Legislature(2015 - 2016)BUTROVICH 205
04/06/2016 03:30 PM RESOURCES
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|Dor Second Presentation: Additional Modeling and Scenario Analysis|
* first hearing in first committee of referral
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SB 130-TAX;CREDITS;INTEREST;REFUNDS;O & G [Contains discussion of companion bill HB 247.] 3:30:48 PM CHAIR GIESSEL announced consideration of SB 130. The committee would first hear from the Department of Natural Resources followed by the Department of Revenue (DOR). She invited Dr. Paul Decker, Petroleum Geologist, and Alex Nouvakhov, Commercial Analyst, both with the Division of Oil and Gas, Department of Natural Resources (DNR), to testify via teleconference. 3:31:47 PM SENATOR STOLTZE joined the committee. ^DNR Overview 3:31:54 PM PAUL DECKER, Petroleum Geologist, Resource Evaluation Team, Division of Oil and Gas, Department of Natural Resources (DNR), Anchorage, Alaska, introduced himself. ALEX NOUVAKHOV, Commercial Analyst, Commercial Section, Division of Oil and Gas, Anchorage, Alaska, introduced himself. MR. DECKER said his slides and presentation are an overview of oil and gas industry activity in Alaska today and how the tax credits interact with the Department of Revenue. 3:32:59 PM SENATOR MICCICHE joined the committee. MR. DECKER said slide 2 looks at the North Slope, Cook Inlet, and the Interior basins that are sometimes called Frontier basins. The resources and reserves for those areas are considered along with current activity and new developments, who the players are, and some of the leasing activity and exploration licensing. MR. DECKER said slide 3 is a North Slope resources overview showing land ownership in the Alaska Arctic. Areas in green represent permanently protected federal lands: national parks, national monuments, and the Arctic National Wildlife Refuge (ANWR), all of which are basically in the Brooks Range. Two regions are between the Brooks Range and the shoreline: the Foothills and the Coastal Plain. In the west, the National Petroleum Reserve-Alaska (NPR-A), is managed by the Bureau of Land Management (BLM); it is just about the same size as the State of Indiana. The Arctic National Wildlife Refuge (ANWR) 1002 area, on the right, is not necessarily permanently protected against oil and gas leasing; an act of Congress could make that either open to leasing or a federal wilderness area. It's in sort-of a limbo status. The state lands are in-between the NPR-A and ANWR. The state offers lease sales there every year in November. The North Slope areawide lease sale is in the Central North Slope onshore. The Beaufort Sea areawide lease sale is north of that, between zero and three miles offshore. The state's Foothills areawide lease sale is in the south. The Arctic Slope Regional Corporation (ASRC) also owns lands in the Foothills). MR. DECKER said that most of the oil and gas development is strung along the shoreline and is coming from a subsurface feature that traps oil and gas called the Barrow Arch, a major subsurface ridgeline that traps oil and gas. Another belt of mostly gas field accumulations is located near the northern edge of the Foothills; most of them are small gas discoveries that have never been commercialized. 3:37:28 PM MR. DECKER said another thing to be aware of is the 639 existing exploration wells, even though exploration density is still pretty low across large parts of the North Slope. Slide 4 displayed federal estimates - United States Geological Survey (USGS) and Bureau of Ocean Energy Management (BOEM) - of the undiscovered technically recoverable conventional resources that could be lurking out there in-between the various well penetrations in Arctic Alaska consisting of about 40 billion barrels of oil and about 207 trillion cubic feet of gas. The gas in the Outer Continental Shelf (OCS) and the state waters and onshore areas is a rough equivalent at around 100 trillion cubic feet (tcf) of gas. There is about 16 billion barrels (BBO) of undiscovered onshore and in-state waters oil versus about 24 billion barrels in the OCS. 3:38:58 PM MR. DECKER said slide 5 displayed Arctic Alaska oil and gas reserves, and that 30 tcf of natural gas is associated with the oil in the North Slope developed oil fields, most of which is at Prudhoe Bay and Point Thomson. However, without a pipeline in place, most of that gas is not really in the reserves category and is best described as "contingent resource," the difference being that without a pipeline, it's not connected to markets. So, most of that gas can't be monetized until that connection is made. Of that 30 tcf/gas about 5.9 tcf is believed to be in the reserves category (connected to a local market on the North Slope) that can be converted into natural gas liquids and sold to the TransAlaska Pipeline and minor sales to manufacturers of miscible injectant that can be exported to other units. So, a small fraction of gas is in reserves, but for the most part it is still contingent resource. On the oil side, Mr. Decker said, the Energy Information Administration (EIA) in 2014 carried an estimate of about 2.8 billion barrels of proved oil reserves on the North Slope. That is a difficult number for the department to actually determine, because it implies a lot of knowledge about a minimally commercial production rate. 3:41:02 PM MR. DECKER said that slide 6 is about current activity and new developments on the North Slope in alphabetical order by operator. Accumulate Energy is a relatively new player on the North Slope; it is an Australian organization that backed into an agreement with Burgundy Exploration that had bought some leases. Then they came to the state's last lease sale and bought quite a few more. They are evaluating the shale trend south of Prudhoe Bay and Kuparuk, very near the Dalton Highway and the pipeline. Accumulate Energy drilled the Icewine 1 well last year and was encouraged with the results. They are conducting seismic acquisition on their extensive lease acreage this winter. Arctic Slope Regional Corporation's (ASRC) AEX, drilled the Placer 3 well this year in the Placer Unit just west of Kuparuk, looking at a Kuparuk sea sand reservoir. It's finished, but the results are still confidential. BP, the operator at Prudhoe Bay Unit, in 2015 completed 8 new grass roots (starting at surface) wells, conducted 46 new sidetracks to different target locations they haven't yet fully gained, and conducted about 420 well workovers in the Initial Participation Area (IPA) at Prudhoe Bay alone. They also completed the first wells in the Lisburne IPA that had been drilled in 9 years. They also completed a 3D seismic acquisition program called the North Prudhoe Survey, partially onshore and partially offshore, along the northern edge of a big unit. 3:43:35 PM Caelus (slide 7) is the operator that took over from Pioneer at the Oooguruk Unit. They have been diligent about ongoing development of a Jurassic Nuiksut sandstone reservoir and drill 4-5 wells a year, all of them long extended horizontal wells with sometimes multiple stage fractures to exploit what could normally be considered a fairly tight reservoir. They are undertaking the Nuna Project, but with the current low price of oil, they have ratcheted back from some of their plans. So, right now the first production is expected from the Torok formation reservoir at Nuna in late 2018, if all goes according to plans. Caelus is also exploring in state waters in Smith Bay, half way west from the state lands towards Barrow along the northern edge of the NPR-A. They have drilled two wells whose results are still confidential. 3:45:23 PM ConocoPhillips has been busy on at least two different fronts: the Coleville River Unit and the Greater Mooses Tooth (GMT) Unit. They kicked off first production in October, 2015, at the Colville River Unit CD 5 well which is mostly in NPR-A. That project is expected to peak around 16,000 BBO/day in the next two or three years, if not already. They plan a total of eight new wells this year in the field near the Colville River Unit. ConocoPhillips sanctioned a $900 million Greater Mooses Tooth 1 on the federal NPRA and that is expected to produce in 2018, reaching an expected peak of 30,000 BBO/day shortly thereafter. They also have plans to drill two wells in the western edge of the GMT Unit. CHAIR GIESSEL asked if CD5 production is considered new oil. MR. DECKER answered that a large part of it is, if not all of it, but there are some interesting complications regarding metering that he isn't the best at answering. He wanted to get back to her on whether it would qualify. CHAIR GIESSEL asked if DNR or DOR makes that determination. MR. DECKER replied that the DNR works alongside DOR to make that determination. CHAIR GIESSEL said the GMT 1 is on federal land, so the state's royalty will be different and asked him to explain what it would be. MR. DECKER replied that the state gets a 50 percent revenue sharing on things like lease and royalty revenue on the BLM lands of NPR-A, with the caveat that the state revenue from there all goes to the stakeholder groups that are impacted, in this case, Native shareholders on the North Slope. It does not go to the General Fund (GF). On the other hand, he believed the state still receives its full value in production tax. He would work to have that information confirmed. SENATOR STEDMAN asked if the royalty was privately negotiated for CD5 and if the state's credits are applicable there. 3:49:35 PM MR. DECKER answered that the CD5 area is largely controlled by ASRC subsurface. For clarification, he was earlier referencing activity that was occurring exclusively on Bureau of Land Management areas. So, the royalty on CD5 barrels will be mostly, if not entirely, tied to ASRC. The portion of CD5 that is affected by different royalty rates may be on a tract basis and he didn't know off the top of his head if that is 12.5 percent or 16.66 percent. He would clarify that for the committee. 3:50:49 PM He continued that ConocoPhillips, on slide 8, in the Kuparuk River Unit, kicked off a new drill site, Drill Site 2S, following up on good delineation well results at Shark Tooth that was drilled a couple years ago. That came on line in October, 2015. They also have significant drilling planned this year for the Kuparuk, Tarn, and the West Sak reservoirs. At West Sak they plan new production at Drill Site 1H News and that is planned to come on line according to plan in late 2017 with an expected peak of 8,000 BBO/day. 3:51:45 PM ExxonMobil completed the initial production system (IPS) that was lined out in the Point Thomson Settlement Agreement. A big portion of that was drilling their West Pad well and the PTU 17 well that are both complete. They also completed a 22-mile liquid hydrocarbon pipeline from Point Thomson to the Badami junction, which connects to the TransAlaska Pipeline System (TAPS). Startup activity is already in progress this week. They are not shipping oil or condensate all the way out of a unit on any sustained basis, but they expect to do that in the weeks if not a month ahead of time. By mid-May they should be producing 10,000 BB/day of condensate from that gas pipeline project. Great Bear Petroleum has been an active lease holder and explorer over the last few years in the shale trend just south of Prudhoe Bay. They also have some conventional prospects that they want to understand better. They are not drilling this year or testing, but they are acquiring a 450 square-mile 3D seismic survey and might be out at their Alkaid well that was drilled last year to see how that pans out. 3:53:33 PM MR. DECKER turned to slide 9, and said Hilcorp is now an active operator on the North Slope both at Northstar and Milne Point. At Northstar they have brought two shut-in wells back into production this past year, and at Milne Point, they drilled three new wells and have started construction of a new grind and injection waste facility. Hilcorp plans to drill 10 new wells and complete 16 workovers in the year ahead. They are also applying currently to expand the unit to encompass an essential waste disposal well along the northern fringe of that unit. Repsol and Armstrong are partners in the Pikka Unit and working hard towards developing the Nanushuk Project. People there are familiar with some of the estimates that have come out in the media of contingent resource that if it's sanctioned would go into the reserve category. Last year, they drilled three exploration wells and sidetracked one. Since 2012, they have actually drilled 12 new wells of sidetracks in the Pikka Unit as well as some others in nearby areas. They commenced the project Environmental Impact Statement (EIS) under the National Environmental Policy Act (NEPA) last summer, and it will take about three years for that EIS to reach fruition and a record of decision. They plan to drill one additional exploration or delineation well in 2017 that will help them decide on the scale of development there. It's all very promising, with the potential for 125,000 barrels a day in average production, and he hopes to see it move forward. 3:55:37 PM In the 2004-2014 time period, 110 exploratory wells and sidetracks were drilled in the north Alaska region as opposed to 1,646 development and service wells and sidetracks. On the seismic front, about 870 line miles of 2D and about 9,945 square miles of 3D data has been acquired; most of these surveys were acquired with tax credits. This is the onshore and shore fast ice zone where land acquisition techniques are used as opposed to seismic vessels in the summer time offshore. 3:56:49 PM CHAIR GIESSEL said she understands there are seismic library companies who come to Alaska and don't have leases, but get an exploration license and go out and shoot seismic. They gain data which they can get exploration credits for (because they have an exploration license). They take the data they have obtained and sell it to multiple companies over time. She asked if that understanding was correct so far. MR. DECKER answered that was pretty much right. One distinction, however, is that seismic libraries do something a little different than acquiring an exploration license from the department. They acquire a permit, usually a miscellaneous land use permit, to acquire the data. They don't need to have an exploration license or a lease to shoot seismic data. Anyone can do that whether they are a leaseholder or not, and that is often how they decide whether they want to bid on leases. CHAIR GIESSEL asked if the state has claim to the seismic data, as it does under certain other permits. MR. DECKER answered the state would not own the data, but the libraries are required to submit it to the state under conditions of their land use permit (LUP). CHAIR GIESSEL asked if that data remains confidential with DNR for the 10-year time frame. MR. DECKER answered that seismic data such as this, in general, has no fixed confidentiality period. So, this data would be held confidential in perpetuity. Other than the fact that now most of the data is being acquired under the tax credit program, that is where the 10-year release to the public gets attached. In the case of the Frontier Basin credits, AS 43.55.025(a)(7) has a two-year period of confidentiality after which the data can be released. 4:00:12 PM CHAIR GIESSEL asked if the seismic libraries pay the state corporate income tax since they sell the data, sometimes multiple times, to different companies. MR. DECKER said he would defer that answer to the Department of Revenue (DOR). CHAIR GIESSEL asked him if there was any other information they should have. MR. DECKER answered not without any other specific questions he wouldn't know where to begin. It's good news to see so much activity. SENATOR WIELECHOWSKI asked what percentage of the tax credit these companies get. MR. DECKER answered that it varies by credit, and once they get down into the slides about DNR's participation in the DOR tax credit programs, slide 31 summarizes them. They would range from 30 to 40 percent in most cases. CHAIR GIESSEL asked which credit would be the one they could access. MR. DECKER answered AS 43.55.025(a)(4) has been a big one. AS 43.55.025(a)(7) is the Frontier basin credit that ranges up to 75 percent or $10 million, whichever is the lesser. Under the AS 43.55.023(a)(2) and (l)(2) there are 20 percent credits that have been applied. The (a)(2)s have applied to a lot of the North Slope shoots and the (l)(2) well lease expenditure credits have applied to quite a lot of Cook Inlet projects. So, credits are 20 to 40 to 75 percent for various seismic programs. SENATOR COSTELLO referenced slide 12 that lists the small independents and asked to get the dates for those and the midsize companies with the years that they started work in Alaska. MR. DECKER said he could do that. SENATOR COSTELLO said the idea is to see if any of the incentivizing legislation they have passed actually ties in with their entrance into Alaska. 4:04:28 PM MR. DECKER said slides 11 & 12 break down the companies working on the North Slope according to large majors, large independents, midsized companies, and smaller independents. They used an arbitrary market capitalization cutoff for the large majors at $40 billion; these include BP, Chevron, ConocoPhillips, Eni, ExxonMobil, and Shell. The large independent and midsized companies are Armstrong, Anadarko, British Gas (BG) Alaska (now absorbed into Shell), Caelus Natural Resources, Halliburton (teamed up with Great Bear), Hilcorp Alaska and Repsol. 4:05:58 PM Slide 12 listed 38 small independents, nine or ten of which are actually exploring currently. Most of them have bought leases and have working interest in leases, but are not necessarily actively exploring. One more should be on the list: Linc Energy. MR. DECKER said they have a histogram for each of the northern Alaska area-wide sales. Slide 13 displayed a histogram of areawide leasing activity on the North Slope (the central North Slope onshore in the Barrow Arch region). Since 1998 when the state first began areawide lease sales, he pointed out that 140 tracts were offered in 2011, but in 2010, 117 tracts (shale acreage) were purchased largely by Great Bear. That was the first entrance of anyone looking at shale on the North Slope, and it caused the DNR to reexam some of its leasing thinking. So, in 2011 DNR restructured its lease sale in the shale trend area, and for a large part of the central North Slope lease sale, they began offering tracts that were one-fourth the size of the previous tracts. That was basically to safeguard the state's interest so that companies couldn't hold a lot of acreage by drilling one well on each lease where it wouldn't be able to drain more than a fraction of that lease. The point is that more leases were bought in 2011, but less acreage was sold in that sale. The state still has that same structure in the shale play area. Another standout year is 2014, Mr. Decker said, when more than 100 full-sized tracts were picked up by Caelus along the Barrow Arch near the shoreline east of the Dalton Highways heading over the Point Thomson Unit. Armstrong and the shale players also picked up acreage in that sale. In 2015, 131 leases sold; 121 were in the shale play by Accumulate Energy teamed up with Burgundy Xploration. SENATOR MICCICHE asked for a comparison of Alaska's previous average tract size and the split up tract sizes to other states for 2014 and 2015. MR. DECKER answered that most states don't have a lot of mineral rights to offer in their lease sales. Most of the places where the shale plays have been active like North Dakota, south Texas, and the East Coast are private lessees and a lot of work is put into rounding up enough leases to aggregate acreage there to drill on. It's widely recognized that shale wells can't drain anything like the size of Alaska's ordinary three by three, nine-square mile tracts. 4:10:41 PM SENATOR MICCICHE asked if he could compare it to the OCS or a similar jurisdictional controlled area. MR. DECKER answered that the three-by-three-mile, nine-square- mile tracts in most areas of onshore Alaska compare very closely to typical OCS tracts, which are in kilometers. SENATOR COSTELLO asked him to explain the significance of single and multiple bids. Does "multiple" mean it's more attractive and what is the significance of comparing the year 2013 to 2014? MR. DECKER answered that it's just a reflection of the fact that DNR offers tracts for competitive bidding. In a majority of lease sales, the majority of tracts sold are sold without competition, meaning nobody actually competes in the bidding. The lion's share of the activity they have seen in recent decades has been a single company pursuing any given tract, and he wasn't ready to compare and contrast the competition from one year to the next. That is just what it is, so to speak, he said. 4:12:51 PM Slide 14 displayed Beaufort Sea areawide sales in the zero to three-mile belt. In 2006, he said, the state sold 50 leases, 30 of them in Smith Bay (the area half-way to Barrow) where Caelus is exploring right now. The other 20 leases sold that year were basically in the vicinity of the Liberty Unit, which is in a little pocket of the OCS that is partially surrounded by state waters, and at that time, BP had plans to develop Liberty. That helped focus interest in that general area. Another standout year was 2011 when 68 leases were sold to a different company, more of them in Smith Bay, but Harrison Bay, too, which is just north of northeast NPR-A. There were lots of speculator bids (operators or lessees that aren't typically associated with actual seismic or well drilling) in the eastern part of the North Slope over towards Point Thomson and no bids were taken in the Beaufort area in 2016, most likely a reflection of the current oil price. MR. DECKER said that slide 15 displayed the gas-prone North Slope Foothills areawide sales. A huge surge of interest happened in the Foothills in 2001/02 when the producers started talking publically about the North Slope gas line. That project basically stalled out in the next few years. The gas line didn't look like it was moving, and so bidding slowed down in this region, as well, not to mention the fact that many of the leases that people thought were prospective were already held. In 2006, there was a revival in the gasline hopes with the Alaska Gasline Inducement Act (AGIA). However, a lot of the acreage was already held, so there wasn't that much to be picked up in that sale. In the more recent years, there has been more of a wait-and-see attitude about the gasline, and more relinquishments have been seen as opposed to purchases. 4:15:52 PM MR. DECKER said slide 16 displayed a USGS 2011 Resource Assessment of the Cook Inlet Basin. It includes undiscovered, technically-recoverable oil and gas. USGS sees about 600 million barrels of yet to be discovered conventional oil, on the order of 14 tcf of conventional gas, and unconventional gas - in tight sandstones or coalbed methane - of just over 5 tcf. It's an optimistic view of the basin, and he reminded them that technically recoverable estimated gas and oil is not the same as commercial, for which each discovery would have to be evaluated on its own. From a reserves standpoint, the Division of Oil and Gas (DOG) released a study in which it estimates 1.18 tcf of proved and probable gas reserves in the Cook Inlet Basin. That number has not changed a lot since they did a study in late 2009/10. The fact that it hasn't dropped much, in fact it has increased slightly, is because of active exploration and delineation of the existing fields. The old fields still have life left in them. There is 1.2 tcf of additional mean undiscovered resource from the Bureau of Ocean Energy Management's (BOEM) estimate of Lower Cook Inlet. He said slide 17 is an alphabetical listing of who is doing what in Cook Inlet now. Apache has been very active over the last several years with seismic and drilling a well, but they are planning to cease all their activity for now due to low oil prices. They do intend to hold most of their leases until expiration and are maintaining an office in Anchorage with a skeleton crew, hoping for the price to turn around. MR. DECKER related that ConocoPhillips said their main fields in the basin have been the Beluga River Unit and the North Cook Inlet Unit, but recently they agreed to sell their interest in the Beluga River Unit. Municipal Light and Power (ML&P) took a large chunk of that, increasing their interest from one-third up to 57 percent. Chugach Electric took on 10 percent and Hilcorp kept their one-third percent interest, and became the operator there. He said Furie has been making great progress over the last couple of years in the Kitchen Lights Unit; they set the monopod platform last year and currently have one well producing about 4-6 bcf/year, which is being sold under contract to Homer Electric. They also completed their onshore gas facilities and pipeline for that production to happen, and that went on line in December. In addition, Furie has just recently brought a second jack-up rig, the Randolf Yost, into the basin, and it will drill two development wells this year. 4:20:08 PM BlueCrest Energy, Inc., at the Cosmopolitan Unit, plans to take delivery of its new land-based drill rig for oil development any time now and plans first oil in mid-2016. That has just recently kicked off from one well in the last few days. Hopefully, they will also get around to using the Spartan jack-up rig to drill some offshore wells into the gas cap of the Cosmopolitan field where there is both onshore development of oil through long- reach horizontal and long departure wells. However, the gas being shallower, would have to be accessed from offshore. So, their plan is to drill with the jack-up rig and then place small monopod platforms very similar to what Furie is doing at the Kitchen Lights Unit. 4:21:02 PM MR. DECKER said slide 18 shows that Hilcorp is the major operator in the basin. Some examples are completion of two new wells in the Cannery Loop Unit with a couple more being planned for this year, a new well in the Deep Creek Unit and plans to drill a second this coming year. Hilcorp also continues adding pads at the Ninilchik Unit and expanding it with extensive lateral and vertical production. They also focused on work-over jobs in the Trading Bay Unit in 2015 and are planning three new wells in 2016. They also purchased XTO Energy, Inc., an ExxonMobil asset (also known as Cross Timbers), and may bring it on at some point. Hilcorp has a projected investment this year of about $120 million in the basin, which is similar to what it spent over the last few years. 4:22:16 PM Slide 19 summarized Cook Inlet activity since it started to rebound (reflecting the Cook Inlet Recovery Act) in 2010 with 24 exploratory wells and sidetracks and 65 development and service wells and sidetracks. This has resulted in the reserve increase he just talked about. In addition, lots of seismic data has been acquired: 725 line miles of 2D onshore/offshore and about 660 square miles of 3D onshore/offshore. Mr. Decker said this statistic is from 2004-2014 tax credit data. 4:23:21 PM Slide 20 listed who is working in [Cook Inlet]. He said that Cook Inlet is becoming a mature basin with a lot of legacy fields being initially developed by some of the larger producers (slide 21). Until recently, Chevron and Marathon operated most of the fields there. They have sold those to Hilcorp and Hilcorp, having a different cost structure and business model, is able to make those things profitable. 4:24:01 PM CHAIR GIESSEL noted that slide 21 was missing from their slide deck. MR. DECKER apologized and said he would amend the presentation and turn the missing slide in to the committee later. CHAIR GIESSEL said slide 22 was a bar graph labeled "Cook Inlet Leasing Activity Trends, areawide lease sale results 1999-2015" and asked him to describe what was on slide 21. MR. DECKER said he would make sure they got slide 21, but it shows that Cook Inlet is a maturing basin and that as things mature, one gets away from the large multinational companies towards mid-size companies like Apache and Hilcorp. A lot of the smaller players are picking up acreage, too, but they are very sensitive to oil prices, so their level of activity is not as insulated from price as some of the bigger companies. Also, because the smaller companies try to be more nimble, that requires an intensive administrative effort from the DNR in processing applications, lease transfers, and such. 4:26:41 PM SENATOR MICCICHE clarified that slide 20 was about Cook Inlet and not the North Slope. Slide 22 displayed the Cook Inlet leasing activity trends from 1999 to 2015. The one big standout is the 106 leases that sold to Apache when it entered the basin in 2011. Their plan was to buy a lot of open acreage and shoot large-area 3D surveys, both onshore and offshore, and look for the kinds of prospects that would not yet have been found on 2D data. They have drilled only one well to date and that is on hold. 4:28:24 PM Slide 23 displayed a location map of all the sedimentary basins in the state and many of the Interior basins that are often referred to as Middle Earth. In other cases there are specific distinctions like where the Frontier Basin tax credits would apply. In the upper left is a comment box - 43.55.025(a)(6-7), the super credits - of 6 for wells and 7 for seismic. Those are sunsetting in June 2016, but they have been available in the six red circles. He said the Kotzebue area, the Yukon Flats and Nenana Basins, the Copper River Basin, and down on the Alaska Peninsula have credits to encourage exploration in those regions. Slide 24 is a "boiled down" assessment of the mean resource for oil and gas in the various parts of the state. The USGS has only been partially assessed the Interior basins; it has done detailed assessments of the Yukon Flats Basin and a scoping of the Kandik Basin only. So, things like Nenana, Kotzebue, Copper River, Holitna, and Susitna have not been numerically assessed, although they are recognized to have potential. Basically most of the Interior basins don't have a lot of oil resource associated with them, but a bit more on the gas side. They all need further exploration to really understand their full potential. 4:30:28 PM SENATOR MICCICHE asked if the USGS applies a probabilistic number to partially assessed basins, and said it would be nice to see the conversion from what they believe is there to real numbers with further development. MR. DECKER said that is his wording, and not all of the basins in the Interior have been assessed. The 234 million barrels of oil estimate applies to the sum of their assessment for Yukon Flats added together with the Kandik Basin. The Nenana, Kotzebue, Copper River, and so forth have not been assessed numerically at all. Senator Micciche was right that all of the USGS assessments are probabilistic. They give a mean case, a 50 percentile case, a 5 percentile, and a 95 percentile case. USGS understands there is a great deal of uncertainty even in undiscovered technically recoverable estimates. 4:32:00 PM Slide 25 is a brief sketch of what constitutes the DNR exploration license program, which is a way of supplementing the state's oil and gas leasing efforts, encouraging exploration on state lands outside of the established producing areas. He explained that every April the department accepts new proposals to look at exploration outside of the existing sales. If they receive a proposal in a certain area, the DNR commissioner can issue, at his discretion, a notice encouraging competing proposals. Anyone who participates would have to submit proposals for how much they would plan to spend for a certain number of years and it would become a competitive bidding event, in that case, based on work spending commitments. To date, three exploration licenses have satisfied their spending commitments and opted over to convert to leases. Those are Susitna II, Copper River, and the Nenana Basin; the Nenana Basin being pretty much the "poster child" for how the department intends land activity there to go. 4:33:26 PM MR. DECKER said slide 26 indicates who is working the Frontier basins, which largely consists of the Native corporations. Ahtna is active on the Tolsona exploration license in the Copper River Basin. It has reprocessed 2D seismic and acquired new 2D specific to their prospect. They plan to drill their Tolsona 1 gas exploration well sometime in the first half of this year. They are in a bit of a rush to get that well done to qualify for the Frontier Basin credit. This is going to be an exploration follow-up to the Ahtna 1-19 sidetrack well that was drilled by Rutter & Wilbanks. Normally, he said he wouldn't have made that comment about Ahtna being in a hurry to qualify for the tax credit had they not already announced that as part of their goal, because that information is confidential. MR. DECKER said Doyon has drilled a couple of wells: Nunivak 1 and 2. They have acquired 2D and 3D seismic, geophysics, airborne geophysics like gravity and magnetics, and lakebed geochemical surveys looking for micro-type carbon seepages. They converted their exploration license to a series of leases a couple of years back and are shooting additional 3D this year. They have plans to spud the Toghottele well in that vicinity this summer. 4:35:11 PM Doyon is also looking at the Yukon Flats Basin (slide 27), he said, and doing similar kinds of work there, but it is not so far along. The land is entirely owned by Doyon and it is checker-boarded with National Wildlife Refuge lands. Nana is evaluating and marketing prospects in the Kotzebue Basin based on legacy industry seismic collected back in the 1970s by SoCal and Chevron. They would love to explore for gas or oil. Usibelli Coal Mine, Inc. has secured a gas-only exploration license in the Healy area and they have drilled one shallow exploration well in 2014 looking for that. 4:36:07 PM Slide 28 displayed Frontier Basin wells drilled and seismic acquired: a total of seven exploratory wells and well branches between 2004 and 2014 and 1220 square miles of 2D and 340 square miles of 3D seismic. The Toghottele well is based on some of the 3D data, so that should be a well-mapped prospect at this point. 4:36:39 PM Slide 29 graphed Frontier Basin Exploration licenses that had been issued. A total of five are listed as active, but since the slide was made, Cook Inlet Energy announced plans to relinquish the Susitna 5 license. Healy is the Usibelli Company, Nenana has Doyon as an operator, southwest Cook Inlet is Cook Inlet Energy, Tolsona is Ahtna, and the Susitna 5 is Cook Inlet Energy, as well. 4:37:22 PM Slide 30 is about DNR's involvement in the DOR tax credit programs, Mr. Decker said. DNR's involvement is limited to projects that yield geological, geophysical, and engineering data (GG&E), mainly exploration wells and seismic surveys. DNR collects and adjudicates all the data generated by these projects and does what needs to be done to make it available for the public according to the specified schedule, working out things like private land holder and ownership restrictions. DNR has no role in credits that do not require data submission (AS 43.55.023(a)(1) capital expenditures work for development projects and the AS 43.55.023(b) NOL projects). MR. DECKER said certain people believe that DNR has a lot of discretion about which credits they actually authorize for approval, but the statues don't give it much ability to do that, which is a good thing. He would not want to be in a position of picking winners and losers, setting the state up for appeals and lawsuits from the various companies by having approved one credit and not another. The criteria are "pretty black and white" as opposed to subjective. The bulk of the prequalification steps the department goes through are mostly to ensure that the credit is really for new exploration (wildcat exploration). 4:39:58 PM He said slide 31 contains the complicated table of DNR adjudication requirements for exploration tax credits on one page. It's become a fairly complicated system of credits to manage, a key point to keep in mind in any efforts to simplify it. CHAIR GIESSEL thanked Mr. Decker for "the beautiful chart that is actually quite readable." Finding no questions, she said they would keep looking it over and know where to find him if they come up with some. 4:41:35 PM MR. DECKER said some of the credits have a prequalification step and that process was displayed on slide 32. Ordinarily the operator that intends to do the work makes a presentation to the DNR prior to any of the work being done. The DNR makes sure that the dates are consistent with the dates intended in the statute and that the location relative to pre-existing wells fulfills the distance requirements from other wells and units. A big part of this is demonstrating that they are looking at a separate trap - a separate subsurface container or potential container of oil and gas - for many of the credits. There are additional factors for Frontier Basin wells and seismic that the commissioner can weigh. Once they reach their conclusion after the presentation, the division briefs the commissioner who then issues a decision that gives them some assurance that as long as the operation is conducted according to plan they will receive their credit. 4:42:43 PM SENATOR COSTELLO asked if the decision made by the commissioner can be delegated. MR. DECKER answered that the decision letter comes from the commissioner's hands, but he relies on division staff to make the determination. 4:43:34 PM He said most of the credits go through a post-exploration follow-up process, but DNR gets all of data (slide 33). That needs to be adjudicated in terms of inventory and quality control, quite an extensive operation that consumes "huge computer resources." In many cases, the department also has a post-exploration or post-seismic processing presentation that looks at things like the dates the operations were conducted are actually consistent with what the department was told initially and what the technical findings are. Then the commissioner issues a decision letter. Finally, after all this is done, there is a lot more data management to do: it has to be loaded for internal use and what can be released to the public has to go out. It has to be archived and a release mechanism has to be worked out. CHAIR GIESSEL asked when the exploration drilling cores actually come into DNR's possession and get archived in the Geologic Materials Center (GMC). MR. DECKER answered that for the most part, core material is not submitted entirely to the DNR. The state is entitled only to poker-chip size chips of every foot of core and that goes to the Oil and Gas Conservation Commission (AOGCC). When the well is released, after two years, the AOGCC normally releases their exploration well files. At that same time, they would release those core chips and rock cuttings and the ground up rock that comes out of the well when they are not coring (the equivalent of rock sawdust). He said Senator Giessel may be thinking of the extensive core repository, a lot of which has been donated by companies and the United States Geological Survey (USGS) from the many wells in NPR-A. For the most part, the conventional cores are the property of the companies that drill the wells and are not turned over to the state. However, the state does have access to those cores for examination as part of the tax credit deal. 4:47:12 PM MR. NOUVAKHOV continued the presentation on slide 34 on the DNR's Royalty Modification Program that falls into two categories: the first is under AS 38.05.180(j), royalty relief that is granted based on economic conditions prevailing at the time; the second is under AS 38.05.180(f), royalty relief specifically targeting Cook Inlet basin, and it's effectively given out based on technical and regional considerations. He explained under slide 34 that the DNR commissioner may provide modification of royalty under certain conditions, the first one being to allow production from a field or a pool that has not been previously produced, and in that case, the reduction of royalty could be all the way down to 5 percent. The second case would allow royalty modification to prolong the economic life of a field or a pool, which is already producing, and in that scenario, the royalty rate could go as low as 3 percent. The third case is for re-establishing production of shut-in oil or gas, and that scenario also allows for a reduction down to 3 percent. Importantly, under the (j) program, the commissioner grants the royalty modification when the lessee makes a clear and convincing showing that the modification meets the established criteria, that it is in the state's best interest, and shows that the development would not occur without providing this royalty modification. That this kind of an underlying economic condition will make a project viable is an important distinction between this provision and the following provision, which affects the Cook Inlet Basin. 4:50:17 PM MR. NOUVAKHOV said the state has not granted royalty modification under the (j) provision very much (slide 35); the three times it did are 5 percent for Oooguruk to Pioneer in 2005, 5 percent and a price trigger for Nikaitchuq to ENI in 2008, and 5 percent until $1.25 billion of gross revenue for Nuna Torok to Caelus in 2014. 4:51:39 PM The Cook Inlet discovery royalty is covered under AS 38.05.180 (f)(4) (slide 36), and that is more technical in nature. Under this statute, the lessee of a discovery well shall pay 5 percent royalty on all oil and gas production from a pool that is attributable to the discovery lease for 10 years following the date of discovery. It's available only for leases in the Cook Inlet Sedimentary Basin. To obtain that, the lessee will have to first prove that the discovery is from a previously discovered oil or gas pool and also get certification for a well that is capable of producing in paying quantities. Furie has applied under this program for KLU 3 in its Kitchen Lights Unit and has received a discovery royalty reduction for four previously discovered gas pools. The lessee will pay 5 percent of production from those four pools until 2023 when the royalty rate will revert back to 12.5 percent. Other than this instance, this royalty reduction has not been utilized. 4:53:13 PM Other royalty relief statutes are AS 38.05.180(f)(5), AS 38.05.180(f)(6) and AS 38.05.180(n)(2). AS 38.05.180(f)(5) automatically grants 5 percent royalty for 10 years for specific Cook Inlet fields identified in statute: Falls Creek, Nicolai Creek, North Fork, Point Starichkof (not producing), Redoubt Shoal, and West Foreland-all currently pay 12.5 percent (slide 38). AS 38.05.180(f)(6) reduces royalty for specific platforms in Cook Inlet if production falls below certain levels. Lower production based on reservoir conditions cannot be "the result of short-term production declines due to mechanical or other choke-back factors, temporary shutdowns or decreased production due to environmental or facility constraints, or market conditions." AS 38.05.180(n)(2) allows reduced annual rent and royalty for nonconventional natural gas to $1 per acre and 6.25 percent. CHAIR GIESSEL thanked both Mr. Decker and Mr. Nouvakhov for the presentations. ^DOR Second Presentation: Additional Modeling and Scenario Analysis 4:56:00 PM CHAIR GIESSEL announced the second presentation from the DOR Tax Division Director Alper entitled "Department of Revenue Second Presentation: Additional Modeling and Scenario Analysis" dated April 4, 2016. KEN ALPER, Director, Tax Division, Department of Revenue (DOR), Juneau, Alaska, said the presentation covers three subjects: a couple of follow-up slides answering questions from previous presentations, slides digging into the specific details of SB 130 and how the math works, then the scenario analysis and the life-cycle modeling. 4:57:09 PM He said slide 4 is a dense slide presenting alternative historic spending on tax credits and its relationship to the statutory formula for how much money could/should have gone into the Tax Credit Fund per language in AS 43.55.028 and how that might play out into the future. CHAIR GIESSEL asked him to cite where this is in statute. MR. ALPER answered that AS 43.55.028(b)(c) and the broader statute called "028" creates the Tax Credit Fund. That fund was created in the bill known as "ACES" (HB 2001 from the fall 2007 special session). This analysis begins with FY09, because that was the first budget cycle after the passage of that bill. The .028 statute creates a new fund from which tax credits can be repurchased and establishes guideline language about what can be appropriated into it in the (b) and (c) sections. That formula is based on the price of oil tied to 10 or 15 percent of the production tax revenue received under ".011." SENATOR COSTELLO asked for information on production for both the actual and the forecasted sections. She was trying to figure out whether knowing the past would help make more accurate projections in future years. 4:59:30 PM MR. ALPER responded that he would provide an updated version of the slide to the committee. The statute says 10 or 11 percent of the amount collected under .011, which in both the ACES and SB 21 regimes means the tax, itself. It's a number that the state never sees, because there are other subsections in AS 43.55 that calculate the so-called credits against liability (the capital credit, the per barrel credit, small producer credit, and various credits that the producers subtract before they actually physically pay their taxes to the state). So, the third column, labeled "Actual Production Tax" is the revenue received by the state: $3.1 billion in FY09, peaking at $6.1 billion in FY12, and the much smaller numbers received today with the low commodity price. The column after that labeled "Credits Against Liability" is the taxes that were never received by the state because for one statute or another the companies who paid taxes were able to reduce their taxes by that amount. That is a calculated figure of AS 43.55.011 revenue (state's gross revenue before the subtraction of any credits against liability) and the number to which the formula in the statute is applied. The next column is labeled "Price of Oil" and the reason it is placed there is because a bifurcation in the formula says that if the price of oil is above $60 use 10 percent; if the price of oil is below $60 use 15 percent. The next column, labeled "Credit Cap per AS 43.55.028(c)," is the amount that would have been appropriated - the alternative reality - what would have happened if the legislature had appropriated money to that cap going back to the beginning. What would have happened in the early years between 2011 and 2013 is that the fund would have effectively been endowed. The column labeled "End Year Fund Balance" indicates the fund balance. The $150 million in that fund column is what is left over after credits of $193 million were claimed at the end of FY09 with a cap of $343 million. 5:01:51 PM SENATOR COSTELLO asked if a company earns a credit, aren't they owed that credit. How can it be capped? MR. ALPER answered that the repurchase fund was not about the earning of the credit but the state's role in physically repurchasing the credits. The expectation is were the fund to be short-funded, then there would be companies carrying the credits to the next year where the fund would be over-funded (as in the early years). SENATOR STEDMAN clarified that the "End Year Fund Balance" column is hypothetical. MR. ALPER said that was right. He added that the operating budget going back to FY09 and through FY15 was written with an open-ended appropriation. The language always said something to the tune of "the amount presented for repurchase for tax credits under AS 43.55 is appropriated from the General Fund to the Tax Credit Fund, .028." In other words, the DOR was authorized to spend the amount of money that was presented for repurchase. There was an estimate of whatever the forecasters thought it might be at the time the operating budget was being written, and then the actual appropriation would be done to match the actual claim for credits. That is how it has been done and the estimate never hits it exactly. The actual number was the actual appropriation in the early years simply because of the way the budget was constructed. Carrying that forward into the alternative reality, had it been to the Cap End of Year Fund Balance, by FY13 the fund has $655 million. Beginning in FY14, the amount spent on credits was more than the revenue coming in and the fund would have effectively been spent down. At the end of FY15, where it says "negative $112 million" the fund would have been out of money and there would be no money to carry forward for FY16. MR. ALPER reminded them of the debate last session about $91 million being the right amount going into the fund and said that number was based on the spring 2015 latest available information that would have led to this calculation at the time the last budget was written. The most recent information reduced that $91 million to $32 million for FY16. Regardless, the actual number that was appropriated by the Governor was $500 million. MR. ALPER said part of the story is that had the fund been appropriated the other way over the last number of years, the state would have been in roughly the same place last session (spent down the fund for FY16), but there may have a different expectation in industry that the state was going to have open- ended participation and the repurchase of tax credits. The standard would have been in the appropriations being tied to a share of revenue rather than being open-ended. The state may have erred in some ways in creating that open-ended expectation, because it leads to a more difficult time in doing credit reform amid limited resources. 5:06:45 PM CHAIR GIESSEL said for completeness doesn't .028 go on to say "plus appropriated funds." MR. ALPER answered, "Unquestionably." The language that was part of the ACES bill was "guideline language." The idea behind the guideline language at the time was to prevent this sort of problem, to put some sort of parameter around it. But it leads to some inconvenience and it could lead to short funding, and the state didn't have cash flow problems during the intervening years. It was simply easier and more convenient to write it open-ended like that. SENATOR COSTELLO asked if he is suggesting that previous legislatures should have predicted this low price environment. MR. ALPER answered that he wouldn't go that far. Obviously, lower prices could happen eventually, but what would happen to tax credits in a low price scenario didn't enter into their forecasts. The DOR, like the most of the rest of the industry, thought that the prices were going to continue higher for a longer period of time. He said that gets through everything in the actual section. In answer the Senator Giessel's question about what happens if the legislature simply appropriates at that statutory cap going forward that the credit claims are estimated to be $775 million beginning in FY17 and the final version of the spring forecast is below that, and then there are the relatively limited appropriations under the credit cap, because of the relatively low production tax revenues of between $19 to $32 million a year. So, the state would be running a shortfall of $200 to $400 million a year, and the End Year Fund Balance in this scenario would be $3.4 billion in accrued credits owed to companies in 2025. This is not a practical possibility simply because the end of FY16 number is more likely to be no more than $200 million (or really zero because of the $775 million that was rolled into FY17). So about $2.8 billion is how much the state could theoretically accumulate in credit obligations to companies between now and 2025 if the system is unchanged and the legislature only appropriates to the statutory guideline. SENATOR STEDMAN commented that the magnitude of the $450 million in credits was a bit of a surprise when it came in in the beginning of the 2009/10/11 period, but the cap numbers were fairly in line with what was going on, so there wasn't really a lot of alarms bells going off. Also, he advised that historically some of the language in both the operating and the capital budgets gets inherited into the next year pretty easily without a lot of review. SENATOR STEDMAN asked for help on where the state actually is now on the Year End Fund Balance so he can get a better grasp on FY15/16/17, and it would be helpful to get it in a table format. 5:11:28 PM MR. ALPER said, "Certainly." The End of the Year Fund Balance at the end of FY16 is for all intents and purposes going to be a zero, and that will be the starting point. Five hundred million was moved to the Tax Credit Fund early in this fiscal year and that is getting spent. It will all be spent and then credits that are not repurchased will be calculated as part of the estimated $775 million claim in FY17. There is no carry forward in this form the way it was written. However, he hadn't discussed the two columns on the right referred to as the "non- cashable carried forward." They are the operating loss credits earned by the major producers who are not eligible to get cash for their credits. He explained that the End of Year Fund Balance for FY16 is zero with accrued non-cashable carried forward credits of $385 million, and that becomes $632 million in FY17. The first thing major companies can do with NOL credits that they can't get cash for, because of existing statutory limitations, is offset their minimum tax, taking it effectively down to zero. Credits in excess of what it takes to go to zero can be carried forward into the following year. That number builds up to about $700 million, and then in roughly FY20/21/22, gets brought down to zero, because in those years, the price of oil goes up a little bit further and the additional production tax, rather than being paid to the state, is offset with this backlog of NOL credits. The state gets relatively low taxes as it works its way through the NOL credits backlog until by 2025 it is out of that world, and hopefully everyone is at least profitable again. The problem is that by that point, depending on other changes to the system, there might be a large backlog of carry-forward cashable credits, which may have been statutorily deferred, that depend on the funds that are put into the Tax Credit Fund. CHAIR GIESSEL said this also illustrates the statement that the major producers are bleeding cash at this point. MR. ALPER admitted that is true as the price of oil is less than what it costs to get it out of Alaska. SENATOR COSTELLO asked if Mr. Alper was assuming companies that experience several years in a row of net operating losses will stick around. MR. ALPER answered that the department hadn't made any fundamental changes to the forecast based on continuing low prices; they only know the production figures the companies tell them. But if the price of oil stays at this level - in the low $40s and high $30s for the next three or four years - he was sure all manner of changes in behavior would be seen. 5:16:41 PM SENATOR COSTELLO said then that the presentation he is providing is focused solely on the budget of the state government and not on the economic impact to the state's economy as a whole. MR. ALPER answered that he wasn't sure of how to answer that. They have known production and price forecasts. For example, companies have told them when they are cutting back on certain behavior - drilling certain wells or shutting down certain rigs - and that does impact future production. But the production doesn't shut off simply because the wells already exist and are functioning, and those existing wells are, for the most part, profitable to continue operating. So, they assume a certain amount of oil will continue coming based on what companies say no matter how bad the price of oil remains. SENATOR COSTELLO asked if he saw a difference between the state's budget and the state's economy. MR. ALPER answered, "Of course; the two are linked. The state is an important part of our economy...;" the state's spending is part of the overall state economy's health. SENATOR COSTELLO noted that today's paper had an announcement that several companies are cutting employees and that she includes affected families and jobs in the economy as a whole, not solely the government's budget. CHAIR GIESSEL said she appreciated that and said she would add another column to this chart: three rigs being shut down, each rig representing 100 jobs - so, 300 jobs right off the bat. Then they talk about support industries that are laying off workers. The registrar at a school in her district said that in January five families withdrew from the school; four of them were oil company-supported families who had lost their jobs. In her years as a registrar, she had never seen that many families withdraw from the school in a single month. 5:19:24 PM SENATOR STEDMAN referred to the $385 million non-cashable carry- forward credits for FY16 that can't exceed expenditures in a calendar year, but the Revenue Sources Book, which most legislators use, uses a fiscal year. The challenge is how the DOR helps policy makers make that conversion so they can understand the magnitude of the credit - good or bad with a numeric that matches the correct timeframes. MR. ALPER said he agreed that the department is often dealing with issues of translation between fiscal and calendar years and how to present them to the legislature. He said this particular number is an odd one, because the end of FY16 happens this June, but none of the NOLs are going to exist in a legal sense until next December, because it's the end of the calendar year for taxes. So, they estimated half a year's worth of NOLs, but they don't actually exist and are not eligible for a credit until halfway into FY17. For illustrative purposes the credits are being shown as they are being accrued by the companies. SENATOR STEDMAN said he wasn't faulting one way or the other, but just wants everyone to be able to understand the same data set. For instance, the Revenue Sources Book uses FY16 numbers and non-deductible operating and capital expenses of $1.9 billion, and in that year most of the credits belong to the majors who will have to carry it forward. But part of the number might be able to be put to the treasury quicker than a multi- year carry forward, which it looks like the industry is going to get. He asked if there was any way Mr. Alper could parse that or help legislators with a benchmark. Is it possible that the GVR barrels might be outside of this, and apply that percentage of GVR eligible credits? 5:24:47 PM MR. ALPER said he would try to answer that. Presuming $1.9 billion in excess lease expenditures at a weighted average credit of 40 percent, they are talking roughly about $800 million worth of NOL credit value out there. His understanding is that those non-deductible lease expenditures are from the majors as well as the companies that don't have production. Those are the cashable NOLs that are already in the state's credit system and that is the number ($400 million a year) he used for FY17. He thought the state would pay about half of that credit obligation and the other half would become the carry forward credits for the majors. SENATOR STEDMAN asked Mr. Alper if he could parse that number for FY15/16/17, because it is a fairly immediate timeframe and they are real numbers. His concern is with knocking out the $600 million, the remainder is still $2 billion in FY18. At some point, he assumed the committee would have some forward-looking presentations on how the credits will impact the revenue collection when oil goes up north of $70. He advised "the folks at home" that carrying losses forward is a common practice and that "this is not something that the legislature dreamed up to benefit the industry." This is similar to the federal corporate income tax and its ability to carry losses. The discussion point comes down to either carrying forward the aggregate of credits or giving companies a credit calculation of 35 or 45 percent. Normally that credit would be somewhere along the lines of a company's marginal tax rate, but from a policy perspective, the concern is that the marginal tax rate is not 35 percent and under the PPT, the carry forward rate was 25 percent. So the impact, while subtle, when the credit number starts going up the carry forward has significant impact. MR. ALPER said the issue of the NOL credit being tied to the base oil tax rate became a bigger deal about two weeks ago when the department started seeing the impact of the spring forecast. There is no magic; it doesn't automatically tie to the base rate. The ACES base rate was 25 percent, but the effective tax rate was generally higher with progressivity. The NOL was 25 percent with SB 21. The base tax rate is 35 percent, but the effective rate is generally lower, because the primary credit is a subtraction mechanism rather than a progressive addition mechanism. So, the NOL is higher than the effective rate throughout the price ranges. Back in PPT, the base tax rate was 23.5 percent and the credit was 20 percent, so they weren't automatically linked to each other then. Therefore, there is historic precedent for not having the NOL rate being directly pegged to the base tax rate, but maybe with these "giant numbers," now is the time for the conversation about adjusting the NOL rate going forward. 5:29:47 PM SENATOR COSTELLO said numbers haven't historically matched equally, but asked if they should be in the ballpark, because the difference between 20 and 22 percent is not that significant. If it gets to a 10 percent difference, at what point would the administration say it's not going to work? MR. ALPER said the difference is the NOL was generally lower than the effective tax rate throughout both ACES and PPT, in some cases dramatically lower. There were times in 2008 when the tax rate for a couple of months got up over 50 percent and the NOLs for those companies that were doing the work was 25 percent. Right now the NOL is a little bit higher than the tax rate even at $100 oil, but they never contemplated the minimum tax before. With a minimum tax, the effective tax rate can be greater than 100 percent; then again it depends on how it's calculated. The 35 percent operating loss credit as the taxes themselves get smaller and smaller does seem to grow out of balance, but he didn't quite know how to fix that.
|SB 130-DNR-DOG-Presenation to Senate Resources-4-6-2016.pdf||
SRES 4/6/2016 3:30:00 PM