Legislature(2019 - 2020)BARNES 124
04/22/2019 01:00 PM House RESOURCES
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Presentation(s): Alaska's Oil and Gas Tax Regime by the Department of Revenue | |
HB122 | |
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* first hearing in first committee of referral
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+= | HB 122 | TELECONFERENCED | |
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ALASKA STATE LEGISLATURE HOUSE RESOURCES STANDING COMMITTEE April 22, 2019 1:03 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 Sara Rasmussen MEMBERS ABSENT Representative Chris Tuck Representative George Rauscher OTHER LEGISLATORS PRESENT Representative DeLena Johnson COMMITTEE CALENDAR PRESENTATION(S): ALASKA'S OIL AND GAS TAX REGIME BY THE DEPARTMENT OF REVENUE - HEARD HOUSE BILL NO. 122 "An Act relating to the Funter Bay marine park unit of the state park system; relating to protection of the social and historical significance of the Unangax cemetery located in Funter Bay and providing for the amendment of the management plan for the Funter Bay marine park unit; and providing for an effective date." - MOVED HB 122 OUT OF COMMITTEE PREVIOUS COMMITTEE ACTION BILL: HB 122 SHORT TITLE: FUNTER BAY MARINE PARK: UNANGAN CEMETERY SPONSOR(s): REPRESENTATIVE(s) HANNAN 04/03/19 (H) READ THE FIRST TIME - REFERRALS 04/03/19 (H) RES, FIN 04/15/19 (H) RES AT 1:00 PM BARNES 124 04/15/19 (H) Heard & Held 04/15/19 (H) MINUTE(RES) 04/17/19 (H) RES AT 1:00 PM BARNES 124 04/17/19 (H) -- MEETING CANCELED -- 04/22/19 (H) RES AT 1:00 PM BARNES 124 WITNESS REGISTER DAN STICKEL, Chief Economist Tax Division Department of Revenue Juneau, Alaska POSITION STATEMENT: Provided a PowerPoint presentation entitled, "Alaska Oil and Gas Production Tax Calculation ("Order of Operations"), revised from 4-15-19 version" and answered questions. BRUCE TANGEMAN, Commissioner Department of Revenue Juneau, Alaska POSITION STATEMENT: Answered a question during the PowerPoint presentation entitled, "Alaska Oil and Gas Production Tax Calculation ("Order of Operations"), revised from 4-15-19 version." ACTION NARRATIVE 1:03:01 PM CO-CHAIR JOHN LINCOLN called the House Resources Standing Committee meeting to order at 1:03 p.m. Representatives Hannan, Rasmussen, Hopkins, Tarr, and Lincoln were present at the call to order. Representatives Spohnholz and Talerico arrived as the meeting was in progress. Also present was Representative Johnson. ^PRESENTATION(S): ALASKA'S OIL AND GAS TAX REGIME BY THE DEPARTMENT OF REVENUE PRESENTATION(S): ALASKA'S OIL AND GAS TAX REGIME BY THE DEPARTMENT OF REVENUE 1:03:17 PM CO-CHAIR LINCOLN announced the first order of business would be a continuation of the Department of Revenue presentation that was previously heard on 4/15/19. 1:03:42 PM DAN STICKEL, Chief Economist, Tax Division, Department of Revenue (DOR), provided a PowerPoint presentation entitled, "Alaska Oil and Gas Production Tax Calculation ("Order of Operations"), revised from 4-15-19 version." Mr. Stickel noted slides 1-15 were reviewed at the previous hearing and directed attention to slide 16, which was a five-year comparison of the production tax calculation for North Slope oil and gas from fiscal year 2017 (FY 17) through the forecast for FY 21. In FY 17, all companies were paying at or below the gross minimum tax; in FY 18, some companies paid above the minimum tax; beginning in FY 19, several major producers are forecast to pay above the minimum tax through FY 21. He said that was the conclusion of the original presentation. 1:06:17 PM MR. STICKEL continued to the first addendum to the presentation entitled, "FY 2020 Distribution of Cash Flows." Slide 19 was an analysis of the distribution of cash flows from North Slope oil production, also known as "government take" or "company take." The basis for the analysis is cash flows to industry after subtracting transportation costs and lease expenditures. He explained the analysis was modeled two ways: on a typical non- gross value reduction (non-GVR) eligible field and on all North Slope production and spending. Slide 20 was the model on typical non-GVR production and outlined the assumptions made by DOR which he described as follows: FY 2020 data for the Spring 2019 revenue forecast; a single company; all non-GVR production. He pointed out this most recent analysis reflects change to the federal corporate income tax rate from 35 percent to 21 percent. Slide 21 was revised from the original version and illustrated the typical cash flow from one barrel of non-GVR production based on an Alaska North Slope (ANS) price of $66 per barrel: costs represent approximately one-half of the value; the state and municipalities get approximately 35 percent; the federal government gets approximately 13 percent; producers get approximately 51 percent. Revisions to the previous slide were based upon the change to the federal corporate income tax and on improved economics. Slide 22, also revised from the previous presentation, illustrated government take at a range of prices; the percentage of government take is higher at lower oil prices. 1:11:31 PM MR. STICKEL explained slide 23 is a model similar to that shown on slide 21, except looking at all slope/industrywide production and costs, including special tax provisions for new fields, and including companies that have exploration and development and thus are not currently paying tax. Slide 24 - in a manner similar to slide 21 - illustrated the typical cash flow from one barrel of oil using all slope/industrywide production: the state and municipalities get approximately 38 percent; the federal government gets approximately 13 percent; producers get approximately 49 percent. Slide 25 - in a manner similar to slide 22 - illustrated government take at a range of prices, using all production and development costs. In this case, at low prices, government take is more than 100 percent of profit due to gross value-based royalty, and minimum production tax and property tax offsetting a smaller amount of cash flow. Mr. Stickel explained DOR is forecasting significant increased industry spending on new developments which will exacerbate the indicated trend. 1:14:08 PM REPRESENTATIVE HANNAN asked for clarification of the aforementioned trend. MR. STICKEL returned attention to slide 22, which indicated the percentage of government take is higher at lower prices when looking at North Slope industry as a whole; DOR is forecasting additional capital expenditures from FY 21-FY 24 thus the total distributable income will be smaller; however, state royalty and property tax are fixed costs. REPRESENTATIVE HANNAN surmised one field is on federal land in the National Petroleum Reserve-Alaska (NPR-A) and inquired as to whether the state only gets royalty from production on federal land. MR. STICKEL said production tax applies to all state land within the state boundaries and offshore up to the three-mile limit. The state gets a share of royalty which will be explained in the following addendum. He continued to the second addendum entitled, "Follow-up from 4-15-19 House Resources Hearing." Slide 27 listed questions from the committee posed during and following the previous hearing. Slide 28 was a map of NPR-A and listed municipalities therein. Slide 29 provided information on state share of royalties regardless of who owns the land and which taxes apply. He pointed out production tax, corporate income tax, and property tax all apply to all land within the state and offshore out to the three-mile boundary, regardless of who owns the land. In addition, lease expenditures within said boundary are deductible for production tax purposes. For purposes of royalty, beyond the six-mile limit is the federal offshore continental shelf (OCS) where federal royalties apply, and the state receives nothing. Between three miles and six miles [offshore], 27 percent of federal royalties is shared back to the state without restriction; for example, the Liberty offshore oilfield, the federal portion of the Northstar field, and some new exploration will be in [the 27 percent] category. Mr. Stickel further explained state lands and offshore from zero to three miles have state royalties at various ranges: within NPR-A a federal royalty applies with 50 percent back to the state with restrictions; in the Arctic National Wildlife Refuge (ANWR), federal royalty applies with 50 percent back to the state without restriction; on other federal land, federal royalties apply with 90 percent back to the state without restriction; on private land, including land owned by Alaska Native corporations, royalties apply to the lease, and the state levies a 5 percent (for oil) or 1.667 percent (for gas) gross tax on the value of private landowner royalty interest as part of production tax. 1:20:54 PM MR. STICKEL continued to slide 30, which illustrated the royalty rate for the Liberty oilfield: three separate federal leases at a 12.5 percent royalty rate, with 27 percent back to the state, or 3.375 percent of the value of production. He noted the state would not receive tax revenue, "unless the development were to result in a taxable event inside the three-mile limit, so [an] example would be a pipeline bringing oil onshore, [that] would be subject to property tax ...." 1:22:29 PM [Due to technical difficulties, an at-ease was taken from 1:22:29 p.m. to 1:23:06 p.m.] MR. STICKEL read from slide 31 which summarized information about allowable lease expenditures for production tax purposes under AS 43.44.165. REPRESENTATIVE HANNAN questioned whether carry forward expenditures transfer with the lease if the lease is sold. MR. STICKEL was unsure and offered to provide the requested information. CO-CHAIR TARR directed attention to operating expenses and surmised employee expenses, such as salaries, are considered allowable lease expenditures. 1:26:42 PM MR. STICKEL said yes, as long as the costs are upstream, ordinary and necessary, and direct costs of production. Slide 32 provided information on how multi-year expenditures are treated in the production tax calculation. Lease expenditures are based on when the cost is incurred in one of the two following situations: 1.) If a producer is also the unit operator, costs are incurred when they are expensed or capitalized for tax accounting purposes; 2.) If there are multiple producers, the costs are incurred when they are billed to the working interest owners. Slide 33 was a graph that provided the components of netback costs including the Trans- Alaska Pipeline System (TAPS) tariff. He clarified the Feeder [pipeline] Tariff component is a weighted average of all production on the North Slope, and the Quality Bank component is negative due to the impact of state refineries that pay into the Quality Bank. MR. STICKEL, in response to Co-Chair Tarr, provided a brief explanation of how oil of various qualities is mixed in TAPS thus the end product is of a consistent quality that may be higher or lower than what a producer put into TAPS; the Quality Bank is an accounting mechanism to adjust for the quality of the crude oil. The refineries along TAPS pay a charge to the Quality Bank because they take out higher quality oil. REPRESENTATIVE HANNAN asked for the location and ownership of the refineries, and why the Quality Bank credits are forecast to increase. MR. STICKEL said he would provide detailed information to explain the increases in Quality Bank credits that are shown on slide 33; the refineries are in the Fairbanks area. REPRESENTATIVE HANNAN restated her question. 1:32:59 PM REPRESENTATIVE TALERICO said Petro Star has a refinery in North Pole. REPRESENTATIVE HOPKINS asked whether the TAPS Tariff is consistent for all of the producers and shippers using the pipeline. MR. STICKEL advised each TAPS owner sets its own tariff; the tariffs claimed by companies are slightly different; therefore, the TAPS Tariff shown on slide 33 represents a weighted average. REPRESENTATIVE HOPKINS surmised the three TAPS owners pay themselves a tariff and then deduct it; a company that is not an owner pays the tariff to the owners and claims a deduction. MR. STICKEL said correct and pointed out there are four owners of TAPS. CO-CHAIR TARR posited Feeder Tariffs are quite a bit larger for some developments such as Point Thomson, because of the expense of the feeder line needed to connect to TAPS. For other "far away" developments, the total transportation cost may affect the economics of the project. MR. STICKEL said DOR expects much of the new production [from developments on the slope] to have higher feeder pipeline tariffs. In further response to Co-Chair Tarr, he estimated feeder pipeline tariffs for Point Thomson are between $10 and $20 and offered to provide additional information. He read from slide 34 information about feeder pipelines and TAPS. REPRESENTATIVE HOPKINS asked whether the higher feeder pipeline tariffs for Point Thomson are due to its distance from TAPS and the central processing facilities. MR. STICKEL responded the oil must travel a long distance from Point Thomson to infrastructure on the North Slope; also, current production is low. 1:39:02 PM CO-CHAIR TARR has heard one of the challenges for smaller operators is access to TAPS and other existing infrastructure, even though there are regulations that seek to prevent a pipeline carrier from discriminating. She questioned whether Alaska's tax system benefits the owners of TAPS - the companies that set the tariffs - and limits the economics of companies that are not owners. MR. STICKEL explained [tax benefits] from feeder pipelines differ from those that affect a gathering line in that a gathering line is upstream of production and transports oil from the wells to production facilities located on the leased land. Costs of developing gathering lines are allowable lease expenditures against production tax; however, a feeder pipeline is downstream of the point of production and the costs of building a feeder pipeline are not immediately deductible but will be deducted over time through the tariff. He read from slide 35 related to the costs to Alyeska Pipeline Service Company for the maintenance and operation of TAPS. He restated each TAPS owner sets a tariff that is subject to regulation by the Regulatory Commission of Alaska, or by the Federal Energy Regulatory Commission, and three of the owners are active carriers. 1:43:33 PM MR. STICKEL continued to slide 36, which was a graph that illustrated effective production tax rates since the enactment of Senate Bill 21 [passed in the Twenty-eighth Alaska State Legislature]. The graph showed estimated effective tax rates at a range of prices for FY 20. The analysis is based on aggregated data for non-GVR eligible production, calculated as tax after taxable per-barrel credits and divided by total production tax value; in FY 20, the effective tax rate on non- GVR oil is estimated to be approximately 8 percent. He pointed out at ANS prices below $65 per barrel, companies pay a gross minimum tax and state take is a relatively higher share of profit; at ANS prices above $65 per barrel, state take is a relatively higher share under net tax. He noted current oil prices put the tax rate at the "crossover point" of 8 percent. REPRESENTATIVE HOPKINS surmised at an oil price of $72 per barrel, the estimated effective tax rate would be at the lowest point of Alaska's tax scheme. 1:45:56 PM MR. STICKEL said if in FY 20, oil prices average in the low 70 [dollars per barrel], the effective tax rate on production tax value would be in the range of 10-15 percent. On slide 37, DOR modeled the effective tax rate for a typical non-GVR field and applied it back to the time of the enactment of Senate Bill 21. He pointed out the relationship between the effective tax rate and ANS price: in FY 18, the rate was about 8 percent, near the crossover point; in FY 14, after Senate Bill 21 took effect, and the higher tax rate was due to higher prices and higher profits; in FY 16, the higher tax rate was due to a gross tax and lower profits and prices. He concluded FY 14 and FY 15 were two years of net tax, FY 16 and FY 17 were two years of gross tax, and the average effective tax was approximately 24 percent. CO-CHAIR TARR pointed out slides 36 and 37 illustrated how closely Alaska's tax system is linked to the price of oil; in fact, legislative consultants have advised this link is the cause for fluctuation in the tax system. She related at high oil prices companies make more investments, and when prices fall, as in 2014, there is a gradual adjustment to lower activity which is not reflected until later years. She asked Mr. Stickel to comment. MR. STICKEL acknowledged company spending has been reduced in response to lower oil prices. He returned attention to slide 36 and said the state has made a policy decision to take a higher share of profits at certain prices and a lower share at other prices. 1:50:19 PM CO-CHAIR TARR opined if companies responded by reducing lease expenditures more quickly in 2016, the overall effective tax rate would have stayed lower. She urged the state to re- evaluate the link to oil price. MR. STICKEL agreed the price of oil has a tremendous impact on the state and on producers; in FY 16, many companies lost money and the 61 percent effective tax rate in FY 16 represents only production tax as a share of production tax value. In fact, additional information will be presented to show that other elements of government take increased the state's share. He turned to the question of total state take since enactment of Senate Bill 21 and said slide 38 illustrated distribution of profits estimated for FY 20 for a barrel of oil produced from a typical non-GVR field and for slope/industrywide analysis with all production and costs; slide 39 illustrated estimated share of cash flow for a typical non-GVR field and for slope/industrywide analysis with all production and costs over the last five years. Mr. Stickel noted in FY 14-FY 15 government and producer take are similar: in FY 16, state and municipalities take [slope/industrywide with all production and costs] was over 100 percent of the cash flow and profit generated on the North Slope; in FY 17, there was some recovery in oil prices, lower spending, and major producers made some profit; in FY 18, there was low production tax revenue due to the effective tax rate, reduced federal corporate federal income tax, and thus increased producer take. 1:55:34 PM CO-CHAIR TARR referred to slide 39 and asked DOR to provide an additional column to show royalty revenue separately from that of production tax. She returned attention to slide 11 and recalled consultants urged the committee to review production tax value: in a true net profits system the production tax value represents the value after all expenditures have been deducted. She asked whether DOR is evaluating other [tax regime] options at this time. 1:57:54 PM BRUCE TANGEMAN, Commissioner, Department of Revenue, asked Co- Chair Tarr to repeat her question. CO-CHAIR TARR elaborated on her earlier question in regard to problems created by the link between Alaska's oil and gas tax system and the price of oil, compared to a true net profits tax system. She suggested the current tax system also creates an ongoing audit problem and restated her question as to whether DOR was considering other options. COMMISSIONER TANGEMAN said the biggest issue [creating the backlog] of audits was that DOR was auditing several different tax structures, which slowed progress. However, the state has maintained a "consistent/stable tax regime for the last several years," and DOR plans to return to a three-year audit schedule. To the question as to whether DOR is exploring changes, he said from a policy perspective, Senate Bill 21 has increased production in consecutive years for the first time in 30 years and will provide stable production for another 10 years. He said Alaska's goal should be a stable, predictable, competitive tax regime, which has been achieved by Senate Bill 21, and noted other states such as Texas, California, Colorado, and New Mexico have not made changes to their tax structures since 2004. Commissioner Tangeman concluded all of Alaska's competitors compete for investment at varying oil prices. 2:02:54 PM The committee took an at-ease from 2:02 p.m. to 2:05 p.m. HB 122-FUNTER BAY MARINE PARK: UNANGAN CEMETERY 2:05:46 PM CO-CHAIR LINCOLN announced the final order of business would be HOUSE BILL NO. 122, "An Act relating to the Funter Bay marine park unit of the state park system; relating to protection of the social and historical significance of the Unangax cemetery located in Funter Bay and providing for the amendment of the management plan for the Funter Bay marine park unit; and providing for an effective date. REPRESENTATIVE HANNAN, speaking as the sponsor of HB 122, directed attention to a memorandum included in the committee packet incorrectly dated 5/16/19, which should read 4/16/19. She said the memorandum answers questions raised at the first hearing of the bill on 4/15/19. Also included in the committee packet was another version of a map entitled, "Funter Bay State Marine Park" which illustrated the existing Funter Bay State Marine Park in a bold outline. Representative Hannan pointed out most of the park is over water with a portion on land in Coot Cove; the recommendation by the Department of Natural Resources was to add acreage, including the cemetery, and create a contiguous parcel. In addition, Ledge Island is not always above water and would also be included in the marine park. 2:09:21 PM CO-CHAIR TARR moved to report HB 122 out of committee with individual recommendations and the accompanying fiscal notes. There being no objection, HB 122 was reported from the House Resources Standing Committee. 2:10:22 PM ADJOURNMENT There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 2:10 p.m.