Legislature(2015 - 2016)SENATE FINANCE 532
04/14/2016 05:00 PM FINANCE
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SENATE BILL NO. 130 "An Act relating to confidential information status and public record status of information in the possession of the Department of Revenue; relating to interest applicable to delinquent tax; relating to disclosure of oil and gas production tax credit information; relating to refunds for the gas storage facility tax credit, the liquefied natural gas storage facility tax credit, and the qualified in-state oil refinery infrastructure expenditures tax credit; relating to the minimum tax for certain oil and gas production; relating to the minimum tax calculation for monthly installment payments of estimated tax; relating to interest on monthly installment payments of estimated tax; relating to limitations for the application of tax credits; relating to oil and gas production tax credits for certain losses and expenditures; relating to limitations for nontransferable oil and gas production tax credits based on oil production and the alternative tax credit for oil and gas exploration; relating to purchase of tax credit certificates from the oil and gas tax credit fund; relating to a minimum for gross value at the point of production; relating to lease expenditures and tax credits for municipal entities; adding a definition for "qualified capital expenditure"; adding a definition for "outstanding liability to the state"; repealing oil and gas exploration incentive credits; repealing the limitation on the application of credits against tax liability for lease expenditures incurred before January 1, 2011; repealing provisions related to the monthly installment payments for estimated tax for oil and gas produced before January 1, 2014; repealing the oil and gas production tax credit for qualified capital expenditures and certain well expenditures; repealing the calculation for certain lease expenditures applicable before January 1, 2011; making conforming amendments; and providing for an effective date." 5:35:01 PM KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE, noted the two documents, "Oil and Gas Tax Credit Reform - CSSB 130(RES)" (copy on file), and "Sectional Analysis, CS SB 130(RES)\H: Oil and Gas Tax Credit Reform Bill, April, 13, 2016". He turned to Slide 3 of the presentation, "Oil and Gas Tax Credit Reform - CSSB 130(RES) ": FY 2007 thru 2015, $7.4 Billion in Credits North Slope o $4.3 billion credits against tax liability ƒMajor producers; mostly 20% capital credit in ACES and per-taxable-barrel credit in SB21 o $2.1 billion refunded credits ƒNew producers and explorers developing new fields Non-North Slope (Cook Inlet & Middle Earth) o $100 million credits against tax liability ƒAnother $500 to $800 million Cook Inlet tax reductions ƒ(through 2013) due to the tax cap still tied to ELF o $900 million refunded credits (most since 2013) Mr. Alper turned to Slide four, which detailed historic credits compared to revenue during the period of FY 07 through FY 15: Total Petroleum Revenue FY 2007 thru 2015 North Slope Production Tax - $32.8 billion Royalties (unrestricted) - $15.0 billion Other GF Revenue - $4.7 billion Restricted Revenue - $8.7 billion Total - $61.1 billion Non-North Slope (Cook Inlet & Middle Earth) Production Tax - <$0.1 billion Royalties (unrestricted) - $0.5 billion Other GF Revenue - $0.3 billion Restricted Revenue - $0.2 billion Total - $1.0 billion 5:37:14 PM Mr. Alper noted that the $2.1 billion had been refunded to producers in the form of tax credits; additionally, the $4.3 billion received by the major producers had been in addition to the $61.1 billion as reflected on the slide. He highlighted that the production tax in Cook Inlet had been di minims over the 9 fiscal years. 5:38:07 PM Mr. Alper showed Slide 5, "Historic Credits compared to Revenue", which offered a data set between 2007 and 2015. He related that the Cook Inlet numbers had increased dramatically after the passage of the Cook Inlet Recovery Act, with the biggest numbers occurring in FY 14 and FY 15, and continuing into FY 16. 5:38:45 PM Mr. Alper discussed Slide 6, "Historic and Forecasted O&G Revenue and Tax Credits." He noted that the slide showed the FY 15, FY 16, and FY 17 data set for total unrestricted petroleum revenue. The left side of the slide offered historical and forecasted numbers for petroleum revenues before and net of returnable credits. The right side of the slide included unrestricted petroleum revenue after credits used against tax liability and a blue line indicating net operating loss credits (NOL) end-of-year balance. He noted that as revenue had declined the system had been overwhelmed by credits, which meant that the state was paying a lot out in credits without the revenue to support the payments. He added that the forecasted revenue reflected weak general fund numbers. He said that the NOL credits worked as a sort of bank account for companies; the state would have to pay back the credits as prices went up. He stated that although the price of oil was projected to rise within the next five years, the state would not experience any boost in production tax revenue because the state would be buying down those NOL credits. 5:40:49 PM Senator Bishop asked whether the reigning in of spending by companies would affect future NOLs. Mr. Alper replied that the numbers were tied to the price of oil. He said that anything that companies did to ratchet back capital spending would lower their break-even point and eliminate the NOLs. 5:42:34 PM Vice-Chair Micciche probed the cause of the net negative in only FY 17 reflected on the slide. Mr. Alper responded that the reason was threefold: one reason was the price, another was the work that had been done in anticipation of the sunsetting exploration credits, and the third was the $200 million that had carried forward from FY 16. 5:43:47 PM Vice-Chair Micciche requested Slide number 6, minus Cook Inlet, or North Slope only. Mr. Alper replied that the information would be provided to the committee. 5:44:08 PM Co-Chair MacKinnon asked for the current average price per barrel of oil for 2016. Mr. Alper clarified that she was requesting numbers for the current fiscal year. RANDALL HOFFBECK, COMMISSIONER, DEPARTMENT OF REVENUE, believed that the price was approximately $41 or $42, for the fiscal year. Co-Chair MacKinnon thought the number provided context since past averages had been in the $70s and $90s. 5:45:06 PM Mr. Alper specified that if the reflected price at the end of 2016 was $42, and the department's official forecast was $39/bbl, the $3 represented approximately $80 million. He added that General Fund revenue fluctuated $25 to $30 million for every dollar increase in the price of oil over the course of the year. 5:45:31 PM Mr. Alper looked at Slide 7, "Historic and Forecasted Production Tax and Credits," which mirrored Slide 6, only restricted to the production tax. The numbers below the line of less than production tax revenue had been negative since FY 15. 5:46:17 PM Mr. Alper discussed Slide 8, "Status of Credit Fund Demand for FY16-17," • FY16 Appropriation Capped at $500 million • $473 million paid out to date • About $200 million North Slope, $273 million non-North Slope • $27 million left in fund with $4 million in- process claims • Current DOR Work Pool $675 million • $10 million in older NOL credits • $22 million in older exploration credits • $552 million in 2015 NOL, QCE, WLE credits • $60 million in 2015 exploration credits • $31 million additional 2015 NOL, QCE, WLE expected via amended returns 5:48:29 PM Mr. Alper looked at Slide 9, "Status of Credit Fund Demand for FY16-17", which further detailed the numbers from Slide 8. 5:49:11 PM Mr. Alper moved to Slide 10, "Status of Credit Fund Demand for FY16-17": Status of Credit Fund / Demand for FY16-17 •All the "in hand" applications, if eligible, result in a known demand for FY2017 of $652 million •This is very current information, based on the CY15 tax "true-up" which was due on Thursday 3/31 •Expected credit applications during CY2016, which could also be paid in FY17: •Another $40 million in quarterly requests for QCE and WLE outside the North Slope •Another $60 million in "last minute" exploration claims •About $20 million in LNG storage and refinery claims •Total, matching "final" Spring 2016 forecast, $775 million-slight reduction from $825 million "prelim" 5:50:46 PM Mr. Alper spoke to Slide 11, "Potential NOL Carry-Forward Liability": Growing Carried Forward NOL's: A New Problem • Since the beginning (2007) all companies except the three major producers have been able to receive cash for their tax credits. Majors must "carry them forward" •Companies producing less than 50,000 bbl /day •Hilcorp crossed over this threshold in 2015 • One or more of the majors had an operating loss in 2015. That becomes an NOL credit that can be used against taxes starting this January (to reduce payments below the minimum tax, as far as zero) •This only partly offsets minimum tax payments this calendar year. We still have some positive production tax income. • With the Spring Revenue Forecast, we now see all three majors with much larger losses in 2016, and possibly for years beyond 5:54:16 PM Mr. Alper turned to slide 12, "Potential NOL Carry-Forward Liability," which reflected the Oil and Gas Tax Credit Fund: Budgeted vs. Actual vs. Statutory Tax Credit Fund Transfer Cap (Beginning with the first budget cycle after the passage of ACES in November 2007.) 5:56:43 PM Mr. Alper pointed out that at the current rate, it was forecasted that the state would build an obligation to industry of $2.8 billion by FY 25. He noted that the non- cashable carried-forward liability would be zeroed out by FY 24. He shared that the last column reflected the total state credit obligation. He said that the price forecast listed the e price of oil in FY 18 at $43/bbl, and FY 21 at $60/bbl, which reflected a dramatic jump that would be assumed to have an impact on the state's finances, but that the revenue was only projected to raise from $16 million to $33 million. He said this was because the industry went from having a $750 million balance to only a $265 million balance; there had been a half million dollars in production tax liability that the state did not receive because it had been used to offset the NOL carry forward from prior years. 5:59:09 PM Senator Bishop probed the stackability of the NOLs. Mr. Alper offered an anecdotal scenario involving NOLs. He said that if companies were earning the NOL credits faster than they used them, they would continue to stack up. 6:00:54 PM Senator Bishop referred to the numbers in red on Slide 12. He understood that the fiscal outlook could improve if the price of oil rebounded above $85/bbl. Mr. Alper though that $80/bbl was a good price point and would make a big difference in the budget. 6:02:04 PM Co-Chair MacKinnon wondered how much of a net operating loss could be expected, using the department's current projections, if producers were laying down rigs. Mr. Alper responded that the laying down of rigs by BP had already been built into the forecast. He said that there was a reduction of lease expenditures attached to that, as well as a reduction of wells being drilled and a reduction in future production. He stated that further reduction of work would be captured in the next forecast. He contended that if current prices maintained for another year there would be a continued slowdown. Co-Chair MacKinnon requested that the department run new numbers with the most current projections that included rigs that had recently been shut down. Mr. Alper replied that he would provide the committee with the information. 6:03:52 PM Co-Chair MacKinnon noted Senator Stedman in the committee room. 6:04:07 PM Mr. Alper discussed Slide 13, "Potential Revenue Loss from Reduced Credits": · CSSB130 (RES) does impact project economics · As part of a broader structural reform to Alaska's finances, the state will be in a better position to meet the credit obligations it does have and provide a more stable fiscal climate overall. · DOR cannot predict specific projects that may be accelerated or deferred as a result of CSSB 130 (RES) or other fiscal reforms · Testimony by others has compared the impact of SB 130 to total royalty revenue received by the state · The following table shows how those two amounts compare under the Spring 2016 revenue forecast · By the final year of the fiscal note, the midpoint impact of CSSB 130(RES) represents approximately 14% of anticipated petroleum revenue 6:05:42 PM Mr. Alper looked at Slide 14, "Potential Revenue Loss from Reduced Credits": Production would have to drop by an additional 9% for the cost to the state from lost royalties to exceed the benefit of the bill. In 2022, this would mean about 35k bbl / day • This assumes that the "lost" production would pay taxes and royalties at the same rate as average production; more likely the marginal projects would pay less • Also, much of the fiscal impact of CSSB130 is specific to Cook Inlet, where revenue per barrel is substantially less He noted that the slide contained a table that included the estimated fiscal impact from the current bill version versus the spring 2016 total petroleum revenue forecast. 6:06:52 PM Vice-Chair Micciche summarized the numbers on Slides 3 and 4. He asserted that the fiscal picture on the North Slope was very different than that of Cook Inlet. 6:07:58 PM Mr. Alper agreed. He thought that Cook Inlet was likely unsustainable, and that companies would react negatively to the unsustainability of the area. 6:08:32 PM Co-Chair MacKinnon had heard the commissioner make statements about the success in Cook Inlet. She asserted that the Cook Inlet was energizing 60 percent of the state. She wondered if there was any data to support the assertion that activity in Cook Inlet was unsustainable. Mr. Alper explained that a fiscally constrained state could not maintain the activity indefinitely. 6:09:56 PM Commissioner Hoffbeck interjected that cycling contracts were being negotiated and discussions were underway for contracts out to 2023, and beyond. He said that he had not heard urgent discussion as to whether gas would be available when it was time to put it under contract, but that some of it was yet to be under contract. 6:10:48 PM Co-Chair MacKinnon agreed that the state did not have the cash flow to support the existing tax credits, but was concerned that the overall region in 10 or 15 years would need to import gas. Commissioner Hoffbeck said that normal practice was to have a 10 year supply or less on the books because it did not make sense for a company to go out and develop a field that could not be monetized for 10 years. He thought that uncertainty would always be part of the equation. 6:12:09 PM Co-Chair MacKinnon understood that companies liked to carry large reserves on their books because it helped with financing. Commissioner Hoffbeck replied that that was true. He added that companies could delineate the field, and know what the reserves were, without actually developing and delivering product. 6:12:34 PM Vice-Chair Micciche lamented that striking a balance between credits and supply would be challenging. 6:13:22 PM Mr. Alper turned to Slide 15, and stated that he would be discussing the "greatest hits" pertaining to the subject. 6:14:11 PM Mr. Alper turned to Slide 16, "Credit Cost in Perspective": Of the $3 billion in state-refunded credits through the end of FY15: • $1.45 billion went to six North Slope projects that now have production • $650 million went to 13 North Slope projects that do not have any production. Some of these are abandoned, and some are in process • $450 million went to six non-North Slope projects that have production • $450 million went to eight non-North Slope projects that do not have any production 6:15:14 PM Mr. Alper looked at Slide 17, "Credit Cost in Perspective": North Slope Refundable Credits Of the $1.45 billion that was spent between FY07- FY15 supporting six producing projects: • Total production through end of FY15 is 38.5 million barrels • Total credits = $37.30 / barrel • This number will decrease over time due to additional production from these fields • Lease expenditures for these projects, through FY15, were $4.94 billion • Credit support was 29% of lease expenditures 6:15:51 PM Mr. Alper reviewed Slide 18, "Credit Cost in Perspective": Cook Inlet Refundable Credits Of the $450 million that was spent between FY07- FY15 supporting six producing projects: • Total production through end of FY15 is 55.9 million BOE (much of this was gas) • Total credits = $7.80 / BOE or about $1.30 / mcf • This number will decrease over time due to additional production from these fields • Lease expenditures for these projects, through FY15, were $1.09 billion • Credit support was 40% of lease expenditures 6:16:56 PM Mr. Alper spoke to Slide 19, "Credit Cost in Perspective," which was a continuation of Slide 18: Cook Inlet Tax Caps •Estimated value to industry $550-$850 over the years 2007-2013 •Total Production Estimate •Gas: ~ 250 million cubic feet / day for seven years = 640 BCF of gas or 106 million BOE •Oil: ~ 10,000 barrels / day for seven years = 26 million BOE •Total Production = 132 million BOE •Using midpoint $700 million estimate, value of caps = $5.30 / barrel or $0.88 / mcf •Sum of Credits + Tax Caps: $2.18 / mcf 6:18:05 PM AT EASE 6:19:13 PM RECONVENED Mr. Alper stated that the previous slides were the best available information that the department could provide within the bounds of confidentiality. Mr. Alper showed Slide 21, "Key Provisions and Decision Points": Preventing certain credits from being used against the minimum tax, or "floor" This is really three different issues / policy questions All of these only pertain to the North Slope: 1) Net Operating Loss for producers not eligible for refundable credits (should major producers be able to go below the floor?) 2) Per-Barrel Credits for GVR "New" Oil (should the tax on production from new fields be allowed to go to zero? Relation to GVR "graduation?") 3) Small Producer / Exploration Credits (should everyone, not just major producers, pay a minimum tax?) 6:21:22 PM Mr. Alper looked at Slide 22, "Key Bill Provisions and Decision Points": Repurchase Limits Historic Notes on large annual credits: Over the 2007-2016 history of the tax credit program: · There has only been one instance of a company who ever received > $200 million in a single year · Five times ever when one company received between $100 - $200 million in one year · 11 times ever when one company received between $50 - $100 million in one year 6:22:56 PM Mr. Alper looked at Slide 23, "Key Bill Provisions and Decision Points": To-date cost of Sunsetting Credits Exploration Credits (various) 2007-sunset • North Slope Refunded: $270 million • North Slope Against Liability: $190 million • Non-North Slope Refunded: $160 million • Non-North Slope Against Liability: $0 Small Producer Credits 2007-2016 • North Slope Against Liability: $340 million • Non-North Slope Against Liability: $60 million • (these cannot be refunded) Total: slightly over $1 billion Mr. Alper offered to cut the presentation short in order to make time for the sectional analysis. Co-Chair MacKinnon responded that he could take the next 35 minutes to finish the presentation; the sectional analysis could be heard on another day. 6:24:58 PM Mr. Alper turned to Slide 25, "Overview of Tax and Credit Calculations": How the Production Tax Works at $100 oil Tax on a single barrel of taxable North Slope oil. We currently have about 160 million taxable barrels/year Market Price $100 Transport Cost $10 Gross Value $90 Lease Expenditures $35 Production Tax Value $55 Tax @ 35% $19.25 Per-Barrel Credit $6.00 Net Payment $13.25 Minimum Tax Gross x 4% $3.60 Higher Of (Actual Tax) $13.25 Approx. Annual Revenue $2.1 billion Mr. Alper noted that the modeled calculation was what the Legislature had envisioned when SB 21 was enacted. 6:27:16 PM Mr. Alper moved to Slide 26, "Overview of Tax and Credit Calculations": At $70 Oil, the "minimum tax" takes over Market Price $70 Transport Cost $10 Gross Value $60 Lease Expenditures $35 Production Tax Value $25 Tax @ 35% $8.75 Per-Barrel Credit $8.00 Net Payment $0.75 Minimum Tax Gross x 4% $2.40 Higher Of (Actual Tax) $2.40 Approx. Annual Revenue $380 million 6:28:31 PM Mr. Alper moved to Slide 27, "Overview of Tax and Credit Calculations": At $40 Oil, producers have operating losses Market Price $40 Transport Cost $10 Gross Value $30 Lease Expenditures $35 Production Tax Value ($5) Approx. Operating Loss $800 million Tax @ 35% ($1.75) Per-Barrel Credit $8.00 Net Payment ($9.75) Minimum Tax Gross x 4% $1.20 Higher Of (Actual Tax) $1.20 Approx. Annual Revenue $190 million Carried Forward Loss Credit 35% $280 million 6:30:02 PM Mr. Alper moved to Slide 28, "Overview of Tax and Credit Calculations": $40 for second year means Operating Loss credits can be used to reduce payments below the minimum tax Year 1 Year 2 Market Price $40 $40 Transport Cost $10 $10 Gross Value $30 $30 Lease Expenditures $35 $35 Production Tax Value ($5) ($5) Approx. Operating Loss $800 million $800 million Tax @ 35% ($1.75) ($1.75) Per-Barrel Credit $8.00 $8.00 Net Payment ($9.75) ($9.75) Minimum Tax Gross x 4% $1.20 $1.20 Higher Of (Actual Tax) $1.20 $1.20 Approx. Annual Revenue $190 million $190 million Less Carried-Forward Loss Credit ($190 million) Actual Tax Payment $190 million $0 Carried-Forward Loss Credit 35% $280 million $370 million 6:31:10 PM Co-Chair MacKinnon asked how much of a percentage of the operating losses could be attributed to personnel. Mr. Alper responded that he did not know. Co-Chair MacKinnon requested that he provide the information to the committee at a later date. She felt that the job losses were not reflected in the slides and were one of the largest cost drives to the state. She requested details concerning the drivers inside of the net operating cost for companies, and how the department had determined the static numbers included in the presentation. Mr. Alper pointed out to the committee that the department had used $45 - $46/bbl as a working average cost, and noted that there had been a 10 percent increase in company costs within the last year. He said that those efficiencies and reductions involved people who would have been building and doing things, and whatever it was that they were going to build the equipment and materials associated with that work had also fallen off the expense profile. 6:33:08 PM Co-Chair MacKinnon requested any information that the administration could provide concerning the cost set into a non-static plan. Mr. Alper agreed to provide the information to the committee. 6:33:40 PM Mr. Alper looked at Slide 30, "Introduction to Scenario Analysis": · The Tax Division has developed a new model, looking at project life cycles · Cash flow over the 30-40 year life of a project, for the state's production tax and credits, all state revenue, the producer's cash flow, and discounted (NPV) · Scenarios Analyzed at $40, $60, $80, and Fall Forecast oil price · Status quo modeled vs. Governor's original bill · Full modeling runs can be provided as a separate document Mr. Alper noted that there were longer presentations that included different runs of how the model worked. He said that the scenario had been developed in response to questions from individual legislators. Mr. Alper spoke to Slide 31, "Introduction to Scenario Analysis": Fields Analyzed: North Slope Oil Scenarios • 50 million barrel • 750 million barrel (12.5% Royalty / 20% GVR) • 750 million barrel (16.67% Royalty / 30% GVR) • 750 million barrel (50% Private Royalty) Cook Inlet Oil Scenarios • 50 million barrel (tax caps sunset) • 50 million barrel (tax caps extended) Gas Scenarios • 670 bcf Cook Inlet Gas (tax cap sunset and extended) • 670 bcf Middle Earth Gas 6:38:22 PM Mr. Alper spoke to Slide 32, "Sample of Scenario Analysis," which showed numbers for the smaller field on the North Slope at $60/bbl. He noted that the upper left corner chart reflected solely the production tax and the credits. He spoke to the graph in the upper right hand corner, which reflected the annual state net gains and losses, with 20 percent GVR, at $60 and price. The lower left chart illustrated the total producer cash flows from the company's point of view, and the lower right listed the life cycle totals for the field. He pointed out that the top four lines showed the production tax numbers, the middle four reflected the all-state revenue, and the bottom four lines showed the producer credits. 6:42:44 PM Mr. Alper discussed Slides 33 through 37, which offered scenario analysis on North Slope and Cook Inlet fields using various tax structures and varying per barrel prices. 6:48:01 PM AT EASE 6:48:24 PM RECONVENED Mr. Alper pointed out that by pushing the credit spend into future years the state was paying the credits over a longer period of time; for some of those years the state was getting revenue from royalties while simultaneously receiving the credits, which reduces the credit spend. 6:49:02 PM Co-Chair MacKinnon asked whether a $25 million cap per organization that was driving multiple partners together, and could create a diversity of revenue, might also slow progress. Mr. Alper stated that the department had presumed that entities would partner up on projects. He said that the $25 million number had been pulled from history, when the state had first ventured into the credit repurchasing business. 6:50:25 PM Mr. Alper spoke to Slide 37, "Sample of Scenario Analysis," and noted that the slides reflecte3d little difference than the North Slope except that there was no production tax. 6:51:43 PM Mr. Alper looked at Slide 38, which reflected the numbers after the implementation of SB 130. He stated that the department could come up with hundreds of similar scenarios to examine. 6:52:41 PM Co-Chair MacKinnon appreciated the testifiers' ability to articulate the administration's position. SB 130 was HEARD and HELD in committee for further consideration. Co-Chair MacKinnon discussed the schedule for the following day.
|SB 130 DOR Additional Info for SFIN 4-14-16 final.pdf||
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|SB 130 Sectional CSSB130(RES) Oil Credit Bill 4-14-16 final.pdf||
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