVPP of about $9.8 billion. Co-Chair Stedman thought the net back was sometimes confusing. Mr. Stickel Tangeman looked at slide 10, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting lease expenditures. The production tax was a modified form of net profits tax. Companies were allowed to deduct capital expenditures and operating expenditures in calculating production tax liability. One major difference in the production tax (as opposed to an income tax) was there was not a depreciation schedule for capital expenditures, and companies were allowed to deduct the entire amount in the year it was incurred. Operating expenditures were essentially any allowable expenses that were not a capital expenditure; such as the ongoing cost of labor, operating a field, and producing oil once a field was up and running. Mr. Stickel stated there was two important terms to define when considering lease expenditures: allowable lease expenditures, and deductible lease expenditures. He specified that allowable lease expenditures were generally any cost in the unit directly associated with producing the oil and was defined in statute. Deductible lease expenditures were developed solely for presentation purposes and was not in statute. Deductible lease expenditures were the share of allowable lease expenditures that was applied in the tax calculation in a given year. A company could apply lease expenditures up to the GVPP, and the amount became the deductible lease expenditures. Any lease expenditures beyond GVPP were considered non- deductible lease expenditures and could be carried forward by the company to apply in a future year. 9:34:55 AM Co-Chair Stedman thought there were some companies that had production that could be deducted, and others that may not have oil production and would not be in the severance tax calculation and would carry forward. Mr. Stickel answered in the affirmative and noted that the lease expenditures listed on the summary were an aggregation of all the different companies doing business on the North Slope. There were some companies that were able to apply all lease expenditures, some companies that had no production carried forward all lease expenditures, and some companies with some production and able to deduct some expenditures and carry some excess lease expenditures forward. All the information was aggregated in the slide. Co-Chair von Imhof looked at non-deductible lease expenditures that were carried forward and asked if the legislature had addressed the matter in 2017 and put a finite amount of time on the carry-forwards. Mr. Stickel stated that the legislature had made changes as to how the lease expenditures were treated. Prior to 2018, the lease expenditures became a tax credit. Beginning in 2018, the lease expenditures became a carry-forward. There was a phase-out provision where the lease expenditures started to deteriorate in 8 or 11 years, depending upon the status of the lease. Co-Chair von Imhof asked about the allowed full deductions of capital expenditures in the year the expenditures occurred; and not allowing depreciation in future years. She thought the policy was a significant accounting choice for capital. She assumed that by not allowing capital to be depreciated over time, net income would be higher in years of production. Mr. Stickel stated that the impact of allowing immediate reduction would be to reduce net income in early years and increase net income in later years. He thought allowance of immediate deduction generally was seen as a benefit to companies. Co-Chair Stedman thought the two expenditure items were included in corporate income tax, and would be subject to amortization and depreciation schedules. Severance tax allowed for immediate deduction, which he thought was standard around the world. It was standard to allow write- offs. He stated that the practice was not abnormal, and the tax percentage was set in Alaska and elsewhere, given the immediate deductions. 9:39:17 AM Senator Shower addressed deductibles. He asked if the items being considered were all state-affiliated, or if the items were mixed with federal items. Mr. Stickel explained that the state deferred to federal definitions for capital expenditures. Commissioner Tangeman added that capital expenditures that occurred in Alaska were being discussed. Senator Shower asked if there was a mix of federal and state regulations at play when discussing deductible operating and capital expenditures. Mr. Stickel stated that the department estimated $4.7 billion of deductible lease expenditures in FY 20. Some of the definitions of what qualified as a capital expenditure versus an operating expenditure relied on federal definitions. Co-Chair Stedman emphasized that severance tax was totally different than corporate income tax. He noted there were decades of Internal Revenue Service rulings on the subject of operating and capital expenditures. Senator Wielechowski discussed depreciation, and thought he heard Mr. Stickel say that depreciation was allowed at 100 percent in the year an expense was incurred. Mr. Stickel answered in the affirmative. Co-Chair Stedman wanted more clarity. 9:42:55 AM Senator Wielechowski thought in other industries in the state, such as an apartment building; an owner did not get 100 percent deduction in the first year, but over many years. He asked if there was any other industry in the state that had the ability to deduct 100 percent in the year the cost was incurred. Mr. Stickel did not want to speculate and offered to provide the information at a later time. Co-Chair Stedman answered Senator Wielechowski's question in the negative. He did not know of any other industry that had a severance tax. He reminded that severance tax and income tax were separate. He stated that there was no instance of deductibility of expenditures not being allowed in severance tax. Senator Wielechowski asked if there was any other state that allowed for 100 percent deductions on expenses for calculation of severance taxes. Mr. Stickel offered to provide the information to the committee. Senator Wielechowski asked if there was any other state that had a net severance tax. Mr. Stickel stated he was prepared to speak to how Alaska's production tax worked. Co-Chair Stedman affirmed that the department could return to speak to a rough outline of tax structures in other states. He stated that Alaska was the only state in the union that owned sub-surface rights of the land. He would be surprised if there was another severance tax in a state that did not own sub-surface rights. Co-Chair von Imhof thought one of the issues of Alaska's uniqueness and the construct of the tax system was due to the state's uniqueness and higher costs. She mentioned the ConocoPhillips form 10K, which had listed the average cost per barrel in various areas in the world and showed Alaska was the highest. She thought in order to get businesses to come to the state, the state's tax system must be equal to costs. Co-Chair Stedman asked members to refrain from comparison and acknowledged the high-cost environment in the state. Co-Chair Stedman asked to direct conversation back to the topic at hand. 9:47:13 AM Senator Wielechowski lamented confidentiality laws that prevented the knowledge of profits per barrel, rates of return per barrel, and costs per barrel. He emphasized that he had been asking for the information for 12 years. He asked if it was possible to get the information and stated he was willing to sign a confidentiality agreement. Co-Chair Stedman stated that the legislature received aggregated information from consultants. The committee had an inability to look at each individual company. Multiple consultants looked at the data and produced figures, and thought the state had substantially more information than previously under a gross tax system. He thought it was possible to extrapolate information on average from the figures that were available. He reiterated that state consultants were in communication with the industry as well as the Department of Natural Resources and DOR to ensure that calculations were accurate. Co-Chair Stedman thought the state understood the range and magnitude of profitability in order to set policy. He stated that there were audits that would be discussed later in the meeting. Severance taxes and royalties were constantly checked for accuracy. He emphasized that while the data was aggregated, it was not fictitious. He would not sign a confidentiality agreement but would set policy using publicly available information. 9:51:23 AM Mr. Stickel showed slide 11, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting production tax value (PTV). He explained that PTV was simply the gross value minus deductible lease expenditures. Aside from the capital expenditure immediate deduction, there was a measure of net profit. He stated that PTV was an important number in tax calculation. He furthered that each company calculated its own PTV based on all its North Slope activity, including all producing fields as well as any exploration and development costs. Each company would have a unique PTV, and a unique PTV per barrel. He summarized that PTV was essentially the tax base for the production tax. Any analysis of productive tax rates, PTV was used as the base. Co-Chair Stedman wanted the public to recognize that PTV was the pile of profit. The amount was gross value less expenditures. Mr. Stickel agreed, and noted that the PTV was before deducting any taxes. Mr. Stickel turned to slide 12, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting gross minimum tax. He explained that there were two calculations done side by side: a net profits tax and a minimum tax that was a tax floor calculation. The minimum tax rate when annual oil prices were greater than $25/bbl was 4 percent of gross value. For FY 20, the minimum tax was 4 percent multiplied times the gross value of $9.8 billion, or about $394 million in aggregate. Mr. Stickel noted that there were two columns for the production tax calculation; one which showed the minimum tax, and one showed the net tax. A company took the higher of the minimum tax or the net tax and apply credits against the amount. Co-Chair Stedman asked if Mr. Stickel's explanation was clear. He had requested a column format for the inclusion of the information in the Revenue Sources Book. He thought there was a significant difference in the calculations when there were low oil prices. 9:55:26 AM Mr. Stickel discussed slide 13, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting net tax calculation and gross value reduction (GVR). The statutory net tax before credits was 35 percent of the PTV, which was the net profit after deducting the costs of operation. For companies with qualifying new production, it was possible to reduce PTV for tax calculation by at the GVR process. The GVR was a new development incentive that allowed companies to exclude 20 or 30 percent of gross value from its PTV calculation. The GVR was an incentive that expired after seven years of production or any three years at greater than $70/bbl oil price. He noted that the amount was relatively small amount currently. The 35 percent tax rate was applied to the PTV net of any GVR. For FY 20, the statutory production tax before credits came to approximately $1.76 billion. The state would take the higher of the minimum tax or the net tax. Senator Micciche asked for Mr. Stickel to explain when the minimum tax would kick in versus the net tax. Mr. Stickel explained that the minimum tax would prevail primarily in times of low oil prices, as it was based on gross value instead of net value. In a situation where price was low or costs were high, a company may have a very small or zero PTV; and it would be subject to the minimum tax and ensure the state received some tax revenue even at low oil prices. Co-Chair Stedman stated that the minimum tax was 4 percent of the wellhead value. Mr. Stickel agreed. 9:58:32 AM Senator Wielechowski observed that the GVR was $128 million on the slide. He asked which fields or projects the reduction applied to. Mr. Stickel specified that the $128 million reduction represented an aggregated number for those companies with a positive PTV that were operating GVR-eligible fields. Senator Wielechowski wondered which fields were considered GVR-eligible and wondered if the fields were considered "new oil." Mr. Stickel answered in the affirmative. He stated that a field qualified for up to seven years of production. He gave examples of Point Thomson, Ugaruk, Nakaitchuq as GVR- eligible fields. Co-Chair Stedman added that the state had highly profitable old fields as well as marginal new fields. The mechanism was to ensure that new fields were not disadvantaged. Commissioner Tangeman answered in the affirmative. He thought there were good examples of the gross value reduction. He mentioned Prudhoe Bay and TAPS. He thought the further east and west from the trunk line, the more costly it was to transport oil. 10:01:01 AM Mr. Stickel referenced slide 14, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting tax credits against liability. The per-taxable-barrel credits were the largest value of tax credits and included two different credits: the 024 "i" and "j" credits. The 024j credits were per-taxable barrel credits for non GVR- eligible production on a sliding scale ranging from zero when wellhead values were over $150/bbl, and up to $8 per barrel wellhead values were less than $80/bbl. At current and upcoming forecast prices, the company would generate the $8 per barrel credit. The credit could not be used to reduce the tax floor of the minimum tax, and companies claiming the credit could not pay below the minimum tax. Mr. Stickel continued to address slide 14. He explained that the 024i credit was a credit for GVR-eligible production, which were newer fields. The fields received a flat $5 per barrel of taxable production credit. The credit could be used to reduce tax below the minimum tax if the company did not take the sliding scale credit. Any per- barrel credits used in the year generated could not be forwarded or transferred; which was also true of the small producer credit. He used the example of FY 20, which had a little over $1.3 billion in per-taxable-barrel credits generated; and there was a little over $1.2 billion were actually applied in the tax calculation. Other credits included small producer credits as well as some prior year credits. Senator Wielechowski asked if there was a breakdown of how many of the per-taxable-barrel credits 024j versus 024i. Mr. Stickel stated that the credits were aggregated for presentation. Senator Wielechowski asked for a breakdown of the credits. Co-Chair Stedman estimated that there was about $140 million on the $5 024i credit, using a percentage of barrel split that was in the Revenue Sources book for FY 20. He thought most of the amount was of the $8 024j credit. Senator Wielechowski asked if it was possible to have a negative tax rate on a field using the 024i tax credit. Mr. Stickel stated that a company may use the $5/bbl credit to bring the tax below a minimum tax if it did not use the sliding scale credit. The tax due would not be less than zero. Co-Chair Stedman stated that a small producer could not apply a severance tax to a negative number, zero was the bottom. Mr. Stickel stated if not taking the sliding-scale credit, a company could use credits to reduce its tax down to zero but not below. For a company taking sliding-scale credits, it could use credits to reduce to the minimum tax but not below. 10:06:30 AM Senator Wielechowski thought a big producer with a very expensive field could also reduce to the minimum tax. He asked if a company could drive its tax rate down to zero, and then use any amount below zero as a carry-forward. Mr. Stickel answered in the negative. If per-barrel taxable credits were not applied in the year they were earned, the credits were forfeit. Co-Chair Stedman recalled that previous legislation had stripped some credits and further hardened the tax floor. Senator Shower asked federal and state interaction, and assumed the slide showed just state taxes. Mr. Stickel answered "yes." Senator Wielechowski recalled a provision that allowed a reduction in the tax rate or GVR allowance on fields that had royalty higher than 12.5 percent. He wondered how the magnitude was affecting the state's production tax. Co-Chair Stedman asked Mr. Stickel to explain the 20 percent and 30 percent GVR. Mr. Stickel stated that there were two different categories of GVR, which was subtracted from production tax calculations. A qualifying new field would get a 20 percent GVR, and 20 percent of the gross value was excluded from the production tax calculation. A higher 30 percent GVR was available if the unit was comprised of entirely state- issued leases of greater than 12.5 percent royalty. Currently no fields met the definition. 10:09:17 AM Mr. Stickel spoke to slide 15, "Production Tax "Order of Operations" FY 2020," which showed a table highlighting adjustments and total tax paid. There were some other items that were added or subtracted from the calculation to arrive at the total production tax revenue received by the state's general fund. There was $43 million in additional revenue for FY 20 that the department was looking at. The funds represented any prior year tax payments or refunds, any revenue from the private landowner royalty tax, hazardous release surcharge, revenue from North Slope gas production, and total Cook Inlet tax liability. The items added up to about $43 million. The total production tax revenue for FY 20 was about $524.7. Co-Chair Stedman asked about the non-deductible carry forward listed on the bottom of the slide. Mr. Stickel noted that for FY 20, there was an estimated $524.7 million in cash into the GF from the production tax system; and an additional $800 million of lease expenditures (largely for explorers and developers) that would be carried forward and potentially used to offset future years' production tax liabilities. Co-Chair Stedman thought that the credits would be used over time until they were timed out as referenced earlier. Mr. Stickel answered in the affirmative. Co-Chair Stedman asked Mr. Stickel to remind the public how long the $800 million of carry-forward would flow forward and phase out if the company did not have production to deduct the expenditure. Mr. Stickel stated that depending upon production status of the property where the lease expenditures were incurred, the carry-forwards would begin to decrease by one-tenth of its value each year after the 8th or 11th year after the expenses were incurred. 10:11:57 AM Mr. Stickel showed slide 16, "Order of Operations 5 year comparison," which showed a table showing an analysis showing a five year spread. The table was an expanded view of the previous slides' analysis to show five years. There was two years of history, the current year, and two years of forecast represented. He pointed out that in FY 17, the state received about $160 million in production tax for the North Slope, on a PTV of about $2.1 billion. Mr. Stickel reported that in the current year, around $700 million in production tax revenue was expected on a PTV of around $6 billion. He remarked that FY 17 was interesting, as all taxpayers had paid the minimum tax or below due to the low price of oil. The total tax after credits was below the minimum tax floor based on companies' specific calculations. Some companies paid at the minimum tax, and some companies were able to take the tax below the minimum to zero. He noted that from FY 18 and beyond, there was a mix where some companies were paying above the minimum tax in each year, and the total tax after credits exceeded the minimum tax. Mr. Stickel continued to address slide 16. He addressed the total non-deductible lease expenditures were listed at the bottom. He commented on increased spending on new fields, with investments in major fields that would yield future production. For FY 17 through FY 19, there was a little more than $300 million per year of lease expenditures that were not deductible against the production tax liability. In FY 20, lease expenditures would be about $800 million; and in FY 21 the amount was forecast to increase to about $1.4 billion. Prior to 2018, the excess lease expenditures turned into a tax credit, and beginning with calendar year 2018 the expenditures were a carry-forward lease expenditure. Senator Wielechowski asked about total tax after credits and asked about the significance of the line below called "other items/adjustments." Mr. Stickel went back to slide 15, which aggregated a number of different items that were not included in the income statement to net out to the total production tax revenue forecast. The items included prior year tax payments, refunds that affected the general fund, private landowner royal taxes, hazardous release surcharges, North Slope gas taxes, and any Cook Inlet tax liability. Co-Chair Stedman had asked the department to show any other deductions to give further clarity to the budget. 10:16:14 AM Senator Wielechowski asked about slide 15, and the $43.4 million in 'Other items/adjustments' listed. He asked if the amount was considered part of the production tax. Mr. Stickel stated that the items were all parts of the production tax and were aggregated in one line for presentation purposes. Senator Wielechowski requested a list of what was included in the aggregated number. Senator Wielechowski asked for a list that encompassed all years. Mr. Stickel stated that the numbers were aggregated to try and condense the table as much as possible. Co-Chair Stedman had wanted the table on one page. Senator Wielechowski asked about effective tax rate on slide 15. He asked if the amount was based off PTV, or taxable barrels. Mr. Stickel stated that when doing effective tax rate analysis, he considered PTV to be the tax base. The effective tax rate for the North Slope production was in the 8 percent to 9 percent range for FY 20. He noted that there was a slide in the addendum that addressed the question. Mr. Tangeman showed slide 17, "Thank you." Mr. Stickel showed slide 18, "Addendum - Follow-up Questions from 3-18-19 Senate Finance Hearing." He explained that the main body of the presentation was concluded, but there were responses to several follow-up questions from a previous committee hearing when the commissioner had presented the revenue forecast. 10:19:19 AM Mr. Stickel looked at slide 20, "Follow-ups from Senate Finance 3-18-19": ?Provide FY20 effective tax rate ?At $66 ANS, estimated average effective production tax rate for non-GVR oil is 8%. Mr. Stickel stated that the slide was in response to Senator Wielechowski's question about the effective tax rate. The effective tax rate was estimated based on aggregated data for non-GVR-eligible production; and was the tax after per-barrel credits divided by the production tax value in the year. There was a chart included to show how the effective tax rate changed with different prices. Co-Chair Stedman reminded that as oil prices went up precipitously, so did capital expenditures and other market forces. He thought the chart depicted general trends of future price changes. Mr. Stickel agreed. Senator Micciche asked if the effective tax rate and the state government take for oil production was the same thing. Mr. Stickel answered in the negative. The effective tax rate was only the production tax itself and the share of production tax value. Total government revenue from the oil industry would include corporate income tax, property tax, and royalties. Mr. Stickel addressed slide 21, "Follow-ups from Senate Finance 3-18-19": ?Provide current Point Thomson feeder pipeline tariff ? As of 1/1/2019, oil produced in Point Thomson is subject to the following feeder pipeline tariffs o $19.490/barrel from the Point Thomson Pipeline* o $1.720/barrel from the Badami Pipeline o $1.300/barrel from the Endicott Badami Connection o Total feeder tariff charge of $22.510/barrel for moving Point Thomson production from the unit boundary to the Trans-Alaska Pipeline (TAPS) * This Point Thomson Pipeline tariff is currently in dispute, the value presented here is the initial Federal Energy Regulatory Commission (FERC) filing that has been disputed Mr. Stickel showed slide 22, "Follow-ups from Senate Finance 3-18-19": ?Provide additional clarification of when pipeline costs are included in netback vs lease expenditures ? Distinction is "point of production" specifically where processed crude passes through the LACT meter ? "Gathering lines" bring unprocessed oil / gas / water to a production facility (upstream of "point of production") o Deductible as lease expenditures in production tax value calculation ? "Feeder pipelines" bring processed crude to TAPS (downstream of "point of production") o Tariffs are regulated by RCA or FERC o Deductible as netback costs in gross value calculation LACT = Lease Automated Custody Transfer; TAPS = Trans- Alaska Pipeline System; RCA = Regulatory Commission of Alaska; FERC = Federal Energy Regulatory Commission 10:22:36 AM Mr. Stickel addressed slide 23, "Follow-ups from Senate Finance 3-18-19": ?Provide estimated amount of credits that were purchased and later adjusted on audit ? For all of the audits performed through tax year 2014, the certificates have already been cashed out. ? A thorough due diligence review has been completed on all 2015 2017 credit applications. COLLEEN GLOVER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE (via teleconference), explained that the slide was a snapshot of the credits that were audited for the 2006 and 2014 tax years. The amount that was disallowed was about $67 million, about $5 million of which upheld in audit. The net difference of $61 million was either paid back to the state, or other credits were used to apply to the amount. Mr. Stickel referenced slide 24, "Follow-ups from Senate Finance 3-18-19": Provide additional clarification of difference between capital (QCE) credits and per-barrel credits ?Two main differences: incentive and monetization ?Incentive: QCE credits provided an incentive for spending; per-barrel credits provide an incentive for production ? Monetization: QCE credits could be applied against tax liability, carried forward, transferred, or sold to the state; per-barrel credits can only be used against liability in the year earned, and are limited by a company's liability before credits and minimum tax floor QCE = Qualified Capital Expenditure Mr. Stickel noted that capital expenditure credits were included in the previous tax regime prior to enactment of SB 21 [oil and gas tax legislation passed in 2013]; and per-taxable-barrel credits were currently used. Co-Chair Stedman asked about the clarification slides that addressed questions form the committee. He encouraged members to work with the department if more detail was needed. ADJOURNMENT 10:26:16 AM The meeting was adjourned at 10:26 a.m.
|032219 2 OGP Credit Audit Update.DOR.3.21.2019.pdf||
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Credit Audit Update
|032219 Order of Operations-DOR.3.21.2019.pdf||
SFIN 3/22/2019 9:00:00 AM