Legislature(2017 - 2018)BARNES 124
03/06/2017 01:00 PM RESOURCES
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ALASKA STATE LEGISLATURE HOUSE RESOURCES STANDING COMMITTEE March 6, 2017 1:02 p.m. MEMBERS PRESENT Representative Andy Josephson, Co-Chair Representative Geran Tarr, Co-Chair Representative Dean Westlake, Vice Chair Representative Harriet Drummond Representative Justin Parish Representative Chris Birch Representative DeLena Johnson Representative George Rauscher Representative David Talerico MEMBERS ABSENT Representative Mike Chenault (alternate) Representative Chris Tuck (alternate) OTHER LEGISLATORS PRESENT Representative Lora Reinbold COMMITTEE CALENDAR HOUSE BILL NO. 133 "An Act relating to the oil and gas production tax, tax payments, and tax credits; relating to adjustments to the gross value at the point of production; and providing for an effective date." - HEARD & HELD HOUSE BILL NO. 111 "An Act relating to the oil and gas production tax, tax payments, and credits; relating to interest applicable to delinquent oil and gas production tax; and providing for an effective date." - SCHEDULED BUT NOT HEARD PREVIOUS COMMITTEE ACTION BILL: HB 133 SHORT TITLE: OIL & GAS: TAXES; CREDITS; GROSS VALUE SPONSOR(s): REPRESENTATIVE(s) GARA 02/20/17 (H) READ THE FIRST TIME - REFERRALS 02/20/17 (H) RES, FIN 03/06/17 (H) RES AT 1:00 PM BARNES 124 WITNESS REGISTER REPRESENTATIVE LES GARA Alaska State Legislature Juneau, Alaska POSITION STATEMENT: Presented HB 133 as the prime sponsor. KEN ALPER, Director Tax Division Department of Revenue Juneau, Alaska POSITION STATEMENT: During the hearing of HB 133, answered questions. ACTION NARRATIVE 1:02:29 PM CO-CHAIR GERAN TARR called the House Resources Standing Committee meeting to order at 1:02 p.m. Representatives Tarr, Parish, Talerico, Westlake, and Josephson were present at the call to order. Representatives Birch, Johnson, Rauscher, and Drummond arrived as the meeting was in progress. Also present was Representative Reinbold. HB 133-OIL & GAS: TAXES; CREDITS; GROSS VALUE 1:03:41 PM CO-CHAIR TARR announced that the only order of business would be HOUSE BILL NO. 133, "An Act relating to the oil and gas production tax, tax payments, and tax credits; relating to adjustments to the gross value at the point of production; and providing for an effective date." 1:03:55 PM REPRESENTATIVE LES GARA, Alaska State Legislature, speaking as the prime sponsor of HB 133, provided a PowerPoint presentation entitled, "And Fairness to All Fair Production Tax To Alaskans And Industry, HB 133." Representative Gara informed the committee HB 133 is the legislature's best attempt to ensure Alaska receives a fair share for its oil in order to provide stable funding for schools, oil tax credits, and the University of Alaska, and to move society forward. Further, HB 133 intends to provide balance to the state's fiscal plan so that everybody contributes, without a focus just on those who have little and not on those who do well; the bill also follows the provision in the state constitution that directs state government to develop the state's resources for the maximum benefit of Alaskans, thus HB 133 also provides balance between meeting the aforementioned constitutional mandate and treating industry fairly [slide 2]. REPRESENTATIVE GARA said, "We have fields in the state that we are supposed to be living off, in terms of raising revenue," however, under current law, the aforementioned fields are allowed to pay a production tax of zero, and many other fields will pay zero for their first seven years. In addition, bigger, higher taxpaying fields, until the price of oil reaches about $74 per barrel, pay a 4 percent tax. That, he opined, in combination with generous tax credits, is a "double whammy" for the state: very low production taxes, and tax credits that will eat up all of the production taxes this year and in future years will yield very little net production tax. REPRESENTATIVE GARA explained in 2003, Gross Value Reduction (GVR) fields were unitized, and GVR fields include "most post- 2003 fields, and they are all future fields." For example, if the Arctic National Wildlife Refuge (ANWR) were to open [to oil production], fields there would pay GVR tax, thus a field of any size in ANWR would pay zero production tax - [as long as oil price is below] $70 per barrel oil - for seven years, which could be some of the fields' most productive years. When oil price reaches $90 per barrel, the state would receive one of the lowest profits taxes in the world at 12.2 percent [slide 3]. There are three factors that qualify an oilfield for the GVR tax provision; one factor is to accommodate fields at Point Thomson, and he provided a short history of the status of Point Thomson production. Point Thomson's primary owner is ExxonMobil Corporation, which would benefit from "this zero percent GVR tax for their first seven years as long as oil remains below $70 a barrel." [The three ways to obtain GVR tax reduction for post- 2002 fields were shown on slide 4.] 1:07:58 PM REPRESENTATIVE GARA said there are parts of Senate Bill 21 [passed in the Twenty-Eighth Alaska State Legislature] and parts of Alaska's Clear Equitable Share (ACES) [passed in the Twenty- Fifth Alaska State Legislature] that make sense, and he urged the legislature to learn from the past and develop an oil tax bill that makes sense for everyone. Currently, Alaska assesses a zero percent tax until oil reaches $15 a barrel, and a 1 percent tax at an oil price just above $15 per barrel, rising to 4 percent between $25 per barrel and $74 per barrel. In North Dakota, at $10 per barrel oil, the tax is 10 percent gross, and in Louisiana it is 12.5 percent gross. He cautioned against comparing Alaska's revenue with North Dakota and Louisiana - Alaska should instead compare revenue with big basins around the world - although other states raise substantially more revenue than does Alaska, up to $74 per barrel [slide 5]. REPRESENTATIVE GARA advised in the coming fiscal year, Alaska will not take in $6 billion to $7 billion in production taxes and royalty as in the past, but will instead garner approximately $225 million in production taxes; after paying out tax credits to companies, the state will actually be $25 million in the red. By fiscal years 2019 (FY 19) and FY 20, after Cook Inlet tax credit changes have taken place, even though the state will take in, in theory, around $250 million in production taxes, it will give back approximately 60-70 percent of that to the industry. So, the net earned by the state will be about $100 million in FY 19 and $150 million in FY 20. He opined that is far short of what Alaska should be generating, especially as [oil] prices get higher [slides 6 and 7]. 1:11:14 PM REPRESENTATIVE JOHNSON stated the materials presented seem to indicate that the oil tax credits appear to be working, and that the state's production is up for the first time in 14 years. She suggested a comparison between Alaska and North Dakota was relevant and said, "I believe Exxon said they were going to be looking to $40 a barrel oil, for production ... and that includes some of the large basin areas ...." Representative Johnson observed this tax is only a portion of the equation. REPRESENTATIVE GARA pointed out that under the old ACES system, the state had a very high tax and paid out very generous credits; under current law, the state has a low tax and pays out generous credits. He said the fields with current activity were moving forward under ACES; for example, Eni, Armstrong, and Repsol came to Alaska under ACES and before companies were offered tax breaks. Representative Gara remarked: And [Repsol] came up under ACES saying, "Alaska has great geology, it's a stable place to do business, we're going to invest three-quarters of a billion dollars, and we're going to move forward with those fields that, that are economic." And we have seen some of those fields announced, but I don't think that there's a field - if there is, there's maybe one - I don't think there's a field that wasn't moving forward before Senate Bill 21. And our goal is to increase oil production, though, the forecasts are that it's going to continue to decrease over the next 15 years unless there is a major find, and we're hoping for major finds. REPRESENTATIVE JOHNSON asked what part of oil production will continue to decrease. REPRESENTATIVE GARA answered that according to the Department of Revenue (DOR) and the Department of Natural Resources (DNR), oil production is forecast to decrease almost every year through the next 20 years, down to less than 300,000 barrels per day. REPRESENTATIVE JOHNSON said, "But that's not what ... we're currently experiencing." REPRESENTATIVE GARA expressed his understanding that DNR's model forecasts one year where oil production isn't going down, but then it continues to go down, which is similar to all of the forecasts the state has had for the last 10 years. 1:14:11 PM REPRESENTATIVE BIRCH asked whether the materials presented incorporate the royalty share; for example, in the event production does go down to 300,000 barrels per day, if there is a one-sixth royalty share, 50,000 of the aforementioned barrels are state-owned. He further asked whether any of the state asset [royalty] - that is made possible as a result of this production - is represented in today's presentation. REPRESENTATIVE GARA responded no, today's presentation is about production taxes. He acknowledged that the state receives 12.5 percent royalty on some fields, and receives approximately 16 percent royalty on other fields. He said he would address royalty briefly later in the presentation, but currently the discussion is focused on production taxes levied under the Economic Limit Factor (ELF) formula [passed in the Tenth Alaska State Legislature, and modified in 2005], the Petroleum Production Tax (PPT) [passed in the Twenty-Fourth Alaska State Legislature], ACES, and now Senate Bill 21. REPRESENTATIVE BIRCH said at some point the state needs to "account for that production," and as a one-sixth or a one- eighth owner of the oil that is produced, the committee needs to recognize and understand that [royalty] is a key component in Alaska's revenue picture. He stressed anything the state can do to increase throughput or production is a good thing. Representative Birch said he welcomed discussion on the [tax] credits, however, he urged the legislature to maintain its focus on what is needed to do to increase production and invite additional exploration and development. REPRESENTATIVE GARA turned attention to slide 8 that depicted the state's current effective tax rates on net value. He explained bigger "Prudhoe Bay-type" fields are called non-GVR fields. According to DOR, the state has a "greater of" system: when the profits tax, under Senate Bill 21, is greater than the 4 percent minimum gross tax, the profits tax kicks in, and DOR projected around $73 or $74 per barrel, the state will generate more money on the profits tax version of current law than from the gross minimum. Slide 5 showed that the state assesses a 4 percent tax on the Prudhoe Bay-type fields until $73 or $74 per barrel. Even at $80 per barrel for Prudhoe Bay-type fields, under current law there is a minimal 13.1 percent tax, and an oil price much over $80 per barrel is not forecast for the next 10 years; furthermore, 13.1 percent production tax is reported to be in the lower end of what is charged around the world. Representative Gara continued as follows: If you look at the GVR fields, the ones with the lower tax rate, they, for the first seven years, if prices are below $70, [would] not pay a production tax. Were prices $80 a barrel, their production tax is about 40 percent lower than the non-GVR fields. So, the newer fields - the ANWRs, the fields you hear ... talked about - they pay about a 40 percent lower tax rate for their first seven years, or if there are three years of $70 prices then for three years. But, those are low tax rates. ... I don't think that we can move this state forward at a zero percent production tax on GVR fields, and a 4 percent tax on non-GVR fields, for prices that go up to the $70 range. 1:18:22 PM REPRESENTATIVE GARA said DOR estimates the cost for producing a barrel of oil on the North Slope, is about $40 [slides 9 and 10]. He explained that the "4 percent oil tax problem" occurs because up until about $73 per barrel, there is a tax rate of 4 percent. Proposed HB 133 recognizes that an average field on the North Slope is profitable at approximately $41 per barrel, therefore, he suggested not raising the 4 percent tax to 5 percent until $50 per barrel, and then at every $8 increment, raise it by 1 percent. The analysis from DOR [on HB 133] is that the state share [would be] 5 percent at $50, 6 percent at $58, and 7 percent at $66 per barrel, which does not approach the North Dakota or Louisiana tax rates. The aforementioned price-sensitive and profit-sensitive increases would still leave the industry with a larger share in revenue than the state. He reiterated this component of HB 133 provides a price- and profit-sensitive gross tax that increases modestly as prices go up [slide 11]. REPRESENTATIVE TALERICO asked whether Representative Gara had information on royalty shares or municipal property tax rates in North Dakota or Louisiana. REPRESENTATIVE GARA indicated Representative Talerico's question would be answered later in the presentation; he recalled previous testimony before the committee that private royalty assessed where oil is being produced on private land is much higher than Alaska's royalty, as well as [the cost of] leasing acreage. REPRESENTATIVE TALERICO asked whether there is state take in "those areas." REPRESENTATIVE GARA answered states do not get royalty if production is not on state land; the royalty is paid to the owner of the land. REPRESENTATIVE TALERICO restated his request for information on municipal taxes. REPRESENTATIVE GARA responded that every state is different; for example, North Dakota has a severance tax, and another [unnamed] tax, both of which add up to 10 percent of the gross. Experts may be able to offer information on what is called "government take," although that should be called "government take plus private take," because in many other states royalty goes to a private landowner. CO-CHAIR TARR noted that the House Resources Standing Committee refers to "non-producer share" to reflect [taxes or royalty an oil producer pays to governments, or to a private landowner, or both]. REPRESENTATIVE JOHNSON returned attention to slide 9, and asked what is included in the average break-even point of $40.21. REPRESENTATIVE GARA said the Fall 2016 Revenue Sources Book (RSB), DOR, indicates $40.21 includes the cost of transportation and the cost of production. In further response to Representative Johnson, he explained that the cost of development is $40.21, before taxes, and deferred to DOR for confirmation. CO-CHAIR TARR said yes, and added that lease expenditure are estimated at $30.88 [slide 10]. 1:24:13 PM CO-CHAIR JOSEPHSON shared others' concerns about "4 percent up to $74." However, as indicated on slide 11, HB 133 would provide 10 percent gross at $90 per barrel, and he pointed out that the state receives a higher percentage under Senate Bill 21 at $90 per barrel. REPRESENTATIVE GARA advised that by $90 per barrel, the current law "shifts over" to a profits tax, and he remarked: Is a 10 percent on the gross bigger than 14 percent profits? Probably, but ... it's field-sensitive - there might be a very profitable field that is at a 20 percent tax rate at $90 per barrel. So, ... our bill does the same thing that current law does, which is when the profits tax is bigger than the gross tax, the profits tax kicks in, so were the profits tax to be larger than 10 percent on the gross, the profits tax would kick in. This would not stop that from happening. REPRESENTATIVE BIRCH returned attention to slide 10 - second line from the bottom - that indicated the "North Slope Credits applied against [total] tax liability," totaled $225 million. He asked: Are not those credits an expenditure that was incurred in the production of the revenue that's realized in the line above, in other words, the gross revenue? ... It seems to me like that's a part of the cost of doing business, the credits basically are a representation of the expenditure that was made necessary for the exploration, development, and realization of the revenues that are derived out of that field. Are they not? REPRESENTATIVE GARA responded, "You know, the tax is on top, and then you get the credits back." He agreed with Representative Birch's point. REPRESENTATIVE BIRCH said the point is that the credits could also be realized as an expense against doing business. For example, certain costs are incurred in the daily operation and the startup of a new business. He expressed his understanding that the credits relate to an expense that was actually incurred in the production and realization of the oil asset flowing through the Trans-Alaska Pipeline System (TAPS). REPRESENTATIVE GARA further agreed that Representative Birch was accurate as to what [slide 10] does not show, [which are] the additional credits the state pays and gives to companies that are not producers. REPRESENTATIVE JOHNSON pointed out that the estimates for transportation costs and lease expenditures are not the same on slides 8 and 10. REPRESENTATIVE GARA acknowledged there is about a $2 difference, and deferred to Ken Alper, Director, Tax Division, DOR, for an explanation. [There followed a brief discussion on the aforementioned discrepancy.] 1:29:05 PM CO-CHAIR JOSEPHSON commented that [an average break-even point for oil producers] of $40-$41 was provided by the Alaska Oil and Gas Association in January . For the purpose of explaining the bill, he opined, [$40.21] works as well as anything, because the amount is not an audit-specific number. REPRESENTATIVE JOHNSON stressed it is important to have accurate facts; in fact, DOR has said that sometimes the break-even point is as high as $46. REPRESENTATIVE GARA observed that a break-even point changes from field to field; for example, in Prudhoe Bay the break-even point is probably a lot lower than it would be for Nuna, as each field is different in size, age, and infrastructure. The break- even point [on slide 9] is DOR's best assessment of the average costs for a North Slope field over the life of the field. REPRESENTATIVE JOHNSON agreed that the discussion was "the average" and expressed her hope "that we weren't picking individual fields ...." She noted various estimates from DOR that were included in the presentation, and urged DOR to explain why there is a discrepancy. REPRESENTATIVE GARA said, "The basic point of HB 133 is to not start the progressive gross minimum tax until above the point where a field is profitable on the North Slope." Royalty relief will be addressed later in the presentation; in fact, there cannot be an exact tax that is perfect for every single field, which is why adjustments through royalty relief are necessary. The bill doesn't raise the 4 percent minimum until $50 per barrel - above where the average field on the North Slope is profitable - and the bill slowly increases the tax rate to 6 [percent to 10 percent], in order to recognize company profitability and the impact that price plays on company profitability. REPRESENTATIVE GARA presented slide 12 that was a comparison of the tax rate the state would levy as a minimum tax under HB 133, with the tax rates of North Dakota and Louisiana. He acknowledged North Dakota and Louisiana are not the perfect states to compare to Alaska, and there are other states with lower tax rates; however, Alaska is really not competing with shale oil states, but with jurisdictions around the world that have big traditional pools of oil. REPRESENTATIVE JOHNSON asked why Alaska isn't competing with shale oil states. REPRESENTATIVE GARA answered that some companies try to produce both, but shale oil is produced by a different technology that involves drilling well after well, because some wells only last two years. He has heard from tax experts that Alaska is actually competing with jurisdictions that have pools of oil similar to those found on the North Slope. 1:33:43 PM REPRESENTATIVE JOHNSON reported that ExxonMobil Corporation, one of Alaska's major producers, stated this morning it is looking to develop the production of shale oil at $40 per barrel, which sounded to her like direct competition [with Alaska]. REPRESENTATIVE GARA responded, "... Exxon is okay, I guess, with the North Dakota tax rate, which is much higher than what we have, if we're competing with North Dakota." He pointed out HB 133 is for the committee to assess, and if the committee believes the state is competing with North Dakota, Louisiana, or Norway, Alaska has a much lower tax rate. In the end, the legislature is supposed to determine a tax rate it believes achieves the maximum benefit to the public, as the constitution requires, and which, he stated, is a combination of [obtaining maximum] oil revenue for the oil the state owns, and also ensuring there is production. REPRESENTATIVE GARA directed attention to slide 13 and recalled the longest and much criticized tax regime in Alaska was ELF. Under ELF until 2005, the gross tax rate on Prudhoe Bay was 13 percent, and on Alpine and Northstar [oilfield units] it was approximately 10 percent; these fields represent the majority of the state's production. Under ELF - criticized as being too generous to industry - the tax rate on the aforementioned fields was double and triple that of current law. In fairness, under ELF, "a number of fields paid nothing in terms of production taxes [such as] smaller fields, [and] older fields. But Prudhoe Bay, [and] the places we had that got the majority of our production from under ELF, [oil companies] paid a much higher gross tax than [they] do right now." REPRESENTATIVE GARA continued to slide 14, and remarked: So, the reality is that producers, they will take home what they get after they pay everybody else, right? And, in Alaska that's largely the state. In other states, that's the state and private landowners. While our normal royalty in Alaska is about 12.5 percent, in Texas though, according to Mr. Ruggiero, it's now up to 20 to 30 percent. The Competitive ... the Competitiveness Review Board, the report that we got in 2015, back then the average Texas royalties were 12.5 to 30 percent depending on the landowner. Mr. Ruggiero says they're now 20 to 30 percent according to the landowner in Texas. California [is] 16 to 25 percent, North Dakota [is] up to 25 percent, [and] Oklahoma [is] up to 20 percent. The royalty share and also the land lease payments in those states tend to be much higher than they are in Alaska. REPRESENTATIVE BIRCH related his understanding from the commissioner of DNR that "Most of the leases that are going out now are one-sixth of royalty share, or one-sixth, or sixteen and two-thirds, whatever one-sixth works out to." He recalled some of the legacy fields, the older ones, are one-eighth, which would be 12.5 percent. REPRESENTATIVE GARA said there are a number of one-sixth fields now, however, Prudhoe Bay and Kuparuk are 12.5 percent fields. The general view of DNR, he opined, is that on the more promising fields, higher royalty is part of the contract. He explained: Oddly enough, under current law, you basically lose the benefit of the higher, higher royalty because there's a provision in the current law that says "Even for those more generously profitable fields that you have a 16 percent royalty on, we just give you the money back in a lower production tax rate." So, it's a wash right now under current law. 1:38:28 PM REPRESENTATIVE GARA further explained under any tax system, a particular field may not have the right tax and therefore is not profitable. Royalty relief is a repair mechanism to ensure that the overall taxes charged by the state - production taxes and royalty - are not too high. If a company can prove a field is not economic under the current royalty system, most of the royalty can be waived. Or DNR can issue royalty orders which specify that at low prices, most of the royalty will be waived, in order to make the field economic. For example, royalty relief applications from Oooguruk, [Nikaitchuq], and Nuna have all been granted [slide 15]. Furthermore, royalty for new fields can be reduced to 5 percent to make a new field economic, and if costs to a producer change, including a change in taxes, royalty on a producing field can be reduced to 3 percent. Thus, he said, the state would receive one-fifth of the 16 percent royalty [the state is due] if DNR determines that royalty relief is necessary to keep a field economic [slide 16]. Royalty relief statute is AS 38.05.180 [slide 17]. He reiterated that royalty relief was granted to Nuna in 2014, and to Oooguruk and [Nikaitchuq] [slides 18 and 19]. REPRESENTATIVE GARA informed the committee ConocoPhillips is the only oil company that reports its Alaska profits, as it is required to do so by the Securities Exchange Commission (SEC). As an aside, he said BP also lists Alaska profits, but one year included the cost of the Deepwater Horizon [4/20/10 oil well explosion and] spill [as a loss], therefore, he questions BP's veracity. Returning to ConocoPhillips, he said in 2016 Alaska was one of the highest generating regions in the world for ConocoPhillips, generating $116 million in profits for the fourth quarter, although the company lost money overall. Representative Gara attributed Alaska profits for ConocoPhillips to Alaska's larger pools of oil, and ConocoPhillips' interest in Prudhoe Bay, Alpine, and some of the more profitable fields [slide 20]. In past years of higher oil prices, ConocoPhillips' profits in Alaska were approximately $2 billion on an annual basis [slides 21 and 22]. Slide 23 illustrated that by FY 19, if HB 133 is adopted, it would generate about $200 million in additional revenue; however, the amount of additional revenue from any new legislation will depend on the price of oil, and the oil price is projected to be about $60 per barrel by FY 19, and $78 per barrel by FY 24 [slide 24]. 1:43:07 PM REPRESENTATIVE BIRCH turned to the larger issue of tax credits and inviting new development, and recalled the initiative that encourages smaller investors has been fairly successful. He asked whether Representative Gara agreed that the credit program was generally successful. REPRESENTATIVE GARA remarked: When you have a tax system that generates a large amount of money, you can afford to be an investor in new oilfields with very generous credits. When you have a tax system that is generating almost nothing, you can't afford to do that. Whether those credits lead to new production - a company will always say that. Do we know that's true? Possibly, possibly not. And, I know this committee is looking at that. I am not one for taking somebody who receives money at face value when they say, "that money was really good to me and really important." They will always say that. You should have some independent experts that tell you whether or not they are working. I'll tell you, in Louisiana, their credit is basically a two- year credit on horizontal drilling, from 1994, when horizontal drilling was new. And you can only take the credit for the cost of the well, and you can only take that for up to two years and if you can't deduct it within two years, you can't use it. It has been testified, when I've been around, that no other jurisdiction in the world has the same combination of low tax revenue take and high credit payments as Alaska. Alaska is unique in the world in that combination of the revenue it generates and the credits it pays. REPRESENTATIVE GARA stated he has no interest in going back to the ACES mechanism, or debating whether ACES was better than Senate Bill 21. The maximum profit take under ACES on production tax was approximately 75 percent, and under HB 133 the state would do better at low prices, and not as well at high prices; in fact, HB 133 is a compromise that is "modest on both ends" [slide 25]. Turning to the second feature of the bill, he reminded the committee that the profits tax for GVR fields can be next to nothing: below and around 10 percent at very high prices. For non-GVR fields, until approximately $90 per barrel, the profits tax ranges from 10 percent to 12 percent, which he characterized as very low. Under PPT, the tax rate was 22.5 percent and ACES incorporated a base 25 percent tax rate. He pointed out there are few "profits jurisdictions" around the world with a 12 percent profits tax; HB 133 maintains the current approach that the state gets paid the higher of either the profits tax or the gross minimum tax. However, if oil prices rise to $90 per barrel, it is unfair that Alaskans would have to live off of a 13 percent profits tax, because that would be too generous to industry. Representative Gara explained as follows [slide 26]: So, we've imposed a new sort of higher of minimum tax, and that will be -- we will still have the mechanism for determining the profits tax under the current law, but it can't go below an effective rate of [22.5] percent. You can deduct below that your, your credits but ... having an effective tax rate of 9 percent, 11 percent - at $90 a barrel - [or] 13 percent doesn't seem sustainable to me. And so, we've adopted a very modest [22.5] percent profits tax as the higher of tax that ... would be imposed when it's larger ... than the gross minimum tax. 1:47:56 PM REPRESENTATIVE GARA noted the bill also incorporates former Governor Sean Parnell's first effort to reduce the ACES tax: [through] bracketing. Because at some point oil companies reach windfall profits range, HB 133 also addresses future high prices through bracketing. Under the ACES tax system, when the tax rate increased, the higher taxes applied to all oil, thus Governor Parnell and opponents of ACES proposed a bracketed windfall profits tax such that when companies achieve a $40 profit per barrel, there is a 10 percent profits surcharge; at a $50 profit per barrel, the [surcharge] would increase by 5 percent on the portion of net income between $50 and $60 per barrel; an additional 5 percent [surcharge] at $60 per barrel on that portion of net income between $60 and $70 per barrel; an additional 5 percent [surcharge] at $70 per barrel and above. Therefore, a company could have a 25 percent surcharge, but the incremental charges on the incremental value of oil would be much less [slide 27]. In summary, Representative Gara advised HB 133 provides the following [slides 28 and 29]: · a fair and modest compromise, with a higher gross tax at lower prices to protect the state, that would be fair to the industry, and that includes royalty relief · a modest profits tax at high prices · recognition that when the price of oil increases all should benefit REPRESENTATIVE GARA then presented slide 30 that showed an alternative provision for the committee's consideration, and remarked: We have a proposal that says at $50 a barrel the rate goes up to 5 percent - the gross minimum tax; and then it goes up goes up at every $8 increase at $58, at [$]66, at [$]74, at [$]82, and at [$]90, by 1 percent. We erred on the side of being conservative before we had modeling done on the bill. But, the state's share of the increase in a gross minimum tax would remain smaller than the overall revenue taken in by an oil company producer if we did it at every $6, and if we did it at every $6, and instead of going all the way up to 10 percent, just capped it at 8 percent. So, just four additional brackets instead of six. So, we did, 5 [percent] to 6 [percent] to 7 [percent] to 8 [percent] and stopped at a maximum 8 percent gross minimum tax, but we did it at every $6 price increase so at [$]56, at [$]62, at [$]68, [and at $]74. Next fiscal year we would take in an extra $200 million in revenue. The state's share for those, for that increase would allow for the producer also to take in extra profits and extra revenue that would be greater than the amount of money the state's share would be. So, their revenue share would be higher than the state's ... additional take. I think that's the better proposal, I didn't want to ... put it in the bill until ... it was modeled. But, that would be my personal recommendation, and not go all the way up to 10 percent - only go up to 8 percent. 1:52:09 PM REPRESENTATIVE RAUSCHER noted that the slide presentation alluded to progressivity and bracketing, and often referenced the ACES tax system. He asked whether Representative Gara recommended a return to ACES. REPRESENTATIVE GARA answered no. The legislature should learn from all of the previous oil tax systems and devise a system that addresses the valid concerns related to prior or current law, and that incorporates the best parts from those laws and is informed by the best advice available. He said, "Frankly, were that [Ballot Measure 1, Alaska Oil Tax Cuts Veto Referendum, defeated 8/19/14] to pass, I would have proposed a different law back then, and I had, as a matter of fact." REPRESENTATIVE GARA further described the alternative proposal: 5 percent at $50; 6 percent at $56; 7 percent at $62; capped at 8 percent at $70. At the point when the profits tax becomes bigger than the gross minimum, he said, "that would take over." The result would be $200 million in revenue in FY 18, rather than $100 million after credits. Representative Gara stated the bill would allow the legislature to start building the state again, pay back outstanding oil tax credits of almost $1 billion, and create one component of a revenue plan that would help get the state out of the red [slide 31]. REPRESENTATIVE RAUSCHER asked whether all would agree that more oil moving down the pipeline would be, in a large part, the answer to the current problem. REPRESENTATIVE GARA agreed that all seek more oil down the pipeline; however, it is not in the state's greatest interest to have more oil in the pipeline while receiving a zero percent production tax for the first seven years, during some of the most vibrant years of a field's production, "or a 4 percent tax after that." REPRESENTATIVE BIRCH referred to fiscal note [Identifier: HB133-DOR-TAX-03-03-17] found in the committee packet which indicated that approaching FY 23, additional revenue increases from $200 million a year to over $300 million per year "as you have a presumably, a declining throughput," and asked whether [the legislation] is basically a $300 million tax increase on the oil industry. REPRESENTATIVE GARA answered: When you're looking at those "out" years, where it raises $300 million a year, that's only because oil companies are reaping in much larger profits, so you would ... be taking a share as oil companies are getting a share from higher oil prices. So, that $300 million-year is at much higher prices than we have today, and I think an oil tax system should be written in a way where the state shares and industry shares in high oil prices. 1:56:00 PM REPRESENTATIVE GARA returned attention to GVR - gross value reduction - which reduces a company's tax payment to zero until approximately $70 per barrel for the first seven years, and then by approximately 40 percent of the tax rate paid by other fields. He said HB 133 would eliminate GVR for large fields that are presumably more profitable - 50,000 barrel fields - while recognizing that small, more challenged fields can still retain GVR. Further, the maximum length of the GVR benefit would be five years, instead of seven years. Turning attention to Cook Inlet, Representative Gara said under current law, after a certain sunset date, Cook Inlet [producers] will pay 35 percent profits tax; presently, producers are paying essentially zero, and the calculations resulting in "close to no production taxes in Cook Inlet" can be explained by DOR. The credits provided by the legislature for Cook Inlet production were intended to incentivize the production of natural gas, although when searching for gas, many companies found oil. The bill proposes a 22.5 percent tax on profits in Cook Inlet, but does not propose a gross minimum tax. In addition, a bracketed windfall profits surcharge is assessed after a company achieves $40 per barrel in profits; however, Cook Inlet is a challenged area and a $40 per barrel profit may never be achieved. He opined some tax is needed as right now, "Cook Inlet is all zeros" [slide 32]. REPRESENTATIVE GARA acknowledged the bill contains one mistake in judgment on his part, and one drafting error. The bracketed provision was not written as intended, thus there is an amendment available to address the aforementioned technical error [amendment not provided]. Further, there was no intent to increase the gross minimum tax on heavy oil, which is defined by the "Schrader Bluff and Ugnu definition of heavy oil," in that any field that has oil with a lower gravity than the Ugnu and Schrader Bluff reservoirs would not be subject to the rising gross minimum tax, but would be left at the existing gross minimum tax rate [amendment not provided]. REPRESENTATIVE JOHNSON asked whether Representative Gara had reviewed HB 111, and how HB 111 compares to HB 133. REPRESENTATIVE GARA pointed out HB 133 does not address tax credits, and he opined the House Resources Standing Committee should make a decision on tax credits. He restated that if the state has higher revenue it can afford to pay tax incentives, otherwise, it cannot. He added that there are two sides when it comes to the state's fiscal health: the revenue the state brings in, and what the state does in terms of incentives. The proposed legislation addresses the revenue side; in fact, the provisions in HB 133 protect the fiscal health of the state and allow it to move forward in a more economically vibrant way, while respecting company profits. REPRESENTATIVE JOHNSON inquired as to Representative Gara's opinion on changing tax policy almost on a yearly basis. REPRESENTATIVE GARA stressed that the two most unstable tax regimes possible are those that are too high, because there will always be efforts [by industry] to make changes, and those that are too low, because that affects investment decisions made in anticipation of changes brought by the public. Currently, the state has a too low tax regime that may be subject to an initiative and/or future legislation. Preferable to changes - brought by industry or the public - is passing legislation such as HB 133 that would provide more certainty to the oil industry. 2:02:20 PM REPRESENTATIVE BIRCH opined there is stability in Senate Bill 21. He suggested comparing the cost of production in Alaska with the cost of production in competitive fields in the Lower 48, excluding royalty, which has been discussed. He cautioned that bankers who have invested in small producers based on the state's promise to pay their exploration costs, have indicated there is a very competitive market for capital. He asked if the bill sponsor had compared the cost of production in Alaska with that of other jurisdictions. REPRESENTATIVE GARA said yes. As a legislator, he has listened to an unknown number of oil tax presentations from experts, "And it's not as simple as just taking the cost"; in fact, there are significant cost differences between producing a Shell oilfield and drilling for shale oil, which can be done with many small wells. All things being equal, drilling a large pool of oil is more efficient than drilling for tiny amounts of oil with large numbers of small wells. In addition, one could compare production in Alaska with offshore oil production in the Gulf of Mexico, although the cost per barrel of offshore oil production is much higher than oil production on land. There is no simple answer as to where Alaska ranks in terms of cost, he advised, but a profits tax equalizes the fact that the costs may be higher; furthermore, there is not one decisive comparison factor, but many comparison factors. REPRESENTATIVE PARISH returned attention to slide 6 that showed production tax net of tax credits earned [in FY 18] was about negative $25 million. He asked about the state's net in the previous years of FY 16 and FY 17. REPRESENTATIVE GARA answered that prior analyses measured oil production revenue compared to what the state owes in cumulative years of tax credits. He was unsure whether 2017 was the first year the state owed more in tax credits than it received in production taxes. The state is hampered in its ability to pay the tax credits due to decreased levels of oil production tax revenue. 2:07:25 PM KEN ALPER, Director, Tax Division, DOR, referred to an earlier question regarding estimated per barrel costs for transportation, capital expenditures (CAPEX), and operating expenditures (OPEX). [Differing estimates of per barrel lease expenditure and transportation costs were shown in slides 8 and 10.] He said both estimates were from the current RSB, Appendix E tables. However, the estimate of $9.33 in transportation cost is the division's estimate for FY 17, the current fiscal year [slide 10]. The other estimate of $9.77 is the division's estimate for FY 18 [slide 8]. Therefore, this year, the total estimated cost is approximately $40 and next year the estimated cost is approximately $43. Last year, the division expected the cost for FY 17 would be $46, but company efficiency measures have reduced the oil industry's per barrel spending by approximately $5 per barrel in the current fiscal year. CO-CHAIR TARR suggested industry's changes in costs might lag behind the actual change in oil price because, for example, the companies cannot respond overnight with reductions in workforce. MR. ALPER advised each year DOR contacts industry regarding its plans for work in the next year, thus data is collected in September and October for inclusion in the Revenue Sources Book. For the industry, mobilization of workforce requires months or even one year's notice and depends upon each company's investment decisions and reaction to price changes. He opined once industry determined the drop in oil price was not going to immediately rebound, "spending has followed." The division's forecast from the fall of 2014 - when the price first dropped - was that oil price would be back up to $100 by FY 17. Soon thereafter, the division extended its negative outlook, and in spring 2016, forecast prices in the low [$]40s for the next two or three years. However, the fall forecast is a bit more optimistic. CO-CHAIR JOSEPHSON recalled discussion about the unofficial "[former Governor Jay] Hammond Doctrine" of oil industry taxes: [two-thirds for state and federal government, and one-third for industry]. Apropos of [slide 6], in 2018 state production tax was $230 million. He questioned whether legislators should ask if industry received $710 million, [approximately $230 million times three] or whether the state's portion of tax revenue should not be paid until oil prices return to $100 per barrel. He pointed out that the state is due billions of dollars, "of course, that's not possible right now." Co-Chair Josephson asked, "How do I know what the industry brought in, in 2018?" MR. ALPER returned attention to slide 6 that showed production tax, and explained total government take, or total non-producer take, is the sum total of all of the different taxes; in fact, an oil company working in Alaska typically has five different taxes: state property tax, state production tax, state corporate income tax, royalty, and federal corporate income tax. Total government take is a share of "divisible rents" - the total divisible profit from producing oil, which is more or less production tax value with the royalty added back into it as part of the divisible total. As discussed in a previous presentation, it is hard to track the share of the net because the division must use aggregated data taken from net profits tax filings; thus, the division does not have knowledge of any company's profits in 1995, because that information was not required. Further, the division's use of corporate income tax filings [to determine profit] is complicated by apportionment formulas and the complexity of corporate income tax. However, data is available from 1978-1981, a time period during which corporate income taxes were determined through a separate accounting mechanism. 2:13:49 PM CO-CHAIR JOSEPHSON questioned whether the division could use data from ConocoPhillips to extrapolate profits earned by other companies. MR. ALPER said probably, although in the years before 2006, the breakdown of ownership would need to be known; for example, ConocoPhillips may have 30 percent ownership. He added, "I suppose that would be possible ... [but] there's always going to be differences among the producers based on their corporate structure, their, what investments they're making at that moment in history, that sort of thing." REPRESENTATIVE WESTLAKE returned attention to slide 8, and referred to the discrepancy that was discussed earlier. MR. ALPER restated the estimate of $9.77 in transportation cost and $33.64 [in per taxable barrel in deductible lease expenditures], is the division's current forecast for the average [oil industry] spending in FY 18. In December  the tax division was asked to use the aforementioned data, assume the other features of the tax system, and calculate the average effective tax rate at a variety of price points; thus the data on slide 8 is taken from a letter to Representative Gara dated January or February , included in the committee packet. REPRESENTATIVE WESTLAKE said he understood the need to revisit the issue of tax credits, and asked whether [revenue information] on royalty is readily available. MR. ALPER answered that royalty revenue is fully documented and reported in the Revenue Sources Books [prepared by DOR]. He observed Prudhoe Bay, Kuparuk, and other major finds were discovered on state land; however, future production in the National Petroleum Reserve-Alaska (NPR-A), offshore, and the Arctic National Wildlife Refuge (ANWR), which are not located on state land, will not provide the state the same share of royalty. REPRESENTATIVE PARISH referred to Representative Gara's statement that BP reported deductions of Deepwater Horizon costs from its Alaska profits, and asked whether Mr. Alper had further information. MR. ALPER indicated no. REPRESENTATIVE GARA, in response to Representative Parish, clarified an example of why BP's annual reports could not be relied upon for an accurate rendition of their Alaska profits is that BP deducted some of its Deepwater Horizon costs, which are not allowed to be deducted from Alaska's corporate income tax; if BP is paying the gross minimum tax of 4 percent, there are no deductions other than the net operating loss. He pointed out Alaska's corporate income tax system works in a "funky" way, and deferred to Mr. Alper for an explanation of worldwide apportionment. 2:18:38 PM CO-CHAIR TARR asked Mr. Alper to briefly describe worldwide apportionment. MR. ALPER informed the committee oil companies have a global income number, which is their profit from around the world, thus taxes paid in Alaska are not necessarily on profit made in Alaska, but are on the amount a company made worldwide, multiplied by a series of ratios tied to ratios of Alaska activity to global activity, such as a payroll ratio, a property asset ratio, and an extraction factor. The resulting formula is multiplied and applied to regular corporate income tax for non- oil and gas companies, and to a special formula for oil and gas companies. He continued: The effect of that, on average, is a little bit less than the statutory tax rate. So, if you look at the corporate income tax statutes in [AS] 43.20, the top rate is 9.4 percent of profits. What we've learned, based on a track record of many years, is at this moment in history, the average oil and gas company is paying the equivalent of about [6.5] percent of their profits to the State of Alaska. So, the short answer there is, the net effect of that multiplier is that we're a little bit of a, a below-the-mean type calculation for the State of Alaska. And, that's why you sometimes hear talk about going back to this idea of separate accounting which would - at least in theory - bring us back to the 9.4 statutory rate. MR. ALPER, in response to Representative Parish, clarified that the percentage actually paid, on average, is a modeling convention of approximately 6.5 percent. For modeling purposes, he explained, the division deducts production tax paid from the income, or production tax value, and "the amount that is left after the production tax is what we calculate the corporate income tax on. And then to go further, after subtracting the corporate income tax, what's left after that, that's what you would calculate the federal corporate income tax on." 2:21:22 PM REPRESENTATIVE PARISH concluded that the state is receiving approximately 3 percent less in corporate income tax than the statute indicates. MR. ALPER agreed "on average"; however, the percentage will vary from company to company because each company has its own circumstances and ratios. REPRESENTATIVE PARISH further asked whether the global apportionment formula takes into account the higher average quality of Alaska oil - which is low gravity oil - in contrast with tar sands that are prevalent in other parts of the world. MR. ALPER was unsure and offered to provide a response from the division. CO-CHAIR JOSEPHSON questioned whether the state is receiving less than what is statutorily designated because the formula at the present time is affected by worldwide deductions, apportionment, and such. MR. ALPER said exactly right. For example, if a company's global share of income is $1 billion, Alaska's 10 percent of that would be $100 million, and if the share of property the company owns in Alaska is less than one-tenth of its global property, "that will reduce the multiplier in some way, those kinds of factors." 2:23:24 PM REPRESENTATIVE PARISH returned attention to the global apportionment issue and opined if the state is getting paid less, due to the aforementioned formula, somebody else must be getting paid more. MR. ALPER recommended that Representative Parish discuss this issue with the division's corporate income tax expert, Brandon Spanos, Deputy Director, Tax Division, DOR. CO-CHAIR TARR recalled there was previous legislation sponsored by Representative Seaton [House Bill 191 introduced in the Twenty-Ninth Alaska State Legislature] on this topic, and said over the years the monetary value of separate accounting versus worldwide accounting has added up to approximately $6 billion [in additional revenue to the state]. MR. ALPER related in 1978 the legislature enacted a separate accounting based system, which was adjudicated through the courts, and which greatly increased Alaska's revenue take. At that time, in 1978, Alaska had a lot of production and relatively low amounts of infrastructure. The state was brand- new to the oil business and not a lot of infrastructure had been built, thus "the multipliers were strongly in our favor." However, multipliers are shifting toward breaking even: Alaska is currently at two-thirds [rate of government take collected from industry] and was probably at one-third or one-quarter [in 1978]. Within the tax division, there is concern that a return to separate accounting may instigate manipulation of the tax system by taxpayers' sophisticated accountants. He gave the simple example of a major operator in Alaska that sells its Alaska operations to a subsidiary based in Washington State, and then leases the Alaska operations back for $5 billion per year; for corporate income tax separate accounting purposes, this would mean the major operator is now operating at a loss. He cautioned that the cumulative impact of a return to separate accounting is unknown. Furthermore, the division performed a rudimentary analysis for the fiscal note attached to Representative Seaton's bill, and estimated a change to separate accounting may have raised a couple hundred million dollars per year, presuming nothing else changed. REPRESENTATIVE JOHNSON requested the committee hear testimony from the [Oil and Gas] Competitiveness Review Board (OGCRB), DOR. CO-CHAIR TARR related there were no plans to hear from OGCRB. She added there was a delay in the board's work after the new administration took office, and she was unsure whether the board was fully appointed at this time. MR. ALPER advised that the 2015 Oil and Gas Competitiveness Review Board Report was made available to the committee. He explained that the most recent project on the board's [deliverables] cycle would have been a Cook Inlet analysis; however, the board chose to defer that analysis due to the major changes to the Cook Inlet taxation system that were made last year. The board recently began the process of hiring an outside contractor to look at various pieces of legislation, and how the board might compare and contrast Alaska's competitiveness, and he said, "So, I would doubt that there is much of, of interest, that's extremely timely, that could be brought to the committee now, although, later in session I think there will be at least a draft report to bring forward." 2:28:07 PM CO-CHAIR TARR said she would report to the committee on the status of OGCRB. 2:28:31 PM REPRESENTATIVE GARA closed, restating that the state contracts for a higher royalty on a field that it believes has the potential to be more profitable. During the debate on Senate Bill 21, an amendment was [adopted] to reduce the production taxes on [potentially more profitable] fields to reduce overall government take to that of the 12.5 percent fields; however, the benefit that lowers the production tax on 16 percent royalty fields is eliminated in HB 133. Finally, the gross minimum tax in HB 133 never gets to North Dakota and Louisiana levels. Representative Gara reminded the committee to subtract about four-tenths from the tax because 35 percent of the taxes paid to the state are deductible from a company's federal corporate income tax. He further explained: So, we can sort of piggyback a little bit on the federal government's decision not to accept as much of a share as it could, but if we raise taxes by 3 percent, we're really raising them by 2 percent because the company then gets that much bigger of a federal deduction. And the way our corporate tax works, you get to deduct your production taxes from your state corporate tax, too. So, you get two deductions for any tax increase, and so, any tax increase here really should be viewed as ... only about six-tenths of what it looks like because about four-tenths of that, the company doesn't really pay. CO-CHAIR JOSEPHSON, although not representing industry, suggested that one of industry's responses to HB 133 will be that Louisiana's fixed 13 percent tax rate is higher at oil prices through $90 per barrel, but HB 133 provides an opportunity for the state, theoretically, to get 35 percent at an oil price of $170 per barrel. REPRESENTATIVE GARA pointed out legislators have a duty to represent their constituents now, and now, no one anticipates world record oil prices of the amount it would take to get the profits tax under current law up to 35 percent. He said it's a mythical tax rate because never has there been an oil price that would have gotten the state [to a 35 percent tax rate]. In order to protect the future of Alaskans during the next decade, and provide a vibrant university system and schools in which Alaskan children can thrive, Alaska legislators need to look at the near-term - three years, five years, and ten years into the future - and HB 133 protects Alaskans over the next ten years; without this proposed legislation, the revenue the state needs now, for reasons the committee understands, will be lost. 2:32:56 PM REPRESENTATIVE RAUSCHER spoke of the confusion created for producers related to whether the proposed legislation is a permanent fix to the oil tax system. REPRESENTATIVE GARA agreed the legislature should not develop a partial oil tax system that would have to be revisited. He remarked: So, in this bill we've addressed the low-price problem of the zero percent production taxes on GVR oil, [and] the 4 percent gross minimum tax that we live on until $74 a barrel. So, that's the "for the next 10 years problem." But, we also address the next 30-year problem by also addressing the fair share we should be getting when companies are in windfall profits range. So, this bill has both provisions. One provision that probably won't kick in for many, many years, which is when companies are in the windfall profits range, [is] "What should our share be?" And, one provision for what we do now. And so, it's ... intended to be stable across all prices, and to be less aggressive than ACES was at high prices, but to be stable across all prices, rather than focusing on just now, or just later. REPRESENTATIVE GARA reiterated there are two amendments to the bill that better reflect the legislation's intent: 1. to not increase the tax on heavy oil; 2. to correct language on bracketing [amendments not provided]. CO-CHAIR TARR announced the committee's intention to have one [oil and gas tax] bill reported from the committee, therefore, the purpose of today's presentation was to hear other options that could be included in upcoming legislation. [HB 133 was held over.] 2:44:04 PM ADJOURNMENT There being no further business before the committee, the House Resources Standing Committee meeting was adjourned at 2:44 p.m.