Legislature(2017 - 2018)HOUSE FINANCE 519
03/22/2017 01:30 PM FINANCE
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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." 1:36:35 PM KEN ALPER, DIRECTOR, TAX DIVISION, DEPARTMENT OF REVENUE, continued addressing a PowerPoint presentation titled "New Sustainable Alaska Plan, Pulling Together to Build our Future; CSHB 111(RES)\N by the House Resources Committee, Oil and Gas Production Tax and Credits: Background and Bill Analysis" dated March 21, 2017 (copy on file). [Note: presentation also heard on March 21, 2017 and the morning of March 22, 2017.] He addressed Section 26 of the legislation on slide 62. The section involved several components of the legislation including the uplift and Department of Natural Resources (DNR) preapproval area. He addressed the uplift portion. He discussed a scenario where the state would not buy credits and instead the lease expenditures would roll forward in some way into a future year against future taxes. The question was how to compensate the taxpayer for only the fact that only a fractional portion of the costs would be allowed to move forward and how to compensate the company if they were not going to get value for several years (i.e. time value of money). The uplift section had been added by the previous committee to provide interest. Mr. Alper highlighted a scenario on slide 62 where a taxpayer had a loss of $100 million and carried forward $50 million in lease expenditures, the amount would earn interest, which was tied in statute to 7 percent plus the federal discount rate (currently 8.25 percent and scheduled to increase to 8.5 percent due to recent action taken by the Federal Reserve Board). The 8.25 percent interest would be added to the $50 million for up to seven years for a total of $87 million (roughly the equivalent to a 30 percent net operating loss (NOL)). The scenario reintroduced three variables that could be built into future debate, amendments, or other: 1) the carry forward percentage; 2) the uplift interest rate; and 3) the number of years the benefit could accrue. He explained that the numbers would change dramatically with any change to the variables. He detailed that with a full carry forward at a higher interest rate for a longer time period, the state could eventually be giving double or triple the original value. He relayed that the 7 percent plus the federal discount rate was the same as the interest rate in Section 2 (the interest rate on delinquent taxes) that the bill currently amended to limit to three years. He recommended linking the concepts together directly by tying the uplift rate to the interest rate statute. He suggested language reading "the amount in 43.05.225." Consequently, if one figure changed the other would automatically change. 1:40:09 PM Mr. Alper continued to address slide 62. The department needed clarification on whether the seven-year period accrued to the taxpayer for their first lease expenditure carry forward only. Alternatively, he questioned if a taxpayer have the ability to carry forward a loss from the second year for a seven-year period as well. The department assumed it was the latter, but the bill language was not completely clear. He turned to slide 63 and explained that the remainder of Section 26 related to preapproval of lease expenditures that would be carried forward. Vice-Chair Gara referred to slide 62 and acknowledged that under the current bill version the credit was less than it used to be. However, in most tax systems companies were not paid interest if they had to extend deductions over a number of years or had to roll their losses forward under federal tax for many years. He surmised an 8.5 percent interest payment to a company that was already getting a credit seemed like a profit on top of a credit. He wondered why the option had been chosen versus using the common option of enabling a company to roll forward credits until it was able to deduct them. Mr. Alper believed the question would be best answered by legislative consultant Rich Ruggiero who had created the concept and proposed it to the prior committee. His understanding was that the language more or less modeled some of the language in production sharing agreements with countries with a slightly different tax system. He detailed the idea was a capital recapture where there was no tax until a company made its initial investment back. There was also the government take share of the amount beyond that amount. He explained it was not unusual in those circumstances for there to be a built in profit or multiplier on top of the expenses before the sovereign began to receive its share. He qualified that his response was a bit of a guess, but it was his understanding based on testimony by Mr. Ruggiero. 1:42:51 PM Vice-Chair Gara stated that in prior tax discussions the legislature had always been told that production sharing jurisdictions around the world tended to have a higher tax rate. He continued that Alaska had a lower tax rate and the state was also giving companies interest on top of tax credits. He would need convincing the state was not getting the worst of all worlds. He recognized that the proposed credit was smaller than the one under current law. Representative Pruitt remarked that many times the state compared itself to other countries. However, Alaska was not a sovereign - there was still a federal aspect to the issue. He believed failing to include the federal component and comparing Alaska to a sovereign could be detrimental to the conversation. Mr. Alper answered in the affirmative - the federal tax was the last link in the chain. Whatever the companies end up paying to the State of Alaska ended up being a deduction against what they paid to the federal government. There were pros and cons to the method. He explained that as the state increased taxes, the federal government ended up receiving less; therefore, the net effect on the company was a bit less than simply the extra dollar paid to the state. Representative Guttenberg asked Mr. Alper to expand on the issue related to the state impact. Mr. Alper responded with a scenario where the state raised the tax burden on a large corporation by $1 million. He detailed that the company's profit would be reduced by $1 million as a result. He continued that most large oil companies paid a 35 percent federal income tax - the state's tax would mean the company would pay the federal government $350,000 less and would only be out of pocket $650,000. Representative Guttenberg asked if there were other considerations when undertaking the exercise. Mr. Alper answered that within the state income tax there was the apportionment formula and the interaction of Alaska's state tax with other states' taxes. For federal income tax, the primary difference was depreciation. For tax purposes the federal government treated capital expenditures differently - they were taken over a number of years and amortized or depreciated. Whereas, Alaska's tax system had 100 percent spending recapture in year one. 1:46:05 PM ED KING, SPECIAL ASSISTANT TO THE COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, addressed slide 63 related to lease expenditures. He noted that two provisions added to the bill in the prior committee impacted DNR. The first was the preapproval process for lease expenditures. Based on testimony provided, DNR better understood the intent. One of the department's largest concerns was the broadness of the language, which could be interpreted in a variety of ways. If the language was maintained, the department requested clarity about what the legislature wanted the department to accomplish. Under the current language it was possible that every line item of each lease expenditure ($6 billion annually) would have to be preapproved by DNR, which would be an arduous and expensive task. He furthered that the department's regulations would probably not be written in that way - DNR would probably automatically preapprove operating expenditures and similar items. The department's review process would likely be reserved for larger projects. He recalled prior testimony in reference to poor management or a project the state would not want to participate in. He suggested if there was a classification of lease expenditures the state was not interested in participating in, it was possible to enumerate the classification within existing statute rather than having the department go through a preapproval process. The department appreciated the deference and latitude; however, because the process involved tax law, it provided very difficult challenges for DNR to overcome if it were to deny an expenditure. Either DNR or the Department of Revenue (DOR) would have to defend in court that the decision had not been arbitrary, which was DNR's largest concern. 1:48:37 PM Co-Chair Seaton appreciated the testimony. He did not want the broadness of language to result in the significant in- depth analysis Mr. King referred to. He communicated that the committee would make sure to take the concerns into account. 1:49:09 PM AT EASE 1:49:25 PM RECONVENED Mr. Alper noted the presentation contained another four or five slides related to the fiscal note that he could address at a later date. ^INDUSTRY TESTIMONY 1:49:59 PM KARA MORIARTY, PRESIDENT AND CHIEF EXECUTIVE OFFICER, ALASKA OIL AND GAS ASSOCIATION (AOGA), introduced herself and provided a PowerPoint presentation titled "House Finance Committee CS for HB 111" dated March 22, 2017 (copy on file). She detailed that AOGA was the private professional trade association for the oil and gas industry in Alaska; it represented the majority of oil and gas companies (represented on slide 2). She read from a prepared statement: Collectively, governments in Alaska, local and state governments combined, this last fiscal year FY 16, received just over $2.1 billion in revenue from the oil and gas industry. This presentation and my testimony does have unanimous consent of our diverse membership. As with any piece of tax legislation that we've looked at over the last decade or so, we often use different guiding principles to weigh the proposal against. This bill is no different. Ms. Moriarty pointed to the guiding principles AOGA used to measure progress including production, investment, competitiveness, revenue, and "fair share" on slide 3. The principles had been used by AOGA when analyzing the original version of HB 111 and the current committee substitute (CS). She stated that the first four principles were very objective, it was clear and easy to weigh whether the bill would provide increased production, investment, competitiveness, and revenue; however, fair share was very subjective. As we examined the latest committee substitute for House Bill 111, it became clear that because of the vast number of changes, the bill definitely raises taxes and increases cost on the industry. The CS for House Bill 111 will not add more oil to the pipeline, it will not attract investment to Alaska, and it will put Alaska toward the bottom of the competitive scale. Throughout my testimony today I plan to briefly highlight the policy sections of concern. You will notice I will point out where the bill does not make any changes or has nothing to do with what many say need to be reformed or continued to be reformed and that's tax credits. There are several sections of this bill that have absolutely nothing to do with tax credits. There are several sections that were just changed last year. Ms. Moriarty turned to slide 5 and addressed the section on increasing the interest rate [Section 2 of the legislation]: Increasing the interest to six years of compound interest will simply increase our costs of doing business and this is a prime example of a section that has nothing to do with tax credits. 1:53:49 PM Ms. Moriarty addressed slide 6 on Sections 3 through 5 and 20 through 22 of the bill related to confidentiality and transparency: This is another section that was just changed last year. There were additional transparency requirements that were part of House Bill 247. There have been some claims that industry, even AOGA in particular, has supported the language in this current version of the CS. That is not accurate. To be clear, AOGA did submit some potential confidential language to House Resources last March. We have gone through and compared what we submitted to the House Resources Committee last year with Amendment 45 that I think was referenced on Monday, as well as the language that's currently in the bill and they are not the same. There is some very clear differences. The current version paraphrases some of the language that we submitted to House Resources and that paraphrased language as well as language that's omitted from the version in front of you are very important and substantive. Additionally, this version includes language regarding very broad authority for the Department of Revenue and it gives the department unfretted and unsupervised power in a variety of ways to request and disclose virtually any information it desires in either executive session or via the proposed new annual report. For a variety of reasons the industry does not support what's currently in the bill. Ms. Moriarty advanced to Section 6 regarding raising the minimum tax (slide 7): Section 6 or a version of Section 6 was in the governor's original oil tax bill last session in House Bill 247. Even though House Bill 247 was touted as a tax credit reform bill as House Bill 111 is, it had many provisions such as this one that has nothing to do with tax credits. Raising the minimum tax is not just a 1 percent increase. For some companies it represents a 25 percent increase and for other companies it's an infinite increase. Your consultant asked industry to be very specific about how they would change their investment behavior and my guess is you're going to hear that directly from some of the companies today. Last session, when we had a similar provision that would raise the minimum tax, there was testimony that this 1 percent increase could result in the reduction of a drilling rig for up to six months on the North Slope. That is significant. House Bill 111 will impact investment decisions. Companies won't keep investing money the same way they are today if these provisions are adopted. 1:56:48 PM Ms. Moriarty turned to Sections 7, 10, 12, 13, and 16 related to hardening the tax floor on slide 8: Not allowing credits to be applied to the minimum tax floor is a tax increase. While this one is directly related to credits, this proposal changes a key provision of the purpose of credits. For some companies using credits against the minimum tax is the only way they continue to invest money, especially in a low price environment. Another key section of Section 7 is this issue of migrating credits. If you're looking at making the tax system less complex, you should eliminate this part of the bill because this proposal actually makes the tax system more complex. It moves the tax to more of a monthly tax and this section would require companies to accurately submit estimates each month versus doing a true up at the end of the year. So, you have to ask yourself if you were a business owner, would you like to file your taxes on an accurate estimate every month versus having an annual true up so you can utilize the very incentives that attracted you to invest in the first place. For us, this is a tax increase and changes the key provision of the current tax system. Ms. Moriarty addressed Sections 11 and 18 related to net operating loss (NOL) credits (slide 10): One part of the NOL credit, and we'll get into NOLs later as well, if you no longer allow an NOL for a cash payment it's almost a double whammy for some companies because the NOL has been said time and time again to be a playing field leveler, especially for small companies on the slope. These two sections really can impact small and newer companies to Alaska. 1:58:58 PM Ms. Moriarty turned to slide 11 related to the changes in the per-barrel credit. Before I go into the changes on the per-barrel credit, I just want to go back and talk about how these so called credits, the per barrel credit, came about. When Senate Bill 21 was originally drafted the tax rate was 25 percent. After it was introduced and during some of the modeling, the Department of Revenue and the legislature recognized that it was going to be a very regressive tax and the effective tax rate would be dramatically lower at lower prices - and they did not want that to happen. So, the department and the legislature worked together to create nothing more than a math formula, which kept the tax rate at about the same percentage across a wide range of prices. That actually added an element of progressivity back into the tax, versus what was originally proposed, which was really a regressive tax. By its very design, it was never the intent to have an effective tax rate of 35 percent. The tax rate was 35 percent with this math formula to incentivize production and that's exactly what it did - it incentivized investment. You're going to hear about projects and production that came online after Senate Bill 21. This math formula kept the tax rate at about 25 percent over a range of prices and that's what's referred to as the per barrel "credit" because changing the per barrel credit now changes the structure of the tax. It would be an immediate tax increase on core fields that provide a little more than 90 percent of our current production. It's not just us as industry who have described it that way. You've had legislative consultants at the time, you had DOR officials at the time, DOR officials today, who recognize that the per barrel credit is not really a credit in the true sense of what you think of it as a credit. Enalytica, the consultant at the time, described the per barrel credit as a misnomer. The current Tax Division Director, Mr. Alper, previously confirmed that very notion. Even though he was not part of the creation of the math formula, he is on record as saying this about per barrel tax credits. This is from a joint House and Senate Resources hearing down on the Kenai Peninsula in June of 2015: "Some of them (credits) are integral parts of the tax regime; the 20 percent capital credit in ACES, the per-barrel credit in SB 21, those are very much offsets to what would otherwise be a very high tax rate." So Director Alper recognizes that a 35 percent effective tax rate is a very high tax rate. He goes on to say: "With SB 21 the credit is an offset to the tax and is designed to create a progressive element, a little bit lower tax rate at lower prices, a higher tax rate at higher prices, so it's hard to really consider them a credit in the context of an inducement to doing work. It's really what we are calling an integral part of the system." So, just know that if you change this per barrel credit, you are making a fundamental change to a very integral part of the tax system and we would argue that this "credit reform" is not really targeted at the credits that I think most are referring to when they talk about credit reform. 2:02:54 PM Ms. Moriarty addressed the proposed new dry hole credit on slide 13. So now we have a new credit in this CS and that's the dry hole credit. For us the policy objectives around the dry hole credit are a bit unclear. The credit would be limited to companies that do not produce oil or gas in the calendar year in which the credit is earned, which frankly would severely limit the eligibility. So, a company could have production elsewhere in the state but if they produced oil they would not be eligible and it disregards production thresholds already in place for the purchase of credits. The other interesting thing to us is that the credit can only be taken if the company gives up the lease, which feels a little awkward to us to us because the explorer that drilled the dry hole would have the information gained from that drilling, they would be the most likely to drill another well on that lease, and would likely stand a better chance of success than a different company. My guess is you'll hear more about that from some of the explorers today. We also think that the surrender of a lease to the state would signal a lack of value and decrease interest in the lease to third parties, while depriving the state of lease rentals prior to a successful lease sale. For us, this seems a bit counterintuitive and again, the policy objectives are a bit unclear for us around this new proposed credit. 2:04:32 PM Ms. Moriarty addressed Section 19 on slide 14. Even though it may seem moot now that the NOL - if it goes back to the original version, is reduced, or is converted to a deduction - this section brings a lot of uncertainty around how it would apply, the language is not very clear to us, and so it leaves more questions than answers for us. Ms. Moriarty advanced to slide 15 and addressed Section 23 related to the gross value at the point of production (GVPP): The gross value at the point of production, we testified to this last year during House Bill 247 and the testimony is the same. We believe by changing the structure of the tax, by preventing the gross value at the point of production from going below zero, creates uncertainty. This is another section that doesn't have anything to do with tax credits. Ms. Moriarty moved to slide 16 and discussed the NOL credit: I think that in some sense both inside the legislature and outside, there's a lot of misinformation about what an NOL is and what it's not. Generally, throughout this whole NOL conversation, the NOL has generally matched the tax rate throughout Alaska's net tax system. This provision that's currently being proposed would penalize companies for investing in Alaska, while they're losing money. Reducing or changing the NOL from a credit to a deduction was never part of Governor Walker's original piece of legislation. In fact, early on when Governor Walker's administration testified to House Bill 247, they recognized that the NOL was an incredible part of leveling the playing field for companies and so they didn't believe the NOL should be changed back then. The proposal before you converts the NOL from a credit to a deduction. As I said, I've probably received more questions about what is an NOL, what is it, how does it work? I went and looked in a business dictionary and this is how they define the NOL: "A net operating loss is the amount by which net expenses exceed revenue in an accounting period." All that means is an NOL is when expenses exceed revenue. Something as business owners, or even frankly as my own personal finances, you don't want your expenses to exceed your revenue. When Senate Bill 21 was written they made the NOL a credit. That was the decision that was made at the time. This bill would change that and it would make the NOL a deduction. If a company has expenses that exceed revenue, they would then deduct that expense when they have revenue - pretty standard. Ms. Moriarty referred to an example related to NOL on slide 17: We put this example together and I think it's a visual illustration that shows the difference between a company who has gross revenue of $1,000. Let's just say for simple math everybody has gross revenue of $1,000 and everybody has the same tax rate of 25 percent. But Company A doesn't have any deductions and so they can't deduct anything. You have your taxable income of $1,000, your tax rate's 25 percent - simple math $250 is the tax bill. But Company B, same income, you have $200 worth of deductions, and you have taxable income of $800. Then you apply the 25 percent tax rate, it gives you a final tax bill of $200. It changes your tax bill by $50. It's why we all want to claim our mortgage interest as homeowners. Then Company C, let's say they don't have any deductions, so their taxable income is $1,000, then the tax is applied at $250, but they have a $200 credit. Now all of a sudden they can deduct the credit after the tax is applied so they only have to pay a $50 tax. So the main difference between going from a deduction to a credit or vice versa is that the deduction is taken before the tax is calculated and a credit is taken after the tax is calculated. That's the difference that you're now considering. 2:09:27 PM Ms. Moriarty addressed slide 18 and referred to testimony from Mr. Rich Ruggiero (legislative consultant): Mr. Ruggiero from Castle Gap Advisers is your legislative consultant now and when he was here a couple of weeks ago he advised that the state should change your NOL from a credit to a deduction. But the bill's current language does not reflect his complete recommendation, because companies would not be allowed to deduct the full value of their loss and of these expenses generated. And the uplift provision is not the way he recommended. So, the current way the uplift language reads would negatively impact economics for all companies in Alaska. Ms. Moriarty moved to slide 19 and provided quotes by Mr. Ruggiero from a March 1 Senate Resources Committee meeting related to changing the NOL from a credit to a deduction and including an uplift: "Every regime, everywhere you go, allows, especially with a development like Smith Bay, everyone who develops gets to deduct the cost of what it took them to get that production from future revenues from that project. Every regime." "To deny that would really move Alaska to the bottom of the competitive scale." Ms. Moriarty elaborated that denying the full value of the loss or the expense would put Alaska at the bottom of the competitive scale. She read an additional quote by Mr. Ruggiero: "Various Countries have different ways of dealing with this. Where there's a long lead time, between when the money is spent and when actual production comes on, they'll offer forms of uplift which is another way of saying interest as it's carried forward so that way time value loss does not become a big kicker to their economics." Ms. Moriarty explained that under the current language it was a big kicker to the economics and did not reflect Mr. Ruggiero's recommendations to the legislature. 2:11:30 PM Ms. Moriarty discussed Section 26 related to a new regulatory process created by the bill (slide 20): We obviously have a lot of concerns about this. When I talk about Alaska when I'm asked to speak at a variety of conferences or give a perspective on what's good and what's bad in Alaska for the oil and gas industry and our regulatory challenges have always been on the federal side - I've always been able to say the state regulatory system does a great job in providing some of the most stringent regulations on the industry but they regulate us in a way where we know the rules and then we're allowed to do the work and we move forward. But this section would change all of that, because this preapproval process as has been described would require preapproval of any expenditure before it could qualify for a potential net operating loss deduction. And if you change NOLs to a deduction that's a very important part. We don't know for the most part at the time of the expenditure if you're going to be in a net operating loss situation, so that's why we do believe that unless this language is tightened up or more clearly defined, the way it's currently written, you would have to have almost every single expenditure preapproved. And then there's a lot of unanswered questions because what would happen if DNR says "Okay, you can build that ice road to do your exploration work, to get that drilling rig out to any pad in the winter time...yep that's preapproved, that would qualify for a deduction." But six to seven years later on audit, the Department of Revenue says "nope, that doesn't qualify." So who is going to win in that scenario? We can tell you that the regulatory process does not always make statutes easier to understand. If you look at our current statutes around deductible lease expenditures, it's described in about three or four different places in statute, there is a very lengthy regulation process, and even DOR right now has different definitions of what qualifies and what doesn't. This would just add another layer and causes us great concern. 2:14:04 PM Ms. Moriarty addressed Section 27 on slide 21 that would repeal the statute that allowed tax credit certificates and proceeds to be assigned to third parties: This is very important for some companies and their project economics because this ability to sign tax credit certificates and proceeds provides really valuable liquidity in early stage projects and it does improve project economics. It allows the credits to be used as collateral and as a source of repayment of project costs through financing arrangements or in joint ventures. Frankly, there's no negative fiscal impact to the state when those tax credit certificates or proceeds are assigned to a third party. But the way this repeal would work and the way its currently written would actually have a retroactive impact. Why do I say that? It's because there are some parties who have already agreed to assign credits generated by expenditures happening right now in 2017, but they won't be able to apply for that credit application until after January 1, 2018. This change would significantly impact some current commercial arrangements. 2:15:32 PM Ms. Moriarty addressed slide 22 titled "Would you invest in Alaska if tax policy changed 7 times in 12 years?": It's been stated that the oil and gas industry is constantly evolving so why do we care about oil taxes changing. Part of that is true, the industry is constantly evolving. I'm glad, because technologies improve and techniques improve to tap additional resources. We are able to develop better monitoring systems to take care of the environment, but global markets and prices - you can't control that and can't predict them and certainly there's always geopolitical changes that impact the industry. But the one area that can remain a constant if the government chooses to is the fiscal system. We just think there is a lot of misinformation right now about how these are being characterized. This would be the seventh change in twelve years and there have been some who've said the industry has asked for over half of these changes. That is not true. Of these seven, the six that have taken place and the seventh one before you, the industry has supported two. We only asked for Senate Bill 21. We didn't ask for the Cook Inlet Recovery Act in 2010. If those statements are made, it's not accurate. Alaska has a lot of potential, the Department of Revenue will say it, everyone will say it. We have great rocks and we have great geology. But this bill has the potential to lose out on long-term revenues over time through lost royalties, production tax, corporate income tax, property tax, if projects never come online. Or if production decline goes back to 4 to 6 to 8 percent decline, you could lose out more over time on lost royalties alone than you would make up in the increases that the bill would put in place. So last but not least, the two principles around revenue and fair share. Fair share is truly in the eyes of the beholder. I'm not going to tell you what the state's fair share should be. Not for me to determine. What this slide shows you [slide 24] from the Department of Revenue - is government share today net of credits. You can see in the orange, which is the top bar, that's the state's share. The state takes the largest portion of the share at every single price. And when the company is underwater, which is the blue section - you can see when we're underwater under $45 - the state is still collecting revenue. 2:18:27 PM Ms. Moriarty advanced to slide 25 comparing Alaska with other locations: It's also been stated that we don't really need to compare ourselves to other fiscal regimes; however, if you look at this chart, the blue line is oil price from January of 2001 to January of last year. You can see as oil prices go up, governments do take more - that's the orange box. But as prices go down, generally, and if you look at January of 2016, of all the major oil and gas regions (not every country), every single one of them in January of 2016 was creating fiscal incentives as the price was decreasing. Ms. Moriarty summarized on slide 26 that gaining a larger portion by the state would not close the fiscal gap. She sympathized with the desire for a fiscal plan. However, the bill raised taxes at every oil price and at significant rates when oil prices were low. For example, at oil prices of $20 per barrel, the bill raised over $400 million more for the state when the industry was losing money in a big way. She underscored that the bill would not put more oil in the pipeline. She emphasized that the state could not expect companies to take on the increased cost and continue to invest money in Alaska. She reasoned the same would apply for any business the state was trying to attract (e.g. hospitals, Native corporations, auto part stores, fishing fleets, restaurants, or hotels). She detailed that the state could not expect businesses to come to Alaska and then raise their taxes regardless of how much money they're making and expect them to continue to invest at the same level. She hoped the committee would reconsider some of the most concerning portions of the bill. Co-Chair Foster thanked Ms. Moriarty for her presentation. He provided information about the afternoon agenda. He asked the committee to hold its questions until the end of each presentation. 2:21:43 PM Vice-Chair Gara believed Ms. Moriarty thought the current tax rate was fair. From his perspective a fiscal plan needed to be fair not only to the wealthy but to lower income Alaskans as well. He stated that for new oil the production tax on profits was zero and at $70 per barrel of new oil in an average field on the North Slope the tax was 0.3 percent. He asked if Ms. Moriarty believed it fair to the people of Alaska. Ms. Moriarty answered it would be up to the legislature to decide what was fair. From AOGA's perspective, the new oil provisions had been put in place for a reason. She detailed that Alaska had a very high cost environment. She had not spoken about the cost per barrel, but many of the new fields were expensive to bring online and represented less than 10 percent of current production. Going forward the majority of the production would continue to come from legacy fields. The provisions had been created to incentivize companies to come to Alaska to explore, develop, and produce in very high cost, high risk areas. She reiterated it was a decision the legislature had to make, but the provisions had attracted new companies to Alaska and had resulted in increased production for some in the last several years. Vice-Chair Gara discussed that the production tax rate was 4 percent for the larger fields until about $73 per barrel, which he considered a problem. He referenced slide 18 where Ms. Moriarty had expressed a concern that a credit was only for half of the cost. He explained that the credit was half the cost because the industry was receiving a deduction that was more than double the actual tax rate paid by companies. He agreed with Ms. Moriarty's statement that there was really no 35 percent tax rate. He stated that the real tax rate paid by companies were in the low double digits and as low as 7 percent. Currently companies were allowed to deduct 35 percent of their costs. He remarked that in other jurisdictions the deduction rate is the same as the tax rate; however, in Alaska the deduction rate was two to three times the actual tax rate, which was the impetus for the 50 percent number. He asked if it sounded fair. Alternatively, he wondered if the state should match the deduction rate with the actual tax rate. Ms. Moriarty answered that talking only about what the industry paid in production tax did not take the full picture into account. She explained that only looking at production tax could give the false impression that it was all the industry paid. She detailed that at every oil price the industry paid royalties, income tax, and property tax. She underscored it was necessary to look at the overall government take. She stressed that the state was taking the largest share at every oil price. She pointed out that the legislature's consultant [Rich Ruggiero] had communicated that if a credit was converted to a deduction and the state did not allow a company to deduct all of its expenses prior to the start of revenue generation, it would be a disincentive to investment. She suggested asking the consultant about the reason for his recommendation. 2:26:26 PM Vice-Chair Gara stated "we just have a disagreement." He noted he did not need to follow up [with the consultant]. He believed allowing triple the deduction rate a company paid in taxes was very generous. Representative Ortiz referred to Ms. Moriarty's statement that the changes in HB 111 would put the state at the bottom of the competitive scale. He asked where Alaska fell on the competitive scale at present. Ms. Moriarty responded that her statement that Alaska would be at the bottom of the competitive scale had come from Mr. Ruggiero's testimony about what would occur if the state did not allow 100 percent deduction of the costs. She noted that the bill did not reflect that. She stated that Mr. Ruggiero may have a better sense of where Alaska stacked up competitively. Based on her study of various oil and gas journals, blogs, and other, there were very few regions - even in the $40 to $50 range - currently considering increasing government take. She believed Alaska had been competitive because companies had continued to invest money at low oil prices, production had increased, and money continued to be invested in Alaska even as some companies were contracting [investment] elsewhere. She concluded that if cost was added, it would change the competitive nature. Representative Ortiz asked for verification Ms. Moriarty believed the state was pretty competitive under current law. He asked if that was what she meant to imply with her previous answer. Ms. Moriarty replied that the state's current tax system had been attracting investment and production to Alaska; therefore, in that sense AOGA did believe the system was competitive. She believed there was significant pressure to be competitive. She referred to substantial talk about where the state's effective tax rate was in the single digits. She explained that was also when companies had been "bleeding cash" and were underwater. The industry was still paying revenue to the state even though it was not making any money at low prices. There was a balance - if prices were to increase, the industry would retain some of the value on the upside. The industry would prefer to see the current balance maintained. Representative Ortiz referred to the 35 percent tax rate. He noted Ms. Moriarty had pointed out the industry also paid other taxes including on royalties. He asked if there were other locations worldwide with the other taxes as well. He surmised that Alaska did not set itself apart by having a royalty tax. He asked there were any taxes Alaska had that other jurisdictions did not, which resulted in Alaska being less competitive. Ms. Moriarty answered that it was very common for tax regimes to have a royalty paid to the landowner, a production tax, an income tax, and a property tax. She stated that a couple of factors made Alaska that were unique. The state was a long distance from the market, which made transportation costs much higher. Additionally, the operating and capital costs were higher. She expounded that because of those factors, Alaska needed to have large fields. She furthered that there were numerous shale plays on the North Slope that had become necessary in the current price environment. She detailed that the cost of producing shale had decreased. She explained that when discussing competition, it was necessary to look at the entire picture. She specified that only looking at production tax failed to recognize all of the other things the industry had to contribute. She relayed that increased costs would only increase the cost of doing business. Based on her understanding, there were very few regimes currently looking at increasing costs through production taxes or changing net profit share leases. Different regimes had different levers to pull and Alaska was one of the few looking at changing taxes. 2:32:19 PM Representative Ortiz asked if Alaska was the only location paying out cash credits. Ms. Moriarty did not know if any other location in North America paid out cash credits. She recommended asking the legislature's consultant during a meeting the following day. Co-Chair Foster provided the list of the upcoming testifiers. Representative Pruitt spoke to Section 7 related to migrating credits - he referred to Ms. Moriarty's testimony "accurately submit estimates." He surmised that the word estimate did not mean 100 percent accuracy. He asked if the monthly accurate estimate was done elsewhere in other regimes. 2:34:30 PM Ms. Moriarty recommended asking Mr. Ruggiero the question the following day. She could follow up after speaking with AOGA member companies. Representative Pruitt spoke to the new dry hole credit. He noted he had asked about its genesis the previous day, but he did not fully understand where it had come from and who supported it. He referred to Ms. Moriarty's testimony that the new credit did not seem to provide value to the industry or the state. He added that Ms. Moriarty had specified that the opinion was approved by all AOGA members. He asked for verification that Ms. Moriarty was speaking for all AOGA members by indicating that the new dry hole credit did not seem to provide value to the industry or the state. Ms. Moriarty replied in the affirmative; none of the 12 companies AOGA represented believed the credit would provide value to the industry or state. Representative Wilson remarked that "we" have continuously heard that oil companies would have increased oil production without SB 21 [oil and gas tax legislation passed in 2013]. She asked if Ms. Moriarty agreed. She wondered how a hard floor of 4 or 5 percent impact the volume of oil coming down the pipeline. Ms. Moriarty responded that Alaska's Clear and Equitable Share (ACES) had penalized investment and investment had been stagnant at that time. She believed it would be very difficult to imagine that an increase in production would have occurred without SB 21. The forecast had not predicted and increase and at present that forecast had been beaten. Representative Wilson reiterated her second question. She explained that the previous year there had been significant talk about the 4 and 5 percent hard floor not actually representing a hard floor. She stated that the bill contained both: a 4 percent floor and a 5 percent floor depending on the price of oil. She asked how it would impact oil coming down the pipeline. Ms. Moriarty answered that the two sections - hardening the floor and increasing the minimum tax - would impact industry investment. She explained that there would be less investment and less production if prices did not change. 2:38:02 PM Vice-Chair Gara listed fields where investment had occurred prior to SB 21 including Point Thomson in 2015, CD5 before 2012, and Moose's Tooth and Bear Tooth. Additionally, Repsol had announced investment of $750 million prior, expansion had been going on in Kuparuk to stem the decline for many years. He asked for an example of a field where investment had not started prior to the implementation of SB 21. He pointed to Smith Bay as a possibility, but he was not certain when the lease had first been purchased. Ms. Moriarty did not recall the slide used by ConocoPhillips in a House Resources Committee meeting, but the slide had summarized investment decisions made and projects brought online after SB 21 had passed. She referred to Caelus's Nuna field as an example of investment after SB 21. She referred to Hilcorp's Liberty field, which was moving forward and providing 70,000 barrels per day. Some of Armstrong's additional investment had occurred after SB 21 and had led to the company's announcement two weeks earlier. She could absolutely point to the fields and was happy to provide a report. 2:39:47 PM Vice-Chair Gara stated the investment on virtually all of the fields mentioned had started prior to SB 21 as did the lease purchase. He was certain that companies would say they would have stopped investment if SB 21 had not passed. Ms. Moriarty offered to compile a report summarizing investment decisions, fields, and projects that came online after the passage of SB 21. Vice-Chair Gara stated "or the investment started before SB 21." Ms. Moriarty replied "absolutely." She stressed that investment had occurred after SB 21 had passed that had not previously been occurring. She stated that companies were happy to compile a report if desired. Representative Thompson remarked that increased production had been seen since the passage of SB 21. He reasoned that there had also been substantial investment where the state had not yet seen the results from SB 21. He believed making changes [to the tax structure] at present would be premature before the results were realized. Ms. Moriarty responded that on some discoveries companies still needed to fully delineate what was there. Additionally, some projects were still in a permitting phase. She agreed time and additional exploration and delineation work were still needed to determine what was there and when it could come online. 2:41:27 PM Representative Grenn spoke to Sections 3 through 5 related to making taxpayer information public. He asked how the sections impacted each company. Ms. Moriarty answered that a concern about the current bill language included the broad authority DOR could have. For example, based on the current language, it was feasible to see where DOR could ask a company what it paid all of its contractors. There was concern about disclosing what a company paid contractor A for transportation, contractor B for hot oil, and contractor C for an ice road. The businesses were all competitive and AOGA did not support the information being publicly disclosed. Representative Pruitt asked if there were any SEC [Securities Exchange Commission] or IRS [Internal Revenue Service] issues with some of the proposed language in the particular sections [Sections 3 and 5]. Ms. Moriarty replied in the affirmative. The current language would allow disclosure of some information that was already protected through other federal regulations. There was a concern from a variety of aspects. Co-Chair Foster indicated that Mr. Seckers would be testifying next. 2:44:05 PM DAN SECKERS, TAX COUNSEL, EXXONMOBIL, thanked members for the opportunity to testify regarding ExxonMobil's concerns about the legislation. He read from prepared remarks: While I am pleased to be here to discuss our views on this CS, I have to say that I am disheartened by the fact that once again I'm here to testify on the state trying to raise taxes on the industry again even though we're struggling with the current economic downturn. An effort not only to raise taxes, but also to change the state's policy for the seventh time in less than 13 years. As you've heard testimony already, such reexaminations and frequent changes serve to undermine the investor confidence in Alaska, Alaska's tax policy, and to weaken Alaska's overall investment climate for attracting continued and future investments. For any tax policy to succeed and to meet the state's long- term objectives for revenue and investment that policy must be competitive, stable, predictable, and provide confidence to taxpayers and investors that the underlining rules of the game won't be changed, otherwise they will adversely affect the economics of decisions. It's been stated by others that part of this effort with this committee substitute is to provide some sort of durability. That if you pass the committee substitute, magically this will provide durability to the Alaska oil and gas system. Durability and certainty were terms that had been thrown around every time there's been efforts to change taxes in Alaska. While durability and certainty are important aspects to any sovereign's tax regime, such durability and certainty lose its value if it comes at too high a cost. Make no mistake, as you've heard testimony even by your director of tax, committee substitute 111 is a tax increase and it changes substantially the tax law. Senate Bill 21 or MAPA the More Alaska Production Act is working as intended. It has led to more industry investment and more importantly an increase to oil production for the first time since 2002. This increased investment and production has led to more jobs, more revenues to the state, and has been good for the Alaskan economy especially during these times of economic downturn. Alaska needs to remain globally competitive for critical capital investments and raising taxes on the oil and gas industry at a time when we are all suffering, as your Department of Revenue has shown you, that will not help Alaskans or the industry weather this economic downturn, it's just going to make matters worse. With those opening comments let me delve into the committee substitute. First, let me say for the record that we do support testimony you just heard from Alaska Oil and Gas Association that this is a troubling, troubling bill. Many of the provisions, as you've heard director of tax Mr. Alper testify, are carryovers from House Bill 247. Unfortunately all of them are bad. We are reminded of the testimony by legislative consultants last year, and I invite you to please go look at it, where they said that these provisions that are in the committee substitute will not improve Alaska's overall investment climate. Again, I ask you to ask your consultant that. It will not lead to more production, it will not lead to more jobs, it will not help maintain or grow production, and it will not help the Alaskan economy. It's just going to make matters worse. The raise in the minimum tax. As you've heard testimony, this is nothing but a tax increase. That's all this is. It's nothing to do with credits. Raising taxes when companies are hurting is not wise tax policy. It's a regressive tax increase and it can't help but hurt the industry and it's not going to be good for jobs. Hardening of the minimum tax floor. The committee substitute would also raise taxes under Section 7, as you heard Ms. Moriarty testify to, by preventing companies from realizing the true economics in their investments, by preventing them from taking critical tax credits to offset the minimum tax as is allowed under current law. This would represent and immediate and significant tax increase and would penalize companies who've made prior year investments and who are making current year investments even though they may be losing money, and would deny them the economic recovery that they need at the time they need it the most because we're losing money. In order for Alaska to maximize investment it's critical to provide investors the opportunity to capture the economic benefit of those investments, especially given the inherent downside risks of long-term capital intensive investments that you have in the state. You heard Ms. Moriarty testify to that and your consultant will tell you that - Alaska is one of the most expensive places to do business. That's not your fault, it's not our fault, it's just a fact. You're a long ways from market and you are in a very harsh environment and very environmentally sensitive environment. That all adds to costs; it's costly to bring oil out of the ground here in Alaska and get it to market. But this provision would significantly and negatively impact Alaska's investment climate, make no mistake about that. If you don't believe me, ask your consultant. Ask anybody if you had a tax increase "what do you think that's going to do?" It's amazing how people see that oil companies would act differently than anybody else. You have a small business, maybe you own a restaurant, your costs are increased - are you going to hire more people? Are you going to expand? Are you going to do the opposite? This provision will announce to the world that Alaska is willing to effect the economics of past and essential current investments solely for short-term needs. Section 7 also has this migrating credit provision and you've heard conversations about that. This is nothing but a tax increase. That's all this is. And why is that? Let's examine this in a little more detail. The tax you have in front of you is an annual tax, it's not a monthly tax. We file estimates every month. Estimates. Look it up in the dictionary what an estimate is. It's a guess. That's all it is. We're guessing what our tax will be for the year, on a monthly basis. We are bound by certain restrictions on what we can claim as deductions in any given month and those are based on estimates. What this provision would say is you must file now, basically perfect estimates or you risk losing valuable tax credits. These tax credits that are going to be affected are sliding scale credits and the small producer credits - you can't carry those forward. You use them or you lose them. So what happens, you make your estimate at the end of the year when you file your annual tax return - again this is an annual tax - if you missed your estimate it's going to cost you money, it's going to raise your taxes. This is a significant change in the law. You're migrating to a monthly tax when right now it's an annual tax. But more importantly, how could we file our returns accurate? How can we know each month what our credits are going to be for the year? Because you're supposed to tax the economic activities of a taxpayer on its entire year activity. Not its month, it's yearly activity. These are estimates, no different than a corporation files its monthly or its quarterly estimates for its federal tax return. There's nothing in that law that says - well if you miss that estimate, that's a shame, you're going to get tax increase. I've not seen this provision elsewhere - and again you can ask your consultant that - and I've never heard the concept of filing perfect estimates or you lose. And this only goes one way, the state does not refund money, we would have to pay higher taxes. That would be the policy of the state. A very troubling provision is in a number of the sections as to reducing the ability to recover net operating losses. There's a lot of misinformation I think on this, or misunderstanding. I think Ms. Moriarty did an excellent job of trying to explain. The net operating loss is nothing more than when your expenses exceed your revenues. This isn't anything any company is proud of. People say - oh you're getting a subsidy because the state's allowing you to recover a loss. I'm sorry, from a tax perspective, that I don't understand. Nobody wants to be in a loss. Nobody. Your tax for the most part is a net tax. It's a hybrid, but it is based more on net income than it is a gross tax. What this provision would then do is to say - well if you invest and you go to a loss, thank you for investing in the state, we wanted you to do that, but you suffered. And you say - well how can that be? It's easy to explain this as Mr. Alper did, from a revenue side. You want to raise taxes like he does? Well, that's great. It's an easy provision to describe. Take away half your deductions. There's a big difference between a statutory tax rate and an effective tax rate. There's a lot of talk on that - oh your effective tax rate is much lower? Well, it has to be. This is a net system. Effective tax rate is determined after your deduction of costs, after your subtraction of credits. It has to be lower. You have a high tax rate of 35 percent, as Mr. Alper has testified to you. It's a high tax rate. There's not another state in the country that's even close to 35 percent. Louisiana is 12.25 [percent]. You guys are almost three times as high. Theirs is a gross tax that's true. And yours is not. 2:54:10 PM Mr. Seckers questioned what would happen. He asked members to step back and look at it from a practical perspective. He stated that many of the committee members were business owners. He asked them to consider how it would work. He emphasized that every December or January he would get a call from our senior executives telling him they were thinking about doing an investment in Alaska and wondering if it would put the company in a loss. He would have to respond that he did not know. The executives would then say they would lose half their investment if so. He agreed. He questioned whether committee members would make an investment with that type of uncertainty. He asked what would happen if an investment arose near the end of the year. He reasoned that if the investment put the company at a loss it would lose half of its deduction. He asked how it work in partner situations. He provided a scenario where Partner A wanted to spend on a particular project, Partners B and C wanted to spend as well, but unfortunately one or more of those partners would be driven to a loss. He questioned whether the investment would move forward. He thought it was an interesting dynamic. He underscored that the state would suffer under the scenario. He stated that the investment may not go forward and it would no longer be a timing difference, but a permanent difference. He asked if it was the policy the legislature wanted to have for the state. He asked if the state's policy would now be that deductions would be allowed for companies that spend less, but companies spending more would be penalized. He stated that an investment would lead to royalty, property tax, and income tax and companies would be penalized. He believed the policy appeared to be inconsistent with the policies the legislature had been trying to enact for the past decade or so by encouraging investment by spending more in the state. He underscored that the proposal would send a signal to do the exact opposite. He stressed that every investment would be under greater scrutiny because a company would lose if they experienced a loss. Mr. Seckers referred to the 7 or 8 percent uplift for a period of seven years. He stated the uplift may be sufficient for some small companies (e.g. explorers), but he did not know. He asked the committee to consider companies that would not go seven years. He stated that for a producer that went negative for a few months and became profitable again would see an immediate tax increase. He was unaware of any other regime that employed that method. He believed the legislature's consultant had advised allowing a loss to go forward and that allowing for an uplift was a policy call. He emphasized that the expenses were important and it would create dysfunctional actions on the slope based on the policy provision. He reiterated that the legislature had to ask itself if it was the policy it wanted to instill in the state. He restated that the policy would penalize companies for spending more and would allow deductions for companies spending less. Mr. Seckers provided a scenario where Company A spent $1,000 in a year and was able to write off the cost at its tax rate of 35 percent. Whereas, Company B spent $1,000, had no revenue in the first year and turned profitable in the second year. Under the provision Company B would not receive the ability to write off the $1,000; it could write off $500, which constituted a tax increase. Every tax regime he knew applied the tax at the statutory rate; it was the tax rate applied to net profits. The effective tax rate may be different - it had to be under a net system. Other regimes applied tax at a statutory rate to avoid "this kind of" inconsistency. 2:57:56 PM Mr. Seckers addressed the sliding scale tax credits: This again is a very troubling provision because it went to the core of the tax structure. This doesn't have anything to do with credit reform. I know people like to call it that, but it doesn't. And as Director Alper has testified to, you take these away, you alter them, and the 35 percent is a very high tax rate. I think those were his exact words, and he's right. It is. This is a tax increase on the legacy fields, that's all this is. Another provision is Section 23 of the bill, which talks about the gross revenue at the point of production. This does not get a lot of airplay for some reason. It's a disguised tax increase that's why. Again, it changes the substance of the law. Ask yourself what this would do. Under Alaska's current structure we pay tax not by field, by segment. We pay a tax for the entire North Slope, Cook Inlet oil, Cook Inlet gas, and everything in between - Middle Earth. We file consolidated returns for the entire North Slope. So what does that mean? A company's got income from one field, income from another field, loss from a field - they consolidate to represent the entire economic activities of that entire segment. What this section would do is to say: No, no, we're sorry, it's a shame, we wanted you to invest in the state, but you chose a field that is so far removed from infrastructure that your transportation costs (which are approved by FERC) are so great that it may drive your gross value at the point of production. And guess what? We wanted you to make that investment, it's good for property tax, good for income tax, good for royalties, but we're going to punish you for production tax. Is that the policy of the state? That you're going to encourage investment only near existing facilities. That you want to sit there and say we want you to invest in the state but don't go beyond this region because if you do you're going to get a tax increase. That is a tax increase to companies and could drive investments in a very distinct way. This picks winners and losers; it looks like you're trying to punish a given field or two. You have to ask yourself is that really the policy the state is trying to come up with. Disclosure of taxpayer information, you've heard a lot on this already. I can tell you these are very troubling provisions. This would in effect allow disclosure of some very confidential and taxpayer sensitive information. As Ms. Moriarty's already indicated there could be contracts going to other companies they would be concerned about. As much as we welcome BP and Conoco and others as partners, we're competitors. Bottom line, we're all competitors. We are bound by federal law what we can or cannot reveal. There also may be taxpayer proprietary information that is a benefit over years and years of work that is beneficial to that company. Could be trade secrets, it could be ways of doing things that are cheaper that we have to protect. This language as written would in effect allow almost anything to be published. This would chill investment and cause all kinds of concerns with the industry as well as how it relates to federal law. 3:01:24 PM Mr. Seckers addressed the preapproval requirement: It's hard to address something that is really a statement in statute that says - oh we want this preapproval process. It's hard to address that, it raises a lot of questions. Really, this is a very troubling provision. The only way to really address this is by highlighting the fact that it just raises all kinds of questions. As Ms. Moriarty testified to - does that mean the Department of Natural Resources has to do an audit of our costs line by line before? How long will that take? When will I have to submit it by? Can somebody else look at it? Can a third party intervene? What happens if the Department of Natural Resources says yes Exxon or taxpayer this is a valid expense, if you go to a loss you can claim this. Six years later the Department of Revenue says yeah but we are reinterpreting our reg [regulation] to say no its not. Who wins? I made that investment based on that representation by your agency. I've got another agency saying that they're wrong. Who wins? What's the appeal process? What happens if the Department of Natural Resources denies something? Says you can't spend that. What's my appeal rights? If you look at the fiscal note that was advanced by the Department of Natural Resources in House Resources they said that they would not have their regulations up and running until 2019. This provision takes effect January of next year. What happens for 2018? How can I invest, I don't have a preapproval. The regs don't come out until 2019. Are they going to be retroactive to January 1, 2018? How would I know? What happens if I've made an investment that the Department of Natural Resources in 2019 says for 2018 sorry you shouldn't have done that one. How's that going to work? Where's the investor confidence? What's going to happen to the projects that are in limbo? There are so many questions this raises. I implore you to examine this very closely. I know in theory it sounds fine. You've got the resource owner providing this preapproval, we don't want to waste money. Ask yourself, is this going to be worth the cost to the state, worth the cost to the industry, and worth the risk on investment and jobs. I don't know. This is a very troubling, troubling provision. ExxonMobil believes that this committee substitute as currently proposed will reduce Alaska's global economic competitiveness. It's going to raise taxes on an activity in the state to which the companies are currently struggling. It's going to force companies - all of us - to reexamine long-term, near-term, and future investment decisions and we believe it's inconsistent to what your policy has been and hopes to be to encourage investment in the state. When you enacted the PPT and ACES you did so to raise taxes when prices were rising. As Ms. Moriarty's chart showed you'd be one of the only regimes that's actually trying to raise taxes when prices are going the other way. So the signal to the world would be: come to Alaska, they'll raise your taxes when you're making money and by the way, if you're losing money or struggling, don't worry they'll raise your taxes then too. Is that really the policy you're trying to come up to? As I've mentioned many times, Alaska remains a critical component of ExxonMobil's worldwide investment portfolio and we look to be here a long time. We really want to work to try to make this policy, all these policies work. And while we will continue to pursue investment opportunities, if bills like this are passed and our taxes go up that just reduces what we can spend in the state and all the investment opportunities now get a different look and are diminished. So Mr. Chairman and members of the committee, let me conclude by reiterating something I've also said before. That Alaska needs to maintain a competitive and stable fiscal regime that attracts and encourages critical ongoing future investments, especially in today's lower prices and that's one of the most important things you face. I get it, we all get it, I don't envy your task, you're trying to balance the budget and go forward, and I understand that. But raising taxes on the industry when they're all hurting sends a very chilling signal to the investment world. We believe the evidence is clear that MAPA is working and if left alone, will continue to work, increase investment, and provide more oil in the pipe. So as policy makers you need to decide whether increasing taxes on companies that are struggling today - will that be a wise, long-term fiscal policy that's going to lead to more jobs? Will it lead to more investment? Will it lead to more production? Will it be good for the Alaskan economy? I believe deep down we all know the answer to those and the answer is no. I thank you for the opportunity to be here today and I'm happy to address any questions that you may have. 3:06:28 PM Representative Thompson asked for a copy of Mr. Seckers' remarks. Mr. Seckers replied in the affirmative. Vice-Chair Gara spoke to Mr. Seckers' comment that the state would be raising taxes solely for short-term needs. He countered that he and others wanted to make sure the state was receiving a fair share in order to fund basic services and have a fair share for all parties. He referred to Mr. Seckers' point that the legislature would be increasing taxes when [oil] prices were low. He believed Mr. Seckers was aware that in the coming fiscal year the state would be paying more in tax credits to companies than it would gain back in production taxes. The goal was to change a tax system that in recent years and in the following year would be paying out more than it brought in with production taxes. It was a different system than a country with high taxes that would try and raise taxes, which would not make sense. He asked for comment. Mr. Seckers answered that the questions were valid. He could not address cashable credits; it was a policy call made by the legislature. Exxon had never received cashable credits and hoped to never receive them. He spoke to fair share and believed the department and Ms. Moriarty's slides indicated the state took in more than the industry at every price range. He believed it was concerning to only focus on the production tax. Exxon paid royalties, income tax, and property tax. It was true that in low price environments perhaps the production tax did not pay as much as the state wanted it to, but it also meant the companies were not earning as much as they may like to. He underscored that the companies still paying the other taxes. He stated it had led to jobs, investment, and to royalties. He believed the legislature needed to decide whether it wanted the investments to move forward. He believed the share the state was receiving was pretty fair notwithstanding the lower production tax the companies paid in the lower price environment. 3:09:23 PM Vice-Chair Gara remarked that there were other jurisdictions currently with much higher tax rates than those in Alaska. He observed that Mr. Seckers had claimed that the state had the highest tax rate in the world at 35 percent. He surmised that Mr. Seckers realized that companies did not pay it; that it represented a price sensitive tax rate and 35 percent was the tax rate at $159 per barrel, which the world had never seen. At the $60 per barrel range for new fields the average production tax rate on the North Slope was zero percent and 4 percent for companies paying the minimum tax. He asked for verification that Exxon never paid 35 percent of its profits at prices below $150 per barrel. Mr. Seckers responded that it was necessary to understand the difference between a statutory tax rate and an effective tax rate. He agreed that the statutory tax rate was 35 percent just like it was for federal income tax. Corporations did not pay a 35 percent tax because it was on net; it had to be below the 35 percent. He continued that if the desire was a statutory rate that equaled the effective rate it was necessary to have a gross tax. By design a net tax could not yield what "you're trying to imply." He reiterated that the effective tax would absolutely be lower; however, companies paid the tax. The calculation was based on 35 percent. Mr. Seckers detailed that if a company had $100 of profit, the tax would be $35; it may get reduced by credits, but it was calculated at 35 percent. He was not certain there was a net regime that would pay the statutory rate because of all of the reductions. Part of the reason the system had been put in place was due to Alaska's high 35 percent tax rate. He clarified that he had never testified the rate was the highest in the world. He corrected that he had been speaking solely about the United States. He underscored that the rate was the highest in the U.S. by far. He explained there were other regimes in the world with higher tax rates but their structures were entirely different. For one, those regimes allowed cost recovery, not cost deductions. Some of the jurisdictions specified that if a company spent $100 it was allowed to recover the full $100 before a tax was leveled. Sometimes a system may even provide an uplift on that to provide for the costs incurred to get the oil out of the ground and then the system taxed at a higher rate. It was not the system in Alaska. He cautioned it was important to be careful when comparing the different systems. He agreed the statutory tax rate was 35 percent, which was the rate companies paid tax on. However, the effective tax rate was entirely different. 3:12:15 PM Vice-Chair Gara countered that if the federal tax rate was 35 percent a company obviously received a deduction on that rate. He stated "this is much different." He underscored that the lower the price, the lower the actual tax rate. He continued that for new fields at prices of $80 per barrel it was 7.9 percent on average. He detailed that at $70 per barrel it was 0.3 percent on average and at $60 per barrel it was zero percent on average for new fields. He stressed that there was no 35 percent tax rate; it was price sensitive. He stated that the federal 35 percent tax rate that was really a 35 percent tax rate at all prices and companies deducted from that. He stressed the big difference between the two kinds of tax systems. Mr. Seckers disagreed. He stated that the statutory base tax rate in Alaska was 35 percent. He agreed the effective tax rate after the application of deductions and credits was much lower. He also agreed that the effective tax rate was a function of the sliding scale credits impacting the rate; however, the statutory rate was 35 percent. He detailed that if he had $1,000 profit, his tax would be $350. Credits came beyond that yielding an effective tax rate. He believed Vice-Chair Gara was misspeaking. He continued it was the same with the federal tax return. His tax rate was 35 percent, which was used for federal worldwide taxable income. Yet the effective rate was different after applying deductions and credits. He reiterated that the statutory rate in Alaska was 35 percent. He agreed it was adjusted by credits; however, the rate taxed on net income or production tax value was 35 percent. Co-Chair Foster stated they would have to agree to disagree. Vice-Chair Gara remarked that the credit Mr. Seckers was speaking about was price related and had nothing to do with investment. Mr. Seckers relayed that the company did not get the credit "just because prices are whatever." It was necessary to produce a barrel of oil in order to get the credit. A company would get zero if it did not produce a barrel of oil. He stressed that a company did not merely receive the credit based on price. He explained the credit was based on gross value at the point of production, but it was necessary to produce the oil in order to receive the credit. There were costs the company had to incur in order to get the credit or reduction to its taxes. The whole purpose of the credit was the more a company produced the better off it became, which was good for the state (increased production, income, property, and royalty taxes). 3:15:12 PM Representative Pruitt discussed that Exxon was the largest publicly traded company but there were other larger oil and gas companies. He asked what percentage of oil and gas development worldwide Exxon was responsible for. Mr. Seckers recalled that ExxonMobil produced less than 4 percent of the worldwide oil - it was in that range. Representative Pruitt asked how many different regimes ExxonMobil invested in. Mr. Seckers replied that the company invested in pretty much every country and state. He elaborated that there may be some locations without oil and gas, but Exxon may have retail, a refinery, gas stations, or other in those locations. He detailed that when the company looked at investments, they looked worldwide. He spoke to questions related to decisions to invest in Alaska - he mentioned increased taxes when prices went up or down. Alaska competed in Exxon's world worldwide. Representative Pruitt believed Alaskans were "Alaskacentric." He believed Alaskans lived in the world that existed when the pipeline had been turned on and failed to recognize it was now in a global market. He asked what percentage of the company's assets were deployed in Alaska. 3:18:21 PM Mr. Seckers did not know. He knew the company's investment in Alaska was "big," but the company was also big. The company spent billions annually in Alaska. He noted it was possible to ask the operators about Exxon's share of the total spend in Prudhoe Bay. He thought the Department of Revenue may have the information from the company's corporate tax returns. He explained that one of the corporate tax return items was property in the state versus property worldwide. Representative Ortiz believed that under SB 21 the goal had been to establish a hard [tax] floor. He asked if that was true. Mr. Seckers answered that he did not recall the goal had been that specific, but he did not know for sure. He elaborated that the bill had eliminated sliding scale tax credits. He stated that hardening the floor and raising taxes was a policy call [for the legislature]. He relayed that going for the NOL tax credit to a deduction served that purpose because deductions could not go against the minimum tax - only credits could. He furthered that the NOL would no longer be a credit. Most of the other credits were disappearing anyway; the only one left on the North Slope would be the per barrel credit. He did not know whether it would pierce the floor, but he did not believe so. He explained that some of it was already occurring because credits were expiring; the floor was being hardened "as we speak." He reiterated that going to an NOL deduction would take away the largest credit that remained. Representative Ortiz asked if the industry rejected the idea there should be a minimum tax paid by industry for the extraction of the state's resources and a minimum share the state should have access to. Mr. Seckers answered that it was difficult to answer. He noted that a gross tax is a regressive tax; it was paid whether a company made a profit or not. He provided a scenario of a business losing money but having to pay tax regardless. He stated it was a hard concept, especially with the current system. He noted it was a policy call. For most taxpayers it was difficult to pierce the floor - the credits were necessary. He emphasized that production tax was merely one item paid by companies. He underscored that the state was not giving the resource away; the state may not be getting as much as it liked, but that was a function of price, which oil companies did not control. Companies paid a royalty (a regressive number), income tax on worldwide operations, and property tax. He reiterated that hardening the floor was a policy call. He believed it was necessary to ask what it would do to current taxpayers with zero minimum tax due to small production that had to go to a rate of 4 or 5 percent. He advised it was prudent to think about how the industry would react to the change. He stated the oil industry would not react differently than any other business. 3:23:56 PM Representative Kawasaki referred to the Point Thomson lawsuit settlement in 2010 or 2011. He noted that Point Thomson development began pre-SB 21. He asked if Exxon had new fields in Alaska since the passage of SB 21. Mr. Seckers answered in the negative. The company was looking at all opportunities, but it was currently focusing on its existing assets. The company was always looking at other options. Representative Kawasaki asked for clarification on options. He asked for verification there were no new Exxon investments in pre-development. Mr. Seckers believed Representative Kawasaki was correct, but he would have to double check. He knew the company was actively looking at all kinds of options and opportunities. He could not say what stage they were in - some of the information was proprietary. Alaska was an important piece of the company's portfolio. Representative Wilson asked if Exxon would have to reexamine projects that may be close to a decision if the bill passed as currently written. Mr. Seckers replied that anytime taxes increased in any jurisdiction it became a factor. He countered the notion that Exxon printed money; the company had a finite amount of capital like any other company. He detailed that the company's capital was apportioned based on economic viability, performance, and so forth. Any time taxes went up it reduced the amount of capital and future investments were reconsidered. Tax increases could also lead to lost jobs, lost production, and other. 3:27:01 PM Representative Pruitt believed the question about new fields was the wrong question to ask because only 3.5 years had gone by since the passage of SB 21. He thought the prudent question was about whether there were investments Exxon had made even in current fields that had come about because of SB 21. Mr. Seckers responded that Exxon was always looking at efficiencies and investments in current activities. He stated it was a valid question to ask operators of BP and Kuparuk because they directed it and much of the investments went there. The company was always looking to do more and with the passage of SB 21 many things such as redesign, workovers, and so forth, became more economic. The company believed SB 21 was working and was good for Alaska's economy. He stated that SB 21 had led to more production, investment, and royalty. He believed the committee substitute was a bad idea and would hurt contractors and others associated with the industry. 3:28:48 PM AT EASE 3:51:47 PM RECONVENED Co-Chair Foster recognized Representative Lora Reinbold in the audience. DAMIEN BILBAO, VICE PRESIDENT OF COMMERCIAL VENTURES, BP, provided a PowerPoint presentation titled "BP Testimony: March 22, 2017, HB 111(N), House Finance Committee" (copy on file). He expressed intent to focus his testimony on policy and how Alaska competed for investment. He explained that when the company made internal decisions about where to invest, there was a limited amount of global investment and every project and location competed against each other. Some things could be controlled by the company (e.g. how efficiently a project could be executed and the use of technology in progressing a project) and many things could not be (e.g. a fiscal system and oil price). It was important for the company to holistically think about how the projects and locations stacked up against one another. Mr. Bilbao continued that as BP had engaged in the discussion in support of a fiscal conversation, it had understood that the focus was related to a specific problem having to do with tax credits; however, it was clear the bill was broader than tax credits. The company encouraged a much more targeted solution, which he intended to address throughout his testimony. Mr. Bilbao addressed slide 2 that showed two charts related to investment trends by region (left chart) and production trends by region (right chart). He detailed that the numbers on the slide were indexed (they began at a common starting point and moved relative to each other), not absolute. He explained that when comparing global spend versus U.S. Lower 48 versus Alaska, on an absolute basis the total number of dollars would not even be seen on the same graph. However, if the numbers were indexed to a common starting point, it was possible to see how different locations moved relative to each other under common circumstances on oil price, fiscal systems, and other. He pointed to the left chart and noted the top line was capital investment in U.S. Lower 48 development, the middle light blue line represented global development, and the bottom [gray] line represented Alaska. The chart indicated that in the early 2000s Lower 48 investment had begun to outpace Alaska and global growth investment. He stated it had been pretty remarkable and had begun to signal a renaissance not only in U.S. oil and gas exploration, but in terms of global oil and gas geopolitics. He continued that around 2008/2009 Lower 48 investments spiked relative to global investment and Alaska. Mr. Bilbao focused on more recent years. He pointed out that since 2013 (circled in red on both charts), while oil prices were beginning to move down and Lower 48 investment and global investment had begun to decrease, investment had increased in Alaska. The charts demonstrated how Alaska investment compared to other locations. He directed attention to the right graph, which showed production trends by region. He noted that with investment went production: as Lower 48 investment spiked, production also spiked. The top dark blue line represented Lower 48 production, which was twice its original starting point on an index basis. Global production was shown to be slowly creeping up and [production in] Alaska continued to decline until about 2014 and had flattened out over the last couple of years (circled in red on the chart). He stated that BP credited the passage of SB 21 to the dramatic increase in investment relative to the rest of the world and the Lower 48. He reiterated that while investment in the rest of the world and the Lower 48, it was increasing in Alaska. There was one distinguishing feature, which was the shift in oil policy attracting investment to Alaska. 3:57:35 PM Mr. Bilbao turned to slide 3 titled "Alaska - How do we Stack up?" The slide pertained to a conversation around production in Alaska relative to the rest of the U.S. In the current year Prudhoe Bay and the Trans-Alaska Pipeline System (TAPS) would celebrate its 40th anniversary of production. He observed that the events were pretty remarkable given the timing was well beyond original expectations. He discussed the original discovery of Prudhoe Bay, which initially projected the production of 9 billion barrels; however, over 12 billion barrels had been produced and BP still believed there were billions more to produce, which it was actively working to do. Mr. Bilbao pointed to the graphs on slide 3 that showed production on a relative basis between Alaska and other Lower 48 sources (i.e. onshore, offshore, shale, tight oil, and other). The left graph provided a reference case for the U.S. Energy Information Administration and the right graph showed an aggressive growth case. Under either scenario tight oil production in the Lower 48 had grown from approximately 5 million to somewhere between 10 million and 17 million barrels of oil. The amount of tight oil that could come out of the Lower 48 was humongous. He noted that the resource opportunity in Alaska was world class, but it was necessary to keep in mind that the resource opportunity in the Lower 48 was incredibly robust. The graph provided a sense of how the Department of Energy's EIA characterized the opportunity in the Lower 48 versus Alaska. Mr. Bilbao continued to address slide 3. He communicated that in the mid-1980s Alaska had been producing about 25 percent of total U.S. production. Whereas, at present Alaska produced less than 5 percent of the U.S. production, which was projected to continue to decline. When comparing Alaska with locations in the Lower 48, there were numerous opportunities Alaska was competing against. He explained that a conversation around oil fiscal policy was a discussion around how competitive the state would be for the next dollar of investment. 4:00:31 PM Mr. Bilbao moved to slide 4 titled "Distribution one barrel in Alaska." He had used the 2016 Revenue Sources Book published by the Department of Revenue and had looked at total spend on an aggregate level. The slide reflected the "all in" number, which provided a good indication of a couple of key points. The book showed an average sales price of $43 per barrel in 2016. Under the scenario, Alaska received revenue of about $7 per barrel between royalty and state taxes. The scenario showed that the industry had spent $48 between operating, capital, and transportation costs. If industry was spending $48 to produce a barrel and was paying government take of $7, on average the industry was losing around $12 per barrel during 2016. He underscored it was a high cost environment for doing business and the industry did not fare well in 2016. He elucidated that BP had lost about $1 million per day in 2016. Mr. Bilbao turned to slide 5 titled "Suggested Principles for Alaska Policy" related to HB 111. He shared that BP had testified to the House Resources Committee that any oil fiscal policy should be measured against a set of common principles. The first principle BP looked at to measure any oil fiscal policy in Alaska is whether it would lead to more oil down TAPS. For the first time in over 15 years, oil flow down the pipeline was higher in 2016 than in 2015. In January and February of 2017, oil flow down TAPS was higher than the same time the preceding year. The increase was primarily from the legacy fields. Mr. Bilbao addressed the second principle on slide 5, which related to extending the life of legacy fields. He stated that the legacy fields were the string on which the pearls were strung. The longer the string of Prudhoe Bay and Kuparuk, the more other fields would be added to the pearl necklace. He noted that 90 percent of TAPS production came from legacy fields. Third, BP believed it was important to encourage more independence to look for oil and gas in Alaska. He detailed it was good for the state and the industry's midstream infrastructure. Additionally, it was beneficial for TAPS to see increased oil flow (whether from legacy fields or not) and BP believed any fiscal policy should encourage increased North Slope exploration and more independence. Lastly, it was important to avoid picking winners and losers. He expressed intent to provide examples of where HB 111 fell short. The company believed the bill failed on all four principles. Mr. Bilbao stated that as a broad tax increase at all oil prices, BP did not believe the bill would encourage more oil down TAPS. He furthered that because the bill included a tax increase and would raise costs, BP believed it would shorten the life of legacy fields. Additionally, the company did not believe the bill would lead to increased independence exploring for oil and gas on the North Slope or looking to actively enter fields on the slope. He explained that either because of a production hurdle the bill would implement or how things were meant to be submitted to DNR, the bill may have a bias towards certain players versus others. He stressed it was very important for any tax policy to be agnostic to who the player may be. He continued that the tax policy should set a foundation for the state ending up in a good place and the industry being in a positive place to continue investment. 4:05:56 PM Mr. Bilbao emphasized that the bill was an overextended response to what had initially been a focused concern about cashable tax credits. The company believed there should be a way to address the problem while keeping companies whole on cashable tax credits and continuing to encourage exploration on the North Slope. He stated that HB 111 went well beyond that scope and stepped into areas that had not been problems identified early on with regards to a base (SB 21) system. He elaborated that the current system had led to investment and production that was good for the state and that had been targeted when SB 21 had passed. Mr. Bilbao advanced to slide 6 and provided examples of BP concerns with HB 111, version N. First he addressed Section 14 related to the per barrel credit, which the slide termed as the "new drillsite killer." He explained that the statutory tax rate implemented with SB 21 and the sliding scale per barrel credit were integrated into a joint system and were not independent from one another. He recalled the conversation in the House Finance Committee during debate on SB 21 related to sliding scale. He explained that as the base rate moved up, the sliding credits were put in place to offset the cost and to provide an incentive for production. He emphasized it had been a critical policy shift between ACES and SB 21. He explained that ACES had incentivized spend, while SB 21 incentivized production. The state had wanted more production down TAPS, which had occurred. He underscored that it only worked when the base rate and per barrel credit worked together to provide an appropriate incentive for investment and to provide a competitive policy to attract the next dollar of investment verses other locations. He stated that BP saw Section 14 as hugely detrimental in running economics on large investments in particular. A tax hit or reduction on the per barrel credit would severely dampen the economics and competitiveness of large investments with big spend and big production opportunity. 4:08:36 PM Mr. Bilbao continued to address slide 6 and spoke to Section 26 of the legislation related to the new DNR process, which the slide termed the "investment decelerator." He stated that it was necessary to know how a project would be treated financially if BP was running economics, otherwise it was not possible to run the economics. He elaborated that before he sanctioned a project he needed to know whether items were deductible, which meant he would need to submit up to 100 percent of the investment for review by DNR. He questioned whether companies would be kept whole if regulatory process resulted in project delays and would impact value to companies. The administrative review could be onerous and more fundamentally, challenging around the ability to make an investment decision. He thanked the committee for its time. He encouraged a conversation around a targeted problem statement such as cashable tax credits. He reiterated his belief that companies should be kept whole and continued exploration should be encouraged. He asked the committee to understand that a broader policy change would be viewed by the industry as a fundamental policy shift making Alaska less competitive than other locations around the world. 4:10:23 PM Representative Wilson referred to slide 4. She asked if the on the slide state taxes included local municipality property taxes. Mr. Bilbao answered that the slide was based on data from the  DOR Revenue Sources Book for state taxes. He detailed that when determining economics, BP included everything it was paying regardless of whether it fell in a production tax bucket, state corporate income tax bucket, or other. The information on the slide reflected an "all in" revenue going to the state. He believed the slide came from page 29 of the book. Representative Wilson asked for verification the slide did not include municipalities. She did not believe municipalities were included in the DOR Revenue Sources Book. Mr. Bilbao did not believe so, but he would follow up. Representative Wilson asked for an estimate of federal taxes on the same barrel in order to understand the true loss. Mr. Bilbao believed there was a broad difference in the current year for different industry members. He did not imagine there was a large federal income tax payment if the industry was suffering a loss. He would follow up. 4:12:38 PM SCOTT JEPSEN, VP EXTERNAL AFFAIRS AND TRANSPORTATION, CONOCOPHILLIPS, provided a PowerPoint presentation titled "House Finance Committee CSHB111" dated March 22, 2017 (copy on file). He outlined his intent to speak about benefits SB 21 had brought to Alaska, what it was intended to do, and whether it had met its intent. He also intended to speak about the current competitive environment in the U.S. The testimony would also address specific elements of HB 111. Mr. Jepsen turned to slide 3 titled "FY 2017 Producer Share vs ANS WC - Fall 2016 RSB Assumptions." The chart was derived from the 2016 Fall Revenue Sources Book compiled by DOR; it showed net cash flow split between the state, the federal government, and producers, as a function of oil price for FY 17. The Y axis represented net cash flow in millions of dollars. The state's share consisted of royalty, severance tax, state income tax, and property tax. Also included in the calculation were the per barrel credits, but the cashable or other tax credits had not been included because they were discretionary expenditures the legislature had decided to make to encourage new entrants to the North Slope for further tax purposes. The chart represented strictly the revenue side of the equation. He pointed to the red portion of the bars on the chart, which indicated the state had the largest share at all price points. He referred to 2013 when $80 per barrel had been considered a low oil price. The share to the state was in the higher $40s and the investor share had been around mid- $30s. At around $60 per barrel, the ratio between the state and investors remained close to the same. At lower prices where profits were thin, particularly below $45 per barrel where industry was in the negative, the state's share continued to increase. The chart did not include percentages on the state's share below $45 per barrel was because the share was infinite; any net profit was consumed by the state through existing gross taxes - primarily the minimum severance tax, royalty, and property tax. Mr. Jepsen continued to address the chart on slide 3. He referred to discussion on whether there should be a set amount of money received by the state (a floor). He explained that there was. He detailed it was the gross taxes the state already received. In the case of property tax, it was not price dependent, but value dependent. He communicated that the state already took the lion's share of the revenue - it took far more than the investor. He noted that if the federal and state share were combined, the total was in the mid-$60s, which was a pretty high government take. He referred to earlier discussion by Vice- Chair Gara related to effective versus statutory tax rates. He explained that the chart represented what the government took after operating costs and capital investments. He could not define fair share for the legislature, but it appeared the state was already in a pretty good position, particularly at low oil prices. An increase in taxes would further widen the gap between investor and state share and would make costs increase in Alaska. Mr. Jepsen noted he would address what the competitive environment looked like. He continued that anything increasing the industry's costs in a high-cost environment, would not going to incentivize investment. The per barrel credit had been included because it was an integral component of the tax rate calculation. He explained that the specific credit had been implemented in the House Resources Committee as a way of taking the extreme regressivity out of the tax rate when looking at lower oil prices. He clarified that it was not a credit per se, but it was an integral part of the tax rate calculation. 4:17:41 PM Vice-Chair Gara asked if the slide counted or did not count the tax rate reduction. Mr. Jepsen answered that it was counted. Mr. Jepsen advanced to slide 4 titled "Activities since Tax Reform (SB21) Passed." The slide addressed the number of projects sanctioned since the passage of SB 21 and whether they had occurred due to the passage of SB 21. The slide showed all of the various investments ConocoPhillips and its partners had authorized since the passage of SB 21 in 2013. Shortly after the passage of the bill the company had added two new rigs to the Kuparuk rig fleet, it had sanctioned and taken delivery of two new-build rigs, and in 2016 the company had four to five rigs running between Kuparuk and Alpine. At present the rig count was down to three for a couple of reasons. First, Conoco had worked off much of the backlog in terms of fixing wells needing to be worked over. Additionally, due to the current price environment, the company had high-graded the portfolio in terms of wells that made since to drill at current prices. However, the investment and drilling opportunities the company had identified three years earlier were still there. He stated that hopefully the company would have the ability to revisit the opportunities assuming an investment climate that incentivized investment as well as some uplift in oil price. Mr. Jepsen continued to address slide 4. In 2016 Conoco had sanctioned another new-build rig (an extended reach drilling rig). The rig would significantly change how much the company could develop from a single drill site. Currently the maximum it could reach from a single drill site was approximately 55 square miles; the new rig would extend that to about 120 square miles. The change could represent a paradigm shift as it could reduce the number of drill sites it took to develop a discovery or a new field and would let the company get further out to the edge of the reservoir in places that may be marginal if it were not for the fact that the work could be done without putting in more infrastructure like gravel. Conoco had also authorized additional investment in its viscous oil resource in Kuparuk - the North East West Sak (NEWS) at drill site 1H. He elaborated that when prices had dropped, the project had been paused for about one year and the company had looked hard at what it could do to reduce costs and was currently back to work on the project. Mr. Jepsen continued to speak to slide 4. The company had brought the first new drill site 2S on stream, which was a project of about $450 million and brought in about 8,000 barrels per day. Conoco had sanctioned 18 additional wells at CD5. The CD5 decision had been independent of SB 21, but the company had decided in the past year it would drill an additional 18 wells in the region. The company had sanctioned Greater Moose's Tooth 1 in 2015. He expounded that exploration had been underway in the late 1990s/early 2000s in the specific area of the National Petroleum Reserve - Alaska (NPRA). The company had made discoveries in the area and had completed an EIS in 2004 with the goal to do CD5 and then CD6 and CD7 (Greater Moose's Tooth 1 and 2). However, the process had not gone according to plan - there had been some issues with the regulatory process and CD5 had not come online until several years back. The decision to make the other investments such as Moose's Tooth 1 were independent decisions. He underscored there was nothing in the past that would dictate that Conoco would have to make the decision. When looking at investment decisions the company considered price, the quality of the reservoir, the rate it would earn, the cost to invest capital, and the tax framework. The projects had made sense to Conoco since the passage of SB 21; he believed SB 21 had been a key factor in the decision to move forward - it was not the only factor - but it helped position the investments better in the company's portfolio. Mr. Jepsen explained that at present the company was trying to permit Greater Moose's Tooth 2 (located about eight miles west of Greater Moose's Tooth 1), which would be another $1 billion-plus project and was anticipated to bring in about 25,000 to 30,000 barrels per day at peak production with about 700 positions during construction. The project was estimated to come online about 2021. The company had recently announced another major discovery in NPRA - about eight miles west of Greater Moose's Tooth 2 - called Willow. Willow was a much larger discovery - the company was estimated 300 million-plus barrels of recoverable oil. It was potentially a multibillion dollar investment with production of up to 100,000 barrels per day depending on the development scenario pursued. The company continued to be bullish in Alaska investment. He furthered that in December  the company had picked up about 737,000 acres in federal and state lease sales in NPRA and just east of NPRA on state acreage. The company believed there continued to be exploration potential, which it was pursuing. Mr. Jepsen discussed that since 2013 there had been significant industry investment by other players. North Slope production had grown for the first time in about 14 years by 2 percent in 2016. In 2015 the decline had been slight at about zero percent. He recalled that during the debate on SB 21 people had asked what would happen if the bill passed. People had asked if decline would be offset or production would increase. 4:23:32 PM Mr. Jepsen continued to address slide 4. He explained that at the time no one had been able to answer the questions. He had not known whether the projects would be sanctioned at the time because the bill had been under debate. Since the passage of SB 21, significant work had taken place on the North Slope - substantially more so than what had been taking place before the passage of the bill. Not only had decline been offset, but production growth had begun. He pointed to a chart in the bottom right corner of the slide showing Conoco's capital budget back to 2012. The blue bars represented the percentage of the company's overall capital budget for each year (from 2012 to 2017). He continued that 2012 had been the last full year of ACES; during the ACES regime from 2007 to 2012, the company had spent between $700 million and $800 million per year in Alaska. Since then the company's budget had been higher. Even in the current environment of low oil prices the company was planning on spending about $1 billion in Alaska. He had showed the percentage as a function of the company's overall corporate capital expenditure to show that its budget had varied based on the projects it was pursuing, but it had remained pretty consistent and had grown as a percentage of Conoco's overall corporate budget. Mr. Jepsen relayed that in 2017 the company's corporate budget was about $5 billion and Alaska would receive approximately 20 percent of the total allocation. Part of the reason was related to current projects the company would continue with; the projects had been authorized due to the positive investment climate in Alaska amongst other things. He hoped the trend would continue, but it would depend in part upon whether a significant tax increase was implemented in Alaska. 4:25:21 PM Mr. Jepsen moved to slide 5 and addressed how the bill would impact on competition. A map on the slide showed the unconventional fields in the Lower 48, which were basically the shale fields (oil fields were represented in green and gas fields were represented in red). He pointed to large investments made indicated next to the Bakken, Permian Basin, and Eagle Ford fields on the slide. He elaborated that much of the investment activity had focused on the areas over the last few years. At the present time there had been a decrease in price, less capital available for investment, and companies were allocating capital based on the cost of supply. He detailed that Alaska had to compete against projects that were typically cheaper to develop and operate and with fewer regulatory hurdles. He referred to work in NPRA, which was a very difficult place to work from a regulatory point of view - due to the federal government, not the state. He discussed that Alaska was a high-cost location to invest. The state was opportunity rich, but it was necessary to be able to compete if the company were to continue investing in Alaska. 4:26:59 PM Mr. Jepsen addressed slide 6 titled "Unconventional: Top- Tier Resource Base and Growing." He detailed that information on the slide had been taken from Conoco's November 10, 2016 analyst meeting. The slide addressed the company's resource base within its portfolio as a function of cost of supply. The cost of supply (dollars per barrel) was represented on the Y axis and the resource was shown on the X axis. At $50 per barrel, Conoco had about 15 billion barrels of resource it could develop. He noted the information was pretty representative of what investment opportunities looked like for the industry as a whole. In Alaska, Conoco's cost of supply was at the top end at the $40 to $50 per barrel range. Over the past year Conoco had focused much of its attention on how to decrease its cost of supply on all of its investment opportunities. The cost of supply on CD5 had dropped from $62 to $40. He was concerned that if the base tax rate structure was increased, it would drive costs of supply up and would make companies less competitive, which could result in less investment in Alaska. He explained it would have a negative long-term effect if the company invested less money, resulting in fewer jobs, less production, less royalty, less severance tax, and less revenue to the state. 4:29:01 PM Mr. Jepsen turned to slide 7 and relayed the minimum tax rate increase (from 4 percent to 5 percent) in HB 111 would be a 25 percent tax increase at low oil prices. The company viewed the change to the per barrel credit as a fundamental change to the SB 21 tax structure. He stressed that the state already received the lion's share of the net revenue - the bill would increase the share even higher. He stated the interest change was punitive, primarily because the state largely controlled the time it took to finish some of the audits. He referenced intention to comment on the migrating tax credit change, the tax information disclosure provisions, and the NOL provisions. Mr. Jepsen advanced to slide 8 titled "CSHB111 Represents a Significant Increase in Tax Rate." The chart attempted to show the percentage increase as a function of oil price between CSHB 111 and SB 21. The Y axis represented the percentage increase in tax rate as a function of oil price. The chart was complicated as it tried to take into account changing the minimum tax rate, changes in the timing of the sliding scale, and a different effective use of per barrel credits. The company viewed the CS as a tax increase - at lower prices the bill represented a 25 percent tax increase and when looking at per barrel credits it still represented a fairly significant tax increase at medium prices. The company would be making money, but the consideration was where the changes would put the company at total cost. He stressed that total cost mattered. He spoke about lower total costs in other locations around the world. He returned to slide 5 and explained that the cost of supply for places like Eagle Ford, Bakken, and Permian Basin took into account whatever the royalty rates may be. They took into account the royalty rates and higher severance tax in North Dakota. Mr. Jepsen summarized that total cost mattered. He stressed that it was not whether the state had the highest or lowest severance tax, but about what it cost to produce a barrel in Alaska and how it competed with other places in the world. He underscored that there was not infinite investment money - it was necessary to place investments in the best place a company could achieve the best return. Conoco was hoping Alaska would continue to remain competitive. He posed a question about why the company was doing business in Alaska if it was such a high cost place to conduct business. First, the production characteristics in Alaska were different than the unconventionals, which were typically high rate and steep decline. In Alaska the characterization could be offset with more conventional reservoirs with a lower rate of decline. Conoco still saw the ability to grow production in Alaska; it would invest in locations that fit in their portfolio that made sense in the current price environment, and where it could make a reasonable rate of return under the tax regime. The company still saw places in Alaska where it could explore and potentially grow its base and potentially generate positive net income and cash flow. He cautioned that if the cost of supply curve increased too much those things could change. 4:33:24 PM PAUL RUSCH, VICE PRESIDENT, FINANCE, CONOCOPHILLIPS, addressed slide 9 related to migrating per barrel tax credits. He referenced previous presentations from DOR that showed where taxpayers had migrated the per barrel tax credits from one month to another during the year in 2014. Conoco disagreed with the view. He detailed that the production tax was an annual tax, but monthly estimated installment payments were made to help ensure the state received tax payments throughout the year. At the end of the year (March of the following year) companies made a final tax payment. He specified that in 2014 taxpayers had utilized their full allotment of the annual per barrel tax credits; they had not migrated them from month-to-month, but had used what was allowed by law for the tax year. The change proposed in HB 111 had been identified as a simple change to a perceived problem in the existing tax law; however, it was fundamentally moving the annual tax to a monthly tax. He referred to testimony on some of the difficulties the change would create related to trying to calculate the monthly tax to the precise dollar. The change would increase the complexity and would potentially open the door to other changes in the same direction. He underscored there was no such thing as migrating credits. He stressed the change was really nothing more than a tax increase. 4:36:07 PM Mr. Rusch moved to slide 10 titled "Basis for Interest Change Unsupported." Conoco viewed the interest rate increase was really a punitive interest rate when considering how long the audit process took and how little control the taxpayer had over the entire process. The slide included a chart titled "Production Tax Audit Timeline," which showed the company's audit status from 2006 to 2011. He relayed that 2006 was the only tax year that had fully completed the audit process, which represented the magnitude of time it took to complete the process. He used 2007 as an example and explained the gray portion of the bar represented the tax year. The final tax return for 2007 had been filed in March 2008. The red portion of the bar included the following six years and represented the period of time DOR took to complete the audit. He noted that the department had taken three years to complete the audit for 2006 (three years had been the statute of limitation in 2006, but it was six years beginning in 2007). There was nothing the taxpayer could do to impact the schedule. Following the red portion of the bar there was a small orange section, which represented a 60-day period in which the taxpayer could appeal the results of the audit if desired. The bar included an additional two-year period in yellow, which represented the informal decision process (the first appeal process) - most of which was controlled by the department. A small blue segment of the bar represented a 30-day period for the taxpayer to appeal. Finally, the green portion represented the Office of Administrative Hearings. He summarized that the process had taken nine years for 2007. Interest had been incurred over the entire period unless a limitation was implemented, which is what had been in place previously. Mr. Rusch elaborated that under HB 247 [oil tax credit legislation passed in 2016] the interest rate had effectively doubled from 4 percent to 8 percent. Additionally, the three-year limitation had been implemented at the same time, which Conoco had perceived as an effort to create some incentive to shorten the audit timeframe. He furthered that HB 111 was contemplating maintaining the high interest rate, but doing away with any incentive for DOR to shorten the audit time. He reiterated there was very little the taxpayer could do to impact the slow timeline. The company saw applying a high interest rate in that environment as punitive. 4:40:03 PM Mr. Rusch addressed other concerns on slide 11: · Tax policy should be focused on the aggregate, not individual tax payer information o Disclosure of individual tax return information may violate SEC, anti-trust, or other regulations o Puts recipients at risk of violating federal law o Confidentiality agreements are difficult to enforce -provision provides for broad distribution · Pre-approval of lease expenditures (NOLs) could effectively require advance approval of production, prices, and all expenses o Could create significant bureaucracy o Results in uncertainty / instability regarding tax treatment o No legislative guidance regarding implementation Mr. Rusch elaborated on slide 11. He clarified that in no way was Conoco saying it did not want to provide the data to the state. He detailed that the company provided a significant amount of data to the state already. The question for Conoco, was about who needed to see the data. He furthered that DOR could provide the data on an aggregate basis to the legislature. He addressed the second portion of slide 11 related to the preapproval of lease expenditures. He pointed to a lack in clarity in the drafting of the bill; the pending regulations left a great amount of uncertainty. He explained the bill required a company to know in advance whether it would have an NOL, which the company would not know. One option was that a company would bring all expenses in for approval. Companies would also have to try to make a determination based on assumptions around production and price. He stated it was problematic and would create significant bureaucracy and uncertainty. He referred to references in earlier testimony about mismanagement. He reasoned that it alone would scare companies because it would become very subjective. For example, he questioned who would decide if a delay was mismanagement or due to regulatory issues. He reiterated that the discussion would scare people off if they were making significant investments. 4:44:50 PM Mr. Rusch continued to address slide 11 and NOL changes. He explained that Conoco had not yet incurred any NOLs to date and barring a significant reduction in prices, it did not anticipate being there. He stated that the NOL change was very complicated and added another layer of complexity to the tax, which he questioned the necessity of. He discussed that in most developments there were partners in investments in Alaska, which would create some issues. He provided a summary on slide 12: · CSHB111 represents a significant increase in the base tax structure in an already high cost environment - moves Alaska in the wrong direction · CSHB111 provisions regarding NOLs and individual tax disclosure requirements will create additional barriers to doing business in Alaska · SB21 is working -it has stimulated investment resulting in jobs, production, and increased State revenue -let it continue to work Mr. Jepsen elaborated that oil flowing in TAPS had increased in 2016 for the first time in a long time. He detailed that significant discoveries had been announced by Conoco and several other companies. Additionally, Conoco had sanctioned and completed a number of developments on the North Slope over the last few years. He stressed that increasing taxes would increase the cost of doing business in Alaska, which could result in less investment, fewer jobs, lower production, and ultimately reduce revenue to the state. 4:47:54 PM Co-Chair Seaton stated that one of the things the legislature had tried to do the previous year in HB 247 was limit the state's exposure on credits given. He believed the concept had been melded into the preapproval provision in HB 111. He explained that the previous year the legislature had been looking at allowing credits to accrue if a company was working on a development plan and getting closer to production tax credit. He asked if the method would work better for industry if the state was attempting to limit its exposure for the cost of developing credits. Mr. Jepsen responded that the scenario mentioned by Co- Chair Seaton would not require any divestiture or disclosure of any cost data, price assumptions, or anything else - which would not be as invasive as the provision in HB 111 or as chilling to investment. He continued it was up for the legislature to decide whether it discouraged a company from coming to Alaska to explore, buy leases, or other. He noted that at that point in time the company would not be in a development plan at that time. He questioned whether the company would be in the same competitive position as someone else who might be. A potential downside to the scenario presented by Co-Chair Seaton was - the state wanted new investors, but it was implementing another barrier relative to someone who may already be in Alaska. Co-Chair Seaton asked if the production tax credits were exploration tax credits or were they building up a seismic log that could be sold to someone else never intending to have something go into production. He explained the legislature had been trying to determine a balance in terms of what it was trying to incentivize. He requested written feedback around the issue. He understood concerns about the intrusiveness of an approval process, but the legislature was trying to address what it could afford and what it wanted to incentivize at present. He spoke about credits leading to production versus merely activity. Mr. Jepsen answered that by in large the activities described by Co-Chair Seaton probably did not impact Conoco significantly. He understood that the cashable tax credits were a significant issue for the state at present. He also understood the desire by the legislature to ensure the state received the most bang for its buck. He would follow up at a later time if he had additional thoughts. He thought some later testifiers would have a better idea of what it would mean for their business because they were actually doing that kind of business. Representative Guttenberg spoke to the disclosure of tax returns and concern by the industry. He was always concerned that DOR could not answer a question due to confidentiality. He detailed that numbers were aggregated and the department could not separate them out. The legislature was trying to determine tax policy apart from information from consultants and industry, the information from the department was what the legislature had to go by. He stated that much of the information was public and available in other jurisdictions around the world. He asked if Conoco would be willing to make information the company disclosed in other locations public in Alaska. 4:53:57 PM Mr. Jepsen replied that he was not aware of any location in the world where Conoco's federal tax return was public information. He believed tax policy should be based upon results it provided. He stated it could be changed if the results were not desirable. However, he believed trying to craft tax policy around individual tax returns was bad policy. He stated that it would not be possible to ever get exactly the desired outcome. He thought successful tax policy achieved the average of the goal - some players would do better and others would do worse. He relayed that Conoco provided substantial information to DOR. He continued that the department had tight control of the information. He did not believe he could follow the company's tax return and make decisions based upon the return. He did not believe the information would be beneficial for Conoco or the committee. He opined that DOR was doing a pretty good job conveying to the legislature and the public what the tax policy was doing for the state. If the desired results were not being achieved it was the legislature's purview to change the tax law. Representative Guttenberg believed the confidentiality posed a problem as the previous day Mr. Alper [Director, Tax Division, Department of Revenue] had not been able to respond to two of his questions. He did not know what Conoco's board of directors would do if it had to consider investment policies in places where they did not have information. He knew that when looking at one set of numbers or one audit it would not be possible to understand due to complexity. He did not understand the industry's opposition to providing the legislature with access to information. He noted the information may not be relevant and may not be decipherable. However, he opined that to understand how something was working in some scenarios but not others was a disservice to everyone. Vice-Chair Gara appreciated the company's presence in Alaska and its commitment to projects. He referred to slide 5 titled "Significant Investment Competition." He asked which states the Bakken shale play was located in. Mr. Jepsen answered North Dakota and Montana. Vice-Chair Gara asked if the company was still investing in those locations. Mr. Jepsen answered in the affirmative. Vice-Chair Gara clarified his interest was "not to tax companies into submission so that you're bleeding red." He continued that some individuals wanted a 10 to 15 percent gross tax at all prices, but it would put oil companies under water at $40 to $50 per barrel. He stated that North Dakota had a 10 percent gross tax at all prices - it increased to 11 percent around $80 per barrel. He asked if his representation of the North Dakota tax was fair. Mr. Jepsen believed the existing price point [in North Dakota] moved from 10 to 10.5 percent. Vice-Chair Gara surmised the tax was much higher than Alaska's 4 percent gross minimum tax. Mr. Jepsen answered by returning to slide 6. He stated it was not about what a particular tax was, but what the total government take looked like. In Alaska, a significant share of the net revenue went to the state at any given price point. He explained it was not about whether North Dakota was getting more than in Alaska; it was about the total cost. He understood the dilemma facing the legislature related to what the tax rate should be - whether it was reasonable and met the state's tax and revenue needs. He explained that the cost of supply was already very high and companies were struggling to compete. If the legislature did anything to increase the cost, the company would fall out of the game. He underscored that total cost mattered. Vice-Chair Gara noted that in North Dakota the royalties paid by companies were largely to private landowners - instead of bidding on a lease like in Alaska, companies paid an acreage cost there. He relayed it had been explained to the committee that Alaska was cost-challenged. He noted that one thing that Conoco did that other companies did not do - because of SEC rules, Conoco reported its Alaska and regional profits. He expounded that in Conoco's fourth quarter of 2015 it had made $110 million in adjusted earnings in Alaska, lost $101 million in Canada, lost $219 million in the Lower 48, made less money in all of Europe and North Africa combined, and had lost money in all other international areas. The only areas the company had made more money than in Alaska was in the Asia Pacific and Middle East regions combined. He asked if he should infer from those numbers that Alaska was really a terrible place to do business. 5:01:17 PM Mr. Jepsen answered that unfortunately SEC-type accounting did not necessarily give an adequate picture of where a company was in terms of generating cash flow. There were numerous things that went into SEC accounting that were not representative of "what we would all look at in our checkbook." Ultimately, the company actually had more positive cash flow in the Lower 48 pre-tax than in Alaska. He deferred to his colleague to provide an additional slide in response to Vice-Chair Gara's question. Mr. Rusch informed the committee that the company's annual report was currently available. The slide would address full-year data. He pointed out that due to the company's size it reported its Alaska results separately. The annual report showed specific cost data for Alaska relative to other parts of the world. He stressed that the cost structure in Alaska was significantly higher than elsewhere in the world. He referred to its remote locations and noted that everything was more expensive everywhere in Alaska. For example, an all-in cost for Alaska was about $43 [per barrel] including transportation, tax, development cost, and production cost. Whereas, the total cost was around $20 in the Lower 48. Mr. Rusch addressed a supplemental slide 1 titled "ConocoPhillips Earnings and Estimated Cash Flow ($ Million)." The slide included a table titled "2016 Cash Flow Estimate." The slide used an SEC-type net income based on U.S. GAP [General Accounting Principles] guidelines. For the year Alaska had generated positive adjusted earnings of $233 million and the Lower 48 had a loss of almost $1.9 billion. He underscored the importance of cash flow. The table adjusted for two items including income taxes and depletion and depreciation. The table added income taxes back in to demonstrate that the company was corporately in a loss position. The company was not receiving a refund for the tax benefit. He stated that the data made Lower 48 look even worse because of the receipt of a significant federal tax benefit. After the inclusion of income taxes Alaska pre-tax earnings were $216 million and the Lower 48 showed a loss of almost $3 billion. The large adjustment was depletion and depreciation, which was a way to amortize previous capital and fixed assets over the period of production. He detailed that a units of production was calculated and a depletion and depreciation rate was assigned to each barrel produced. The number for the Lower 48 was significantly higher than the rate for Alaska. There were a number of factors driving the different rates, including the significant capital investment made in the Lower 48 over the preceding four to five years. Much of the investment had been to set up infrastructure (i.e. pipelines and other fixed assets) for future production. Mr. Rusch continued to address the supplemental slide 1. He relayed that the reserve base in the Lower 48 was much smaller relative to the capital size. Units of production were calculated based on the booked proved reserves. He furthered that the Lower 48 developments were fairly new and they were only able to book a small percentage of the production expected out of the wells - additional reserve- adds would be seen over time. When the non-cash item was added back the estimated cash flow before investing was about $1.1 billion for Alaska versus $1.3 billion for the Lower 48. Once the capital expenditures (cap-ex) were factored in the estimated pre-tax cash flow for Alaska was $200 million and $9 million for the Lower 48. He explained that the results were not stellar. He specified that the company had $12 billion to $13 billion invested in Alaska. When looking at the companies Lower 48 business only about 40 percent of its production was oil - the remainder was natural gas liquids and gas. He noted that the gas price in the Lower 48 had been approximately $13. He referred to the future investments Conoco was making in the Lower 48 and explained that it was investing in oil, not gas. He shared that the company had recently announced it was disposing or marketing a significant portion of its gas assets in the Lower 48. The slide represented a combination of oil and gas; however, future investments were veering towards oil, which would be much more profitable. 5:10:25 PM Co-Chair Seaton wondered if there was an effect of being able to write off 100 percent of cap-ex in the year it accrued versus having to do a depreciation schedule. He asked if it showed up in the slide. Mr. Rusch responded that the information presented in the table [supplemental slide 1] was purely on a financial basis. There was no accelerated depreciation or anything else. He clarified that all of the fixed assets were amortized on units of production; it was very different than what was witnessed in tax depreciation or other depreciation purposes. Co-Chair Foster recognized Senator Peter Micciche in the audience. 5:11:49 PM Vice-Chair Gara emphasized that the gross tax rate in Montana of 10 percent was 250 percent higher than the tax in Alaska. He reiterated his earlier statement about losses Conoco had experienced outside of Alaska in 2015. He stated that in almost every year going back to 2010 Alaska was either the most profitable or the location where the company had lost the least or close to the least amount of money. He was glad to know the company was profitable and was doing better in Alaska than in most other places. However, he believed it indicated Alaska was a decent place to invest. He added that even under ACES Alaska ranked first of second for Conoco; the Middle East and Europe were the places where it tended to do better. Mr. Jepsen reiterated that the items shown on the slide were not cash results, reflections of where the company was investing its money, or of the lower cost of supply opportunities the company could invest in. The company had about 7 billion barrels of resource to invest in below $35 per barrel cost of supply, which was where Conoco was currently putting its money. The company had historical investments that were putting it in the negative net income category due to the drop in oil price. He underscored that the data did not represent cash flow numbers. He explained that Wall Street liked to evaluate companies on net income because it tended to smooth out investments over time rather than presenting a "saw tooth" profile. Many investors believed the net income method should be done away with and only cash flow should be used because it was what determined what a company was actually earning. The company was not putting its money in gas fields or in places that would continue to drive its earnings negative; it would put the investment in different places. He continued that Conoco had invested quite a bit in some of the unconventional basins and it would not begin to drill more wells. He concluded that it was not possible to take from the numbers presented on the slide that Alaska had a big advantage over the places Conoco was looking at investing at present. 5:15:07 PM Representative Kawasaki asked about the key metrics included in the calculation of production cost per barrel. Mr. Rusch responded that the number was all inclusive and represented production tax, taxes on net income, transportation, and the development cost where Conoco had taken its capital on a per barrel basis. The goal on the slide was to show all spend in the current year divided by barrels. Representative Kawasaki asked for verification that the calculation included capital expenses for the year, which had been high in 2016. Mr. Rusch responded that when he had referenced a $43 [per barrel cost for Alaska] it reflected an all-in number. He referenced the $16.12 cost per barrel for Alaska versus the $11.06 cost per barrel in the Lower 48 [at the bottom of the supplemental slide 1] and explained that it was purely a production cost number (primarily lifting costs and other related expenses). Representative Kawasaki asked for clarification that the number did or did not include capital and transportation costs. Mr. Rusch responded that it did not include those items. 5:17:09 PM Representative Kawasaki referred to slide 6 of the presentation. He asked about the definition of the cost in supply. He wondered if the cost of supply included capital expenses paid in the year, transportation costs, and lifting costs. MR. Jepsen answered that the cost of supply was the breakeven price required to get a 10 percent rate of return on an after tax basis. It included all elements - severance tax, royalty, and transportation; it was an all-in metric. Representative Kawasaki asked if capital was also included. Mr. Jepsen responded that capital was included. Representative Pruitt returned to the discussion about required information the legislature was asking companies to provide. He quoted from slide 11 of the presentation that disclosure of individual "tax return information may violate SEC, anti-trust, or other regulations." He provided a scenario where state law potentially conflicted with federal law and asked which Conoco would chose. Mr. Jepsen replied that he hoped there would not be a situation where the scenario would occur - presumably the legislature would ensure its regulations aligned with federal law. He relayed that generally federal law superseded state law. Representative Pruitt asked whether the state would open itself up to litigation from Conoco's investors if it tried to force the company to provide certain information that could violate federal law. Mr. Jepsen replied that he was not an attorney and could not definitively answer the question. The company was not planning on being in an NOL situation; therefore, it would not be planning on coming to the state with the information. From a generic standpoint he believed it was very problematic and the issue raised by Representative Pruitt was legitimate. 5:20:21 PM Co-Chair Seaton asked to return to the previous slide [supplemental slide 1]. He referred to a realized oil price in Alaska of $41.93 and production cost in Alaska of $16.12. He stated it turned out to be $26.00. The realized oil price in the Lower 48 was $37.49 with a production cost of $11.06, which equaled $26.50. He asked for verification that the Company's margin in Alaska compared to the Lower 48 was essentially equal. Mr. Rusch clarified that the $41.93 and $16.12 figures did not include transportation. It was necessary to also factor in transportation costs of approximately $10 per barrel for Alaska; transportation cost for the Lower 48 barrel was minimal. Co-Chair Seaton asked if the presenters had any other slides that showed Alaska costs or production volumes that would give a more definitive picture of what Alaska looked like from Conoco's perspective. Mr. Jepsen responded that they did not have any additional information on hand. He noted that the annual report had been published and was the source for the information shown on the slides. Co-Chair Seaton asked for verification that the price and cost information were from the annual report. Mr. Jepsen answered in the affirmative. He added that the figures did not include capital or transportation on production costs. Given that much of the company's production in the Lower 48 represented low margin investments (i.e. natural gas), the company wanted to invest in other locations where margins were higher. Co-Chair Seaton remarked that his calculations still showed about the same margins [between Alaska and the Lower 48]. He stated that a look had been taken at the fields with gross value reduction (GVR), which had an entirely different margin, cost expenditure, and yield to the state. One of the problems may be with melding GVR field costs with non-GVR fields. He asked if it would be problematic to have costs associated with GVR fields only offsetting costs or profits from GVR fields. He wondered if it would be problematic to ring fence the two things separately since there was such a large differential with 20 percent GVR in the fields. Mr. Jepsen responded that anytime ring fencing was applied it created problems including different classes of assets. Additionally, it made it more difficult to evaluate how to invest as a function of a company's overall portfolio. He stated that ring fencing had been talked about a number of times related to heavy oil and GVRs. Philosophically he believed it would put the state in a bad place - it did not necessarily incentivize the right behavior as it was important to have people investing in the best projects. He believed the current system (without ring fencing) lead to a more reasonable development scenario where companies invested in the best projects and the best outcome from investments. 5:24:59 PM Vice-Chair Gara referred to the realized oil price at the bottom of the supplemental slide 1. He wondered if it represented the average Alaska oil price in 2016. Mr. Rusch responded in the affirmative. Vice-Chair Gara continued to address the slide referred to the $233 million in profit for the company in Alaska. He noted that in general terms for oil companies $233 million was not a substantial profit. He asked if the company's breakeven price in Alaska was at oil prices in the $30s per barrel or lower. Mr. Jepsen could not comment on what the Alaska breakeven price may be; it was not publicly disclosed information. Vice-Chair Gara surmised the breakeven was somewhere below $41.93. Co-Chair Seaton interjected that the questions were not answerable. 5:26:37 PM AT EASE 5:27:36 PM RECONVENED BENJAMIN JOHNSON, PRESIDENT, BLUECREST ENERGY II, LP (via teleconference), provided a PowerPoint presentation titled "House Finance Committee - CS for HB111, J. Benjamin Johnson Testimony" dated March 22, 2017 (copy on file). He read from a prepared statement: Good afternoon Co-Chairs Foster and Seaton, and members of the Committee. For the record, my name is J. Benjamin Johnson. I am the president and CEO of BlueCrest Energy Inc. Thank you for the opportunity to speak concerning this very important matter. Mr. Johnson commented that he was the first of the smaller producers and also the only producer testifying from the Cook Inlet. He continued to address prepared remarks: First, I want to echo what we've heard today from Kara Moriarty and other members of the industry. In particular, I want to emphasize the importance to Alaskans of fostering an environment that helps get Alaska's vast resources developed and brings value to its residents. Just last year we heard many voices claiming that Alaska's oil industry was dying. The conventional wisdom said that it was time to "move on" beyond oil. But now we know that was wrong! In fact, the positive changes to the state's tax system over past years has attracted the capital and new companies so that the natural decline of TAPS has been stemmed - at least for now - and the state has laid the foundation for decades of continued production. And of course, we've all heard about three gargantuan oil finds that have been announced on the North Slope. But that's just what has been announced! Who knows what else may be coming as result of more exploration!? These huge new fields will take time and a lot of money to reach production. But if these new finds can be developed, they are poised to usher in a new era of productivity and long term wealth for Alaska. 5:31:00 PM Mr. Johnson moved to slide 2 and 3 and continued prepared remarks: In the Cook Inlet, we have also seen a re-birth of old fields, doubling the total Cook Inlet production of oil and ending the gas supply crisis. Right now, BlueCrest is developing a substantial new field in the Cook Inlet. The Cosmopolitan Unit is poised to become the largest oil producing field in the Cook Inlet and has the potential to provide enough natural gas to supply the Southcentral utilities for many years to come. Because of the location, Cook Inlet fields can be developed much more quickly than those on the Slope. Yes, the size is smaller than some of the largest North Slope fields, but so are the costs and time to bring online. For example, we built and turned on our initial onshore production facility in Anchor Point in a little more than a year. 5:32:16 PM Mr. Johnson advanced to slide 4 and provided prepared remarks: And now, we have completed and started-up the most powerful Extended Reach Drilling rig in Alaska, specifically designed for this project. A couple of weeks ago, we successfully finished drilling the longest-reach well ever in the Cook Inlet, resulting in thousands of feet of net pay for new oil production. And yesterday, we began drilling the next well that will include two long horizontal production zones. We have the potential to drill up to 20 of these large new wells, likely more than doubling or even tripling the current Cook Inlet oil production. While we are drilling, we create between 200 and 300 jobs, and they are almost all filled by Alaskans. We know the oil is there; it's just a matter of spending the money to implement the technology to get it out. 5:33:13 PM Mr. Johnson moved to slide 5 and read prepared remarks: Now let me tell you a little bit about BlueCrest's story. Most of you know that, although our corporate headquarters are in Texas, I am from Alaska. My parents lived in Anchor Point and Homer in the '40's and '50's before I was even born, and I grew up in Kenai. I worked my way through college on the Cook Inlet Platforms and then for ARCO as an engineer on some of the early Prudhoe and Kuparuk projects. I later earned my master's degree from UAA with my thesis written on "What to do with the North Slope gas?" When BlueCrest's current managers initially formed BlueCrest about 7 years ago, I personally hoped we'd be able to come back to Alaska and bring new value to this land. But, in our role as managers of assets for global private investors, we have to do our best to ensure that their investments receive the highest returns possible. 5:34:19 PM Mr. Johnson discussed slide 6 and read from prepared remarks: We've heard this theme earlier today - and I can personally testify that it's a fact. The oil business is largely a matter of competition for investment dollars. Large oil and gas investors look all over the world, and the investment money will naturally go wherever they believe it can generate the highest return. Our investors have the opportunity to invest their money in many locations around the world, and we have to offer a better deal to get them to invest in Alaska. Long before we made the decision to come here, the BlueCrest management team looked all over the US for investment opportunities that would allow us to find and develop new oil and gas. We certainly expected that Alaska had the resources in the ground, but Alaska's costs and administrative processes simply made it non-competitive with fields in the Permian, Gulf Coast, or North Dakota basins. Investments in Alaska are daunting: it costs roughly three to five times as much to drill a well or build production facilities in Alaska as it does anywhere else in the U.S. 5:35:32 PM Mr. Johnson moved to slide 7 and continued to read from prepared remarks: We weren't even considering investing in Alaska until 2009 when we met some representatives from the State of Alaska who had a booth at the North American Petroleum Exposition. They were enthusiastically urging new companies to come north to develop the state's resources. State officials handed out a book ironically called "Dispelling the Alaska Fear Factor" and provided information sheets describing the incentives the state was providing for new explorers and developers to come to Alaska. The state was remarkably offering to rebate a portion of upfront investments made by oil companies in order to help make the Alaska investments more competitive with investments in the Lower 48, and the state has offered a consistent schedule up until last year for reviewing and paying those credits on time. The tax credits were meant to tip the balance in favor of Alaska. The bottom line is that BlueCrest chose to invest hundreds of millions of dollars in Alaska (instead of investing elsewhere) because the incentives offered by the State were believed to be enough to offset the cost differences between Alaska and the Lower-48. Let me be very clear. We would not be here - and we would not be developing Cosmopolitan that can provide hundreds of millions of dollars to the State over time - but for our initial belief in the good faith of the State of Alaska to follow through on its promises to us. When we first looked at developing the Cosmopolitan project a few years ago, we very carefully made sure that we would have the investment funds necessary to get us to completion. We believed that the State would follow through with its highly-promoted tax credit program that actually paid cash rebates to small companies for their investments in the state. Granted, that was a one-of-a-kind opportunity. But nevertheless, it was what the State clearly announced it would do. So before we ever started, we made sure that we would have enough investment money available to get us to the point where we could finally be cash-flow-positive and begin paying back the investors. And, of course, as committed to us by the state's representatives, that plan was based on the belief that a portion of the total investments would be covered by the state tax credits. 5:37:57 PM Mr. Johnson moved to slide 8 and continued to read from prepared remarks: And we did it. As of today, we have successfully proved up the large oil and gas resources in the Cosmopolitan Unit. We have completed a large new production facility (on-time and under-budget), and we have built and started-up the most powerful drilling rig in the state. We have just finished drilling a record-length well that could be the first of many future wells with decades of production. And that new production will likely generate more than $750 million dollars in royalties alone for the state. 5:38:33 PM Mr. Johnson moved to slide 9 and 10 and continued to read from prepared remarks: To date, BlueCrest has invested over $300 million, and we have received about $26 million in tax credits. And every penny of those credits has been re-invested in the field development. But here's the rub. BlueCrest has done its part and invested everything we said we would, but the State has failed to live up to its original commitments to pay the tax credits that have been earned to date. We fulfilled our commitments to invest hundreds of millions of dollars in hard cash for development of the Cosmopolitan resources. But the State has so far failed to pay its share of the tax credits, and that has left a large hole in our plans for funding the continuation of the field development. 5:39:29 PM Mr. Johnson moved to slide 11 and continued to read from prepared remarks: But if the remaining tax credits are not paid, the results to the state are tangible: Without receipt of the rest of the tax credits as originally promised, we could be forced to slow or stop drilling the new oil wells that would unquestionably provide large returns to the state, resulting in a loss of hundreds of jobs for Alaskans. Surely it goes without saying, but if the wells aren't drilled, Alaskans get nothing. Alaska's residents lose jobs. Alaska vendors lose business opportunities. And the state and local governments lose revenue. A competitive production tax system with incentives for new development is absolutely not a give-a-way. As a major land-owner, Alaska benefits from every barrel that is produced on its lands, and I contend that you should be looking at this as an investment opportunity. Alaska stands to generate tremendous future revenues from a dynamic and successful oil industry. The more you can do to stimulate new development and enhanced production from existing fields, the more Alaska's residents will benefit. Remember, the state gets zero value if that oil is never found or stays in the ground. 5:40:41 PM Mr. Johnson moved to slide 12 and continued to read from prepared remarks: HB111 is a great example of a terribly misguided and shortsighted attack on the goose that lays Alaska's golden eggs. Do you really think you can dramatically alter the tax structure for short term gain or create incredible administrative burdens and still get the same production value in the future? I've been involved in the US oil industry for over 40 years now. I've engineered and managed oil and gas developments all over the country, and I can tell you that passing HB111 will deprive Alaska of future developments and will result in less future state revenues and fewer Alaskan jobs. In the interest of time, I will only address a couple of the specifics in the bill, but I do agree with the testimony of AOGA and the other companies we've heard today. I've got to tell you that the pre-approval provision in section 26 has got to be the most egregious waste of government and industry resources I've ever seen in my career. First of all, it's not even possible to conduct oilfield operations if we have to stop and wait for every expenditure to be approved in advance. We can't even always do that internally, because we deal in a business that is fraught with uncertainties, and we often have to react quickly. We have to authorize our line-level managers to make many spending decisions on the spot, and there would absolutely be no time for an external review. When we encounter something while drilling or operating wells and facilities, we have to handle it immediately. Secondly, no matter how you look at it, any money spent by industry costs industry far more than any tax deduction or credit. So no prudent oil company wants to spend one more dollar than is necessary. And keep in mind that under the current existing process, every expenditure is actually reviewed by the DOR after the fact. No deductions or credits are allowed if they are not in compliance with current regulations. So this proposed pre-approval process would provide zero added value to the State, it would require a huge increase in State staff, and it would delay projects. It is a lose-lose proposition. 5:43:28 PM Mr. Johnson moved to slide 13 and 14 and continued to read from prepared remarks: Paramount to BlueCrest and other smaller companies in the state is payment of the tax credits that have already been earned and are now owed. We now understand that you may decide to change or even eliminate the tax credit incentives going forward - but please at least honor the state's commitments for the amounts that have already been earned. So to wrap up, I'd like to re-emphasize the future potential wealth this state can have if the competitive economic environment is done right. Alaska is a land of tremendous undeveloped potential. I urge you to encourage growth to realize the state's true potential. Let's all work together to wisely develop and grow Alaska's long term value. 5:44:37 PM Vice-Chair Gara appreciated Mr. Johnson's presentation. He understood Mr. Johnson knew about the state's $3 billion deficit, that there was no tax on oil in Cook Inlet, and that the state owed close to $1 billion in tax credits. He asked him what the state should do in terms of paying the tax credits. Mr. Johnson offered that the state should do something to pay the tax credits even if only a portion was paid. He stated it was not so important that the company receive everything it was owed immediately, but whatever it could get was better than nothing. Additionally, he noted that Alaska had money in savings; however, he recommended against spending the money if it would be lost and gone. He advised it was a very careful decision to make in terms of how to invest. He continued that the state was investing in the future through its tax program. He believed it was key to ensure the future was positive. Representative Wilson wondered if certain projects were halted if tax credits were not paid. Mr. Johnson responded that BlueCrest had enough money from its investors to finish the first well and almost finish the second well. He detailed that if the company had all of the credits it was owed by the end of the current year - roughly another $100 million - it would have the ability to continue drilling. He elaborated that there were 20 wells the company could drill - it could be drilling wells for years. However, if BlueCrest did not receive any payment for its credits the board would likely have to borrow more money to enable completion of the second well. After that point, the board had not approved continued drilling. He explained it would be necessary to determine alternative ways to finance the future. He concluded that the oil was there and the company had a great team; he would hate to have to shut down operations. Representative Wilson asked if Mr. Johnson meant that the company would be forced to lay people off or to stop advancing construction. Mr. Johnson clarified that BlueCrest was not talking about laying off its production people, but it may need to temporarily shut down the drilling program at some point in the future. He specified that if drilling was shut down, the individuals currently working in that area would not have a job for a while. Co-Chair Foster thanked Mr. Johnson for his presentation. He indicated that the committee would take a 10 minute break. 5:49:22 PM AT EASE 6:04:26 PM RECONVENED PAT GALVIN, CHIEF COMMERCIAL OFFICER and GENERAL COUNSEL, GREAT BEAR PETROLEUM, noted that he was the first North Slope exploration company to testify on the bill and to provide perspective on the playing field and the balance of tax impacts on incumbents versus new companies. He provided a PowerPoint presentation titled "House Finance HB 111" dated March 22, 2017 (copy on file). He intended to distinguish between companies with current production that were able to offset their expenditures against their revenue versus new companies without revenue that were incurring losses until production began. He addressed slide 2 and relayed that the bill did not work for new companies. He detailed it abandoned the long standing state interest of encouraging new companies to invest in the North Slope. The bill reduced the incentive for investment and tilted the playing field and disproportionately treated the new companies poorly in relation to the same investment that may be made by an incumbent company. The bill also treated new companies very differently and negatively in relation to incumbents. Mr. Galvin began by addressing the investment aspect. He intended to speak to how investment made by an incumbent was treated under the current tax system and how it was treated for a new company. He addressed a situation where an incumbent made a discovery and had to invest $1 billion to make the new project work (slide 3). Following investment, the company could immediately deduct the expenditure from its revenue. The deduction meant the company would save $350 million on its tax bill (35 percent). He clarified that the 35 percent was not the company's effective tax rate. He detailed that because SB 21 was different than its predecessor, the impact of investment was different. He specified that because the per barrel credit came after the tax calculation, the amount of investment an incumbent made received a 35 percent reduction in its tax bill. Mr. Galvin spoke to slide 4 and explained that under the status quo a new company that made a $1 billion investment in a project would generate a $1 billion loss. The 35 percent NOL credit was intended to provide the company with an equivalent economic value to the savings the incumbent received. Under the status quo, they did not receive the same economic value because the new entrant was not able to immediately recover a savings. The company generated a tax credit certificate and received $35 million per year in payments from the state (under current law) until production began. If the company decided to take a significant reduction in the value of its certificate, it could receive a total of $61 million. Once the company began production it would begin to use the certificates against its tax bill. He explained that the new company's cost of capital was fairly significant and it was a risky business to be in. He furthered that people expected to receive a decent return on their investment and the company was missing out on its ability to use $350 million for years to come. He noted that the amount also be diminished in value significantly - in five years' time the value may be worth only 60 percent of its original amount. 6:10:51 PM Mr. Galvin turned to slide 5 and explained that under the current version of HB 111 the new company was only able to take half of the investment as a loss. He detailed that in the example he had provided the $1 billion investment became a $500 million carry forward loss. When a company eventually had production, revenue was deducted from its eventual tax obligation and would end up with a combined aggregate of $175 million value. With the uplift currently in the bill, the $175 million value was preserved to some extent. Under the proposed bill, an incumbent making an investment would immediately receive a $350 million value, while a new company making the same investment would get a $175 million value. Mr. Galvin moved to slides 6 and 7 and addressed a scenario where an incumbent and new company are 50/50 partners on a $2 billion project, with each investing $1 billion. The incumbent company had to spend $650 million for its half, whereas the new company had to spend $825 million for its half. He observed that clearly the scenario was unfair. He continued that the new company would feel disadvantaged in the system. He remarked that the message would be that the state would prefer incumbents spend on projects rather than new companies. Second, the commercial reality was that the disparate economic value for partners was a problem because the partners would not reach an agreement on how to proceed. The partners would be fighting and negotiating on how to deal with the disparate treatment. He concluded it would either slow down or doom projects that may otherwise go forward if companies were being treated equally. Mr. Galvin sited a third observation about the partnership scenario. There would most likely be arbitrage between the incumbent versus the new company related to the project's value. He explained that under the situation a company would see the scenario as an advantage and would offer to buy out the other company. The incumbents would be economically incentivized to buy out their partner because they could make an immediate uplift in value by buying out the partner for a designated amount. He explained that the incumbent would receive an immediate write off. He had heard concern from a number of legislators and others that the NOLs were unaffordable for the state - the companies would not be paying taxes for years after the project went into production. He agreed that it may be true depending on the economics of the project, but eventually once the company was able to recover its cost, it would begin to pay taxes on profits. He explained if the incumbent was incentivized to buy out the new company, it would receive an immediate tax break and the state would see the immediate reduction in tax receipts. He reiterated the reasons the impact was detrimental to the state in many ways. 6:16:31 PM Mr. Galvin spoke to the changes provided in HB 111 regarding the small producer credit (slide 9). He noted there had been significant talk about hardening the [tax] floor], but one of the things that had not been discussed was the substantial change it made in the way the state addressed small producers trying to get up to speed on production. He explained that the state had set in place an opportunity for companies who qualified as a small producer to receive a non-transferrable credit that did not carry forward and was only available to reduce taxes in a single year. He continued that it provided a cushion for companies operating on the margin to bring on new production. He explained that in the aggregate it did not have a big impact on the state's bottom line; it was also winding down. The ability to become eligible for the small producer credit had expired the previous year. The credit had a 10- year life and most of those qualifying had become eligible early in the 10-year period and were currently near the end of their eligibility period. He expounded that many companies had invested and become producers with the expectation the credit would be available to them as they go forward. He underscored that the elimination of the ability for a company to use the credit against the minimum tax meant essentially eliminating the value of the credit. He noted that swamping the economics for many small companies was not in the state's interest. 6:18:42 PM Mr. Gavin scrolled to slide 10. He remarked that a couple of bill sections dealt with preapproval of expenditures by DNR. He pointed out that the provisions only applied to those costs that were expected to become NOLs, meaning that only new companies would get "this kind of scrutiny" of their investment decisions. He added there was no information on what that scrutiny would be. He explained that the provisions did not come across as treating companies on an equal basis. Similarly, transparency sections in the bill only dealt with NOL credits. He stated that as effective in the particular bill it was "really kind of a nothing" because it only applied to credits going away at the same time the transparency would become effective. However, if the provision was moved over to follow the NOL carry forward it would mean transparency would be required only for new companies. He observed there was not much conversation about the credits taken against production taxes, but there was much conversation about credits paid out in cash payments. He stated it was strictly a function of the way the budget worked; therefore, the public focused on the cash credit payments as the problem. He reasoned that if the state ended up with a transparency that only exposed new companies, it was what the public policy would tinker around with, which was unfair and was not in the state's long-term interest. He encouraged treating new companies equivalent to incumbents and encouraging new companies to invest in Alaska. 6:22:40 PM Mr. Gavin spoke to what he understood to be the original intent of the bill. He believed the intent had been to deal with the cash credits particularly with the potential for new development projects coming down the line. He addressed slide 12 titled "End Cash Repurchase - Pay Outstanding Certificates: A Bill Explorers and New Producers Could Support." He believed there seemed to be a potential opportunity for a workable bill: a bill that would eliminate NOL credits and associated cash payments. He noted the dry hole scenario had caused confusion, but he believed it made sense. He detailed the idea was if a company came into the state, drilled a couple of wells, was unsuccessful, and exited the state, it should have the same economic value of its investment as if it was eventually achieving some production. He believed there should be some equivalence to the company's investment value versus what an incumbent or a new company going to production would be. He believed that as originally proposed the new company would have to drill its wells and if it was unsuccessful it would be responsible for paying vendors and giving up leases and then it would be treated fairly along with other companies by receiving a check for its risk. He remarked that no one would testify the current provision was good for them because none of them planned to be leaving the state. He underscored that from the state's perspective it made sense to try to attract new companies. Mr. Gavin reasoned that if the credits and cash payments associated with NOLs were eliminated, it would end the "cash bleed" the state was concerned about. There would no longer be an issue of the state having to pay cash payments as companies moved towards development of new projects and the loss of value from the status quo would be relatively small given that current tax credits were not paid out very quickly; the investment from small companies would not be slowed down, there would be an equivalence. He continued to address a bill explorers and new producers could support (slide 12): · Allow 100 percent carry-forward, and annual uplift, for net operating losses o Treats New Companies in a manner equivalent to Incumbents · Commit to repay all outstanding cashable tax credit certificates within two years o End the current repayment uncertainty that is threatening the survival of many new companies to Alaska · Eliminate remaining HB111(RES) sections Mr. Gavin elaborated on the items listed on slide 12. Allowing 100 percent carry forward to maintain equivalence with incumbents. The annual uplift was not a giveaway, but simply captured the value of the current expenditure until it was actually realized. He explained that the expenditure needed to grow over time in order to recognize the value of a deduction was worth much less at present than it would be in five years. He specified that explorers and new producers had creditors expecting repayment and the companies did not have the ability to repay them until the state did. The items listed on slide 12 would save the state cash payments and would keep explorers and new producers on level footing with incumbents. 6:27:02 PM Mr. Gavin concluded that the bill was flawed and needed amending. Great Bear wanted to see that if the state eliminated the cash payment obligations going forward that it was tied to a recognition it needed to pay back the credits that were past due. He believed it needed to be laid out more clearly than "nebulous language" in the current bill about being associated with a fiscal plan. He remarked that no one knew what that language actually meant. Vice-Chair Gara expressed confusion about the uplift and noted that the state was not inflation proofing anything including schools. He discussed that under the uplift provision the state paid a credit and 8 percent interest on top of that. He wondered about a 2 percent interest as something closer to the inflation rate and the "real growth" of money. Mr. Gavin clarified that it was not a credit. He detailed that a loss was carried forward to eventually be deducted against future revenue. He explained that current incumbents received an immediate 35 percent deduction in the same year. The intent was to make the value to a new company somewhat equivalent. The loss was allowed to be carried forward and if a company had a 35 percent deduction the following year given that its money cost significantly more than the interest rate presented - the net present value of the deduction would be reduced because of the company's general cost of capital. The uplift was intended to mitigate the issue - to recognize that a 35 percent deduction was worth less in the future than it would be if taken at present. He elucidated that it was not inflation - it was about the value of money to the company. Vice-Chair Gara knew that Great Bear had been around for some time and he recalled six or seven years earlier when the company had announced there may be a big shale play on the North Slope. He asked about progress made on the exploration. He disagreed with the idea that the state should make things equal by increasing a new entrant's deduction to make it as overly generous as the incumbent's deduction. He did not believe a company paying a 10 percent profits tax should receive a 35 percent deduction. Mr. Gavin responded to Vice-Chair Gara's second question regarding the size of the deduction. He recalled discussing with the committee in the past that it set the amount. He advised that if the legislature wanted to reduce the amount of the deduction it should not take Great Bear down to 50 percent because it believed everyone should be reduced 20 percent. He stated it was not good policy. The purpose of the uplift was to treat companies equally. He recommended finding where the legislature was comfortable and keep companies all even by including the uplift. He moved on to Vice-Chair Gara's first question and answered that Great Bear still believed a shale play could work on the North Slope. It believed that the economics for a conventional play would work much better, particularly with regard to initial investment. For the last four years the company had focused its search on more conventional plays. Its exploration had resulted in a number of very promising prospects the company intended to drill in the next year. Based on a successful conventional development project the associated infrastructure would support an unconventional or shale play to follow. He explained that they were all stacked on top of each other; therefore, it was possible to follow from the same pads and potentially the same wells. He was as optimistic about finding economic oil on the North Slope as he had been throughout his time with Great Bear and before. The issues it faced were external including oil prices and potential changes to the state's tax policy and credits. 6:33:31 PM Co-Chair Seaton asked whether extending the capital expense of incumbents to a seven-year depreciation schedule would even the playing field and prevent arbitrage between the incumbents and new companies. Mr. Gavin asked for clarification on Co-Chair Seaton's question. Co-Chair Seaton explained that the idea of giving a capital expenditure write off of 100 percent in the first year for legacy companies. He continued that normally capital projects had to be depreciated over time. He continued that instead of giving new companies a seven-year uplift, legacy companies could be required to depreciate their capital expenditures over seven years. He believed it would equal out the incumbents and new players and would not cost the state more money. He believed Mr. Gavin wanted new companies and incumbents treated equivalently. He explained that he believed it was very rich to allow incumbents to write off 100 percent of their cap-ex on a severance tax in a single year. He noted that it cost the state quite a bit of money. He was trying to determine whether it was possible to make things more equivalent for incumbents and new companies instead of paying more on an uplift. He remarked that many locations made companies depreciate cap- ex, but Alaska did not. Alternatively, he wondered if there was another mechanism that would level the playing field. Mr. Gavin indicated that what Co-Chair Seaton was suggesting would be a way of mitigating the difference between the incumbents and exploration companies; however, the change would create a greater economic hurdle for new projects to come on board. Co-Chair Seaton relayed that one of the things the committee had been trying to do in the previous year in HB 247 was to address production tax credits or expenditures. He detailed there had been efforts to limit the state's exposure - for example, in relation to a production tax, perhaps the state should only give the credits when an approved development plan was in place. He noted there were a number of situations where companies had conducted large seismic projects, but never went into production or did exploration that may result in a project 20 years later. He asked if there was any way the state could limit its exposure of costs to the state related to production tax carry forward offset. He mentioned the preapproval process by DNR. Mr. Gavin thought that what Co-Chair Seaton was describing had already been resolved by HB 247 and the expiration of the exploration incentive credits. He detailed that at present there were only the NOL credits or NOL carry forward losses. There was no business model he could imagine where a company would undertake such a significant expenditure unless they intended to get some sort of revenue out of production in the future. There was no ability to monetize, profit, or return any money to investors through that kind of a system. One of the problems with the bill's current language pertaining to DNR it failed to establish a system that encouraged new investment. He spoke to the importance of encouraging companies to come in and take risks, drill wells that may fail, and shoot seismic to learn about the geology and identify potential areas for future exploration and production. He continued that investment would dry up on the front end if the state only provided a lease expenditure for situations where a discovery had been made and a company was moving towards production. He elaborated that it was too risky and the economics were not there to justify that kind of risk exposure for new companies. He believed the state had come a long way in terms of what was seen during the heat of the post-SB 21 uplift in the NOL rate stacked on top of either Cook Inlet credits or exploration incentive credits where it had been looking at 75 to 85 percent of costs being covered compared to the system going forward. The system moving forward allowed a company to carry a 35 percent loss forward. He explained that it would result in different behavior. He believed the things described by Co-Chair Seaton was no longer likely to be pursued by anyone. 6:42:13 PM Representative Guttenberg surmised with the crash of prices and the state's inability to pay credits the industry's perspective was that the situation had entirely changed. He referred to NOLs and other items. He asked what had changed and what the state needed to respond to "that's still out there." Mr. Gavin replied that the issue had resolved itself because multiple things had timed out and HB 247 had ended the Cook Inlet credit. There had been a two-year increase in the NOL credit rate from 35 percent up to 45 percent and exploration incentive credits had been stacked on the NOL credit. Both items had expired. The only remaining item was the 35 percent credit or the carry forward loss. That level of state participation would not alter behavior in the way the state may have seen in the past. 6:44:07 PM Co-Chair Seaton suggested that if the 35 percent credit or the carry forward were not going to alter behavior he reasoned that the state should not be spending the money. Mr. Gavin corrected his prior statement. He clarified that he believed Co-Chair Seaton had been speaking about imprudent investment decisions and finding a way to cut them off. He detailed that the motivating factors that lead to the imprudent decisions were no longer present. The current status quo would in no way incentivize that kind of behavior. The state would get people looking for oil who were making prudent investments associated with the likelihood that the investment would result in future oil production - otherwise those companies would be out tens to hundreds of millions of dollars. The situation would motivate good decisions on its own. 6:47:03 PM PAT FOLEY, SVP ALASKA RELATIONS, CAELUS ENERGY, LLC, mentioned the experts that had testified before him. He expressed his intent to address why Caelus mattered, about its production dilemma, and in generalities about HB 111. He underscored that tax policy mattered. The legislature decided policy and the industry decided its own behavior. He encouraged the legislature to incentivize the behaviors it would like to see. He provided a PowerPoint presentation titled "Caelus Activity Update: House Finance Committee, HB 111" dated March 22, 2017. Mr. Foley began on slide 2 and addressed why Caelus mattered. He relayed that Caelus was an operator on the North Slope. The company operated the Oooguruk field and made about 14,000 barrels per day for a total of about 28,000 million barrels of oil (Pioneer and Caelus combined was more than $2 billion). The company had recently sanctioned its Nuna project (shown in right on slide 2) - the project was currently a large gravel pad. The company had also bought about 350,000 acres to the east and the previous year it had drilled two successful exploration discovery wells in Smith Bay. 6:49:20 PM Mr. Foley addressed the Nuna project and read from slide 3: Nuna Oil Development Overview · Caelus holds 100 percent interest · 2 wells confirm reservoir deliverability · 2,800 BOPD flowed from 1st Torok well · 100 - 150 + MMBO 2P reserves · 20,000 to 25,000 BOPD peak production · Completed 22-acre NDS drill pad & road · 600,000 CY gravel / 27,000 loads · Economic Impact · 300 FTE contractor construction /drilling jobs · $2.2 Bn in royalties and taxes · Next Steps · Investor Confidence: Legislature · Modules / Flow lines Mr. Foley elaborated on slide 3. Caelus hoped to see first oil as soon as late 2018 - to make that happen it would be necessary to commit to the project, purchase line pipe, and install flow lines the current winter. However, the company was hesitant to take on the activity because of low oil prices and due to uncertainty in the oil tax regime. He pointed to the Nuna financials reflected in the lower right table on slide 3. He explained that the figures were based on an oil price of $70 per barrel; therefore, the numbers would not be as high in the current price environment. The company was working hard to go forward with the project if the reality was closer to oil prices of $60 per barrel. The numbers showed that the company had over $2 billion in future revenues that would go to the state with about $700 million in production tax, $500 million in net profit share payments, and $1 billion in royalty payments. He noted that the question was always asked about what was received [by the state] for the tax credits. He agreed that the state was helping the industry with tax credits. Under the current law the Nuna project would continue to accrue and earn about $150 million in tax credits. He detailed that if the state helped contribute about $150 million and in exchange it returned over $2 billion - it was more than a 15 times multiple on the investment. He recognized that perhaps a more fair way to look at the scenario was the state's return on all of its tax credit investment was closer to a multiple of 10. 6:51:34 PM Mr. Foley provided an update on the Smith Bay discovery (slide 4) located in the National Petroleum Reserve - Alaska (NPRA). He emphasized that Smith Bay was the discovery of a very substantial resource. There were about 6 billion barrels of oil on its leases - it could be up to 10 billion barrels. He detailed that the discovery included an area of over 300 square miles, the two wells had confirmed a gross interval of about 1,000 feet in thickness and the net sand was about 200 feet. He furthered that it was a tight reservoir and to develop the project commercially it would be necessary to expend substantial capital and to drill numerous wells. He stated that the "thing that saves us out here" was the oil they discovered, which was about 43 degree gravity oil (about twice the quality of the average Prudhoe Bay oil). He underscored that the oil was low viscosity and high mobility - it was possible to produce more oil due to its quality, through poor quality rocks. Mr. Foley continued to address slide 4. He acknowledged that Caelus had significant work to do on the Smith Bay project. He noted that "these are not reserves." He clarified that resource was defined as oil in the ground, while reserves were economically recoverable. The company planned to drill another appraisal well in the winter of 2018, which would be a lateral well of about 2,000 feet in length. The well would be fracture stimulated and a flow test would be conducted. He clarified that the exploration activity was taking place out on the Beaufort Sea. The company would spend well over $100 million to drill the well. Following the work the company would begin its environmental regulatory process for an environmental impact statement. The company hoped to be successful on the project and hoped to have first oil sometime around 2025. If the project came to fruition it would represent more than 200,000 barrels of day into the Trans-Alaska Pipeline System (TAPS), thousands of oil field jobs, and nearly $28 billion in total revenues to the state. The total came from $15 billion in royalty payments, $10 billion in tax payments, and $3 billion in ad valorem payments. He reiterated that the numbers reflected oil prices of $70 per barrel. He added that due to the remoteness of the area and the high cost associated it could take oil prices close to $70 per barrel for the project to move forward. 6:54:28 PM Mr. Foley summarized potential Caelus contributions on slide 5. Contributions could include more than 2 billion barrels of additional production into TAPS, more than 2,000 jobs during the construction and drilling phase at Smith Bay, and total payments of over $34 billion to the state. Mr. Foley turned to slide 6 and addressed what he termed as Alaska's production dilemma. The slide included a graph showing Alaska oil production from 2000 to 2040. The production actual production decline was from 2000 to 2017 was shown in blue and the projected decline for future years was shown in gray. He reminded the committee that in 2000 TAPS had more than 1 million barrels per day. At present production was only half that amount at slightly more than 500,000 barrels per day. He pointed to a pink horizontal bar on the graph representing where the TAPS minimum throughput became challenged at about 300,000 barrels per day. He remarked that he had spoken to a group with Admiral Tom Barrett [president of Alyeska Pipeline Service Company] in Fairbanks the previous day. He relayed that Admiral Barrett had reminded everyone that the industry was very good at solving problems, but there was not yet a technical solution to continue production through TAPS at less than 300,000 barrels per day. The collective goal was not to allow throughput to decline below 300,000 barrels per day. He pointed to two big ledges on the far right of the slide - the lower peak reflected all of the known projects Caelus was not a part of, including Armstrong's Pikka project and ConocoPhillips' work at greater Moose's Tooth. The graph did not include the expanded success Armstrong hoped to enjoy due to its new wells drilled in the current year (including Willow). The higher light blue peak reflected Caelus's contribution including Nuna, Smith Bay phase one and two, and hopeful exploration success in its eastern acreage, which would bring throughput up to more than 1 million barrels per day. 6:56:38 PM Mr. Foley advanced to slide 7 and quoted Ken Alper, [Director, Tax Division, Department of Revenue]: "… elimination of the NOL would have made it harder for independents to proceed with their projects" Tax Director Ken Alper, Alaska Department of Revenue Senate Resources Committee, February 1, 2017) Mr. Foley elaborated that HB 111 did not put more oil in TAPS and it did not create more jobs or new investment. He continued to address the slide and provided several quotes by Rich Ruggiero [tax consultant to the legislature]: Alaska: great rocks but high costs - "These risks need to be offset by favorable tax features" "New players should be encouraged to increase activity … they bring a fresh perspective" "Every regime, everywhere you go, allows, especially with a development like Smith Bay, everyone who develops gets to deduct the cost of what it took them to get that production from future revenues from that project. Every regime." "To deny that would really move Alaska to the bottom of the competitive scale. " Rich Ruggiero, Castle Gap Advisor Senate Resources Committee, various dates, 2017 Mr. Foley expounded on the slide. He agreed with an earlier statement by Vice-Chair Gara that Alaska was not a bad place to do business. He shared that in his previous career he had worked internationally and had been responsible for evaluating new country entries. He detailed that when evaluate the risk it was necessary to consider government take, the resource potential, how abundant the contracting community was, above ground risk, and other. He concluded that all in all Alaska was a great place to do business. He continued that Alaska had attracted companies such as Caelus, Great Bear, and Armstrong. He remarked that the state had worked feverishly to help attract the new companies and he implored the legislature to help keep them in Alaska. He agreed with Mr. Ruggiero that fresh perspective should be welcomed by the state. 6:59:27 PM Mr. Foley continued to slide 8 titled "Alaska's Future - Which slice do you want?" He clarified that the slide did not show a production forecast. He asked members to think of the pie charts shown on the slide as a cartoon. The upper left quadrant showed the piece of the pie the state was entitled to in Alaska on average under the current system. He detailed that the pie chart reflected 500,000 barrels per day. The blue portion of the chart reflected the state's share at 60 percent. The pie chart on the upper right showed the state's share under HB 111 - the state's portion was bigger. Under an alternative scenario where production was doubled the chart on the lower left showed the state's portion of the pie in a growth scenario - the state's portion of the pie would remain the same. The lower right pie chart depicted an HB 111 scenario where the state would receive a bigger pie and a larger piece of the pie. He understood it was rational economic behavior, but he did not believe it was a feasible solution. He did not believe the state could increase taxes, make Alaska less competitive, and still allow the pie to grow. 7:01:30 PM Mr. Foley moved to slide 9 remarked there was significant conversation about Alaska being entitled to its fair share and a question about what constituted a fair share. He believed it was the wrong question to ask. He believed the question to ask was how competitive the state wanted to be and if it was seeing the activity it wanted. He reasoned that if the state was satisfied with current activity it was fine. Alternatively, he recommended raising taxes if there was too much activity or finding a way to attract investment if there was too little activity. He agreed with Mr. Galvin's testimony that there needed to be a way for the state to make the payment to the companies for credits they had earned. Caelus had made investments in good faith and hoped the legislature could find a way to appropriate money to pay all of the credits it had earned. He explained that Caelus was continuing to strive to make big investments, which it could not do with its money. He specified that when Caelus went to the market for investment, there were two things that mattered to investors: confidence and stability. Any changes to the tax law impacted stability. Additionally, as long as payments remained unpaid it shook investors' confidence that their money would be returned if they invested in future projects. Mr. Foley summarized that HB 111 would increase barriers to entry, it would negatively impact new developments, and it would make Alaska less competitive for new investments. He conceded that it may generate short-term gains, but it would have a harmful effect on the state's fiscal health. He stated the bill would not attract future investment, help new developments come online, put more oil through TAPS, or put more Alaskans to work. He shared a story about a recent visit to the pipeline training center in Fairbanks. He furthered that there were numerous graduates from the program, but very few were going into oil field jobs. He stated that as changes were made to the tax policy it was the people who suffered due to lost jobs or other. He provided a story about the owner of a truck driving company. The owner had been working to help his drivers understand that tax policy matters. He underscored that due to the state's tax system, every Alaskan is in the oil business. 7:05:23 PM Representative Wilson asked if Caelus was investing in projects because of the passage of SB 21 or whether the projects had already been in the works. Mr. Foley replied that Caelus had purchased the Pioneer assets. He detailed that Pioneer had come to Alaska in 1992 and had done significant work. He explained that Pioneer had a wealth of opportunities in the Lower 48 as one of the premium companies in the Permian [Basin] shale play. He furthered that Pioneer had decided to divest its assets and had sold to Caelus, which had all occurred under SB 21. He referred to the high progressivity element under the prior ACES tax regime and although companies could earn tax credits, the credits could not be monetized unless they were sold to another company at a discount. He explained that SB 21 had brought the progressivity down - at higher prices the share was more equitable - and it allowed new companies to sell earned tax credits at full value to the state. He referred to the characterization of tax credits as a subsidy or handout. He countered that it was not the intent of the credits. He specified that the intent of the credits was to level the playing field so the efficiency of investments for new players was similar to the incumbents. He believed it was unfortunate to think of them as tax credits or NOLs. Alternatively, he suggested thinking about the efficiency of allowing large profitable companies making lease expenditures to save $0.35 per $1.00. He furthered that new companies were not able to utilize the credits until later down the road; therefore, the state made the decision to pay 100 percent cash value for them. H Mr. Foley admitted and understood that the state was not in a position to continue to pay cashable tax credits going forward. One of the recommendations from a House Resources Committee consultant was considering allowing the costs to roll forward and increase them with an interest rate. The resources committee had said no to the recommendation, but had allowed companies to take half of the credits. He implored the committee to maintain a level playing field for companies. He continued that if current taxpayers enjoyed a benefit of $0.35 on the $1.00 for every lease expenditure, the state could put new companies in a similar position by allowing them to roll credits forward and compensate for the time value of money with an interest rate. 7:09:21 PM Representative Wilson asked if rolling the credits forward with an interest rate would allow Caelus to do some of the projects it wanted to. She referred to the option as an alternative if the state was unable to pay cash credits. Mr. Foley clarified that there were two very separate issues. He explained that at present Caelus held cashable tax credit certificates in excess of $100 million. The company had done the work to earn another $100 million. The company would like the state to find a way to honor and pay the $200 million. He conceded the payment did not need to be immediate, but a bankable plan was needed. Going forward, he encouraged finding a way to keep companies in the same economic position if the program needed to be discontinued and the company would no longer be eligible to accrue cashable tax credit certificates. He was troubled that people became hyper focused on the production tax element. He reminded members there were numerous elements to government take including bonus, royalty, ad valorem tax, and jobs from the activity. He noted it would mean companies paid less production tax in the future, but the state would receive royalty from day one. Representative Wilson spoke to the cashable credit component. She asked if having a set payment plan (such as designating that the state would pay the credits owed to companies within in a five-year period) would be better than the current situation. Mr. Foley answered that five years sounded like a long time. Representative Wilson stated she had just used that number as an example. She asked for a more realistic number. Mr. Foley suggested a two-year period where the state specified it would pay a given amount at present and another set amount later. He requested something the companies could rely and bank upon. Vice-Chair Gara thought he had heard Mr. Foley testify that every regime let Caelus recover all of its expenses. He discussed that states in the Lower 48 ran on a gross tax and companies were not able to deduct. He referred to Louisiana that had a gross tax of about 12 percent. Louisiana had a minimal deduction for well costs for up to two years. He asked for verification that many other states with gross tax did not let companies get their money back. Mr. Foley replied that he believed it was wrong to mix regimes. He elaborated that in general the Lower 48 was a royalty system with a gross tax. Alaska was a complex hybrid of a royalty and a net tax with a gross tax floor. His statements related to other regimes had been about international locations with a net tax system. Vice-Chair Gara spoke to locations with a profits tax. He remarked that companies did not receive all of their expenses back in many of those locations. He believed companies received a portion based on the tax rate. He asked if the company got every dollar back or was able to deduct it. Mr. Foley deferred the question to Rich Ruggiero who would address the committee at a later date. He added that for regimes with split profits, profits were always calculated by the sum of a company's total costs minus the sum of total revenue; tax was paid on the amount if it was positive, but the amount was rolled forward if the amount was negative. Vice-Chair Gara asked if Caelus's purchase from Pioneer included Oooguruk and Nikaitchuq. Mr. Foley answered that Pioneer had been the owner and operator of Oooguruk; the asset had been purchased by Caelus when it bought out Pioneer. He furthered that ENI was Caelus's 30 percent partner; ENI was the 100 percent owner of Nikaitchuq. 7:15:05 PM Vice-Chair Gara stated that Oooguruk had been started prior to the implementation of SB 21 and had received royalty relief from the state like Nikaitchuq. He stated that no one had spoken about the benefit the state provided where if tax was too high on a field, the state reduced the royalty up to 13 percent. Mr. Foley answered that Pioneer had sold its assets to Caelus. During that time Caelus had been looking at the state and when SB 21 became law, it created an incentive program that attracted Caelus to come up to Alaska. He agreed that Oooguruk predated SB 21. He furthered that the field had qualified for royalty modification, which was about to come to an end. After the implementation of SB 21, Caelus had sanctioned Nuna, it had purchased 350,000 acres of leases in the east, and it had drilled two exploration wells in Smith Bay. He relayed that Nuna had received a royalty modification, which was done during an oil price environment that was similar to the present. The royalty modification for Nuna would expire - one of the time requirements was production by a certain date. He added that Caelus would likely apply for a renewed royalty modification. Co-Chair Seaton mentioned the cashable credit regime. He provided a scenario of a regime where a company had a 35 percent partner. He wondered about the value. He wondered if the state's participation was seen differently under a cashable credit scenario. 7:18:15 PM Mr. Foley replied that he was not certain he understood the question. He explained that credits were earned in accordance with how costs were borne. For example, if a new company and earned a 50 percent working interest it would earn 50 percent of the credits. Representative Pruitt stated that one of the major concerns that was vocalized was that a production tax would not be seen. He used the Nuna development as an example. He asked about how long there would be development coming from the project and how long it would be before the state would see the production tax come in after the repayment of the credits. Mr. Foley answered that Nuna would hopefully have its first oil in 2018. He furthered there would be a drilling rig for about four years and production would begin around 20,000 barrels per day. He specified that royalties at Oooguruk were higher than normal. The large fields had a one-eighth flat royalty, but Oooguruk had one-eighth royalties plus a 30 percent net profit. He had other leases with a one-sixth royalty. He did not know when the state would see the payout of the production tax credits, but the answer was knowable. He believed Mr. Ruggiero would show the committee examples of typical oil fields and how they may look in terms of cash flow. 7:21:29 PM Representative Pruitt appreciated the response. He believed people could get lost in the credits and fail to recognize they would bring about a benefit. He noted that Mr. Foley had highlighted that in a net profits tax everyone was able to write off the development cost. He believed the concern was the state wanted its money immediately. He wanted to ensure there was discussion about the long-term nature of the projects. He reasoned that receiving money immediately did not always end up being the best long-term investment for the state. Beyond the royalty, there will be production tax coming from investments. He surmised it may just be a matter of time before the money came in. Mr. Foley moved to slide 3 showing the Nuna development overview. He asked members to imagine a scenario where the state never received a production tax dollar. The state would still receive royalty of over $1 billion and net profit share payments of about $500 million. He then moved to slide 8 showing four pie charts. He wanted to find a way to "grow the pie." He would like the large blue portion of the large circle as opposed to the small circle; it was how the state would be rewarded. Representative Wilson asked how the discussions the legislature had annually [pertaining to oil tax] impacted Caelus's ability to get partners. Mr. Foley answered that it was challenging. He stated that the company was not challenged in resources, it was challenged by raising money at oil prices of $50 per barrel and due to the uncertainty in the tax regime in the state. Representative Wilson believed sometimes the legislature lived in its own bubble and forgot that when it was trying to recoup money it may actually be losing more because oil companies could not find partners and development faltered because the industry was perpetually wondering what the state would do next. 7:25:13 PM JEFF HASTINGS, CHAIRMAN and CHIEF EXECUTIVE OFFICER, KUUKIP SAE AND CEO, SAEXPLORATION, referred to a PowerPoint presentation titled "House Finance Committee" dated March 22, 2017 (copy on file). He shared that SAExploration was a prime contractor and an explorer; it was also the holder of approximately $20 million in tax credits and would probably receive another $60 million in credits over the next few months. He read from slide 2: · Our team has been partnered with the Kuukpik Corporation for the past 20 years · The company employs and average of 400 people per year · The Kuukpik-SAE JV is a consistent revenue source to o Kuukpik Corporation and its shareholders o The village of Nuiqsut o The thousands of Alaskan families that benefit from each program · We are committed to preferentially hire Native Alaskans and Alaska residents o We are proud of our 80%+ Alaskan hire rate · We are committed to using Alaskan subcontractors and suppliers Mr. Hastings turned to slide 3 titled "Our Core Business - Collecting Seismic Data": · Seismic Operations are the tip end of the spear · Seismic data is critical information, essential to the success of an exploration program · Recently, use of new technology is producing higher resolution images of the subsurface o Information that is a direct correlation to the new discoveries which have recently been announced · The information gathered from the seismic data is critical to finding new opportunities, new reserves to sustain Alaska into the future. Mr. Hastings elaborated on slide 3. 7:28:42 PM Mr. Hastings turned to slide 4 and addressed the benefit from a single program. The graph on the right was titled "AKlaq 3D Seismic Program," which was a tax credit program shot in 2016. The single program was benefitting over 1,000 Alaska families. The majority of the revenue generated was paid to subcontractors and suppliers who are Alaskan. Of the $57 million in revenue generated, $49 million was earned by Alaskan contractors and suppliers. Slide 5 included a snapshot of the 190-plus suppliers the company used per year. Mr. Hastings moved to slide 6 and discussed an annual seismic revenue chart from 2012 to 2017. He shared that seismic activity was a good barometer of the health of the exploration effort in any given area. The chart showed three vertical timelines shown in red - in 2012 and 2013 there was approximately $40 million and $57 million spent respectively. With the passage of SB 21 [indicated by the first red vertical bar] the increase in spending went to $139 million and $217 million in 2014 and 2015 respectively. The second red vertical bar indicated the first cut of the tax credit appropriation ($200 million cut in the fall of 2016) - at the same time there had been a decline in commodity price. In many ways there was a perfect storm happening in Alaska. The desire was for new ideas and reserves to come online, but the commodity price was falling, the state had a fiscal gap, funding had been cut for tax credits, and the result was a 55 percent difference in the amount of dollars spent on seismic in 2016. The third red vertical bar between 2016 and 2017 reflected the second cut in the tax appropriation, which also resulted in a 55 percent decrease in seismic activity spending in Alaska. He noted the chart represented all seismic spending in the state. Mr. Hastings turned to slide 7 titled "Historical Seismic Programs." He pointed to the increase in programs following the passage of SB 21 and the decrease when the commodity price began to fall and the tax credit appropriations were cut in 2015 and 2016. In 2016 the number of seismic programs fell to two. 7:32:46 PM Mr. Hastings turned to slide 8 titled "Alaska O&G Tax Policy: Our Perspective": · Alaska's current tax structure has resulted in an increase in capital spending, which has resulted in more data, new opportunities and reserves. o Seismic data enabled by current tax structure resulted in major North Slope reserve discoveries · The veto of the tax credit budget appropriation in 2015 and again in 2016 has had several negative effects o Capital spending is down--Including capital spending in the contractor community o There is no visibility, or confidence on the State's willingness to settle what it owes o Liquidity/money needed to fund projects has all but dried up o Independents, seismic companies, and most contractors cannot self-fund o Many contractors are still waiting to be paid for services they have rendered Mr. Hastings elaborated on slide 8. He explained that legacy producers had gone to work and had increased their capital spending. Alaska had attracted new ideas and companies into the state with independents and the state's contractor community had started to invest in new equipment and innovative ways to lower the cost to offset the falling commodity cost. The seismic data enabled by the current tax structure had resulted in four of the recent major North Slope reserve discoveries announced in the last three to four months. The new data and new players were resulting in new reserves and increased production. The veto of the tax credit budget appropriation in 2015 and again in 2016 had had several negative effects including reduced capital spending, no confidence in the state's willingness to settle what it owes, liquidity and money needed to fund projects had dried up or was very difficult to get, and many contractors were still waiting to be paid for services they had rendered in 2014 and 2015. 7:35:39 PM Mr. Hastings spoke to the reality for SAE on slide 9. He explained that the delayed tax credit payout had forced the company to a crossroads where two options surfaced. Option one was to seek protection under the Chapter 11 bankruptcy code and leave Alaska vendors hanging and option two was to restructure the company and work with Alaskan subcontractors and suppliers to find a way to extend payments. The company had opted for option two, which had eliminated 90 percent of the shareholder equity (the majority had been held by employees). He shared that he had moved to Alaska in 1986 and he had built two or three companies; he wanted to continue investing in the state. He emphasized that it had been nine months since the last veto [of tax credit appropriations] and there was still no plan [by the state]. He spoke to uncertainty and no visible plan on how the state would fund its debt. As a public company, SAExploration continued to see its equity eroding as the uncertainty continued. Mr. Hastings moved to slide 10 titled "The Impact of HB111 on Kuukpik SAE": · This bill as proposed reduces the cap on state purchase of credits from $70 million to $35 million per company which will dramatically stretch out payments for the debt owed. · The secondary market, which is already uncertain of its ability to purchase credits will be destroyed by this bill o many of us will have no other opportunity to monetize the credits owed other than through the state · There is no clear view or timeline for exploration tax credits: o When will the applications be processed? o When will they be issued? o When will they be paid? · The impact on this Alaska company, our Alaska subcontractors and all the Alaskan families that make their living through these companies will be significant Mr. Hastings elaborated on the slide. He explained that the bill as currently written would destroy the secondary market. As an exploration company, SAExploration would never produce a barrel of oil; therefore, it had two options - for the state to pay the company or to offer it into a secondary market. He explained that because the secondary market had been paralyzed, the company only had one option remaining. He underscored that the company was in dire need of a strategy and plan from the state to indicate to investors and shareholders that there was something to look forward to. He continued that there was no clear view of the timeline related to exploration tax credits. He understood the credits had expired; however, there were numerous credits that still had not been issued. He spoke to the compounding impact on the company and subcontractors waiting in line. The company was already impacted on its wait for cash. The bill would present another significant challenge. 7:39:54 PM Mr. Hastings He underscored it was critical Alaska remained competitive with regards to global investment. He shared that every 1.5 days the company moved a 200-person camp three miles, which cost about $100,000 per day. The same crew in the Lower 48 was one-third the size and the workers lived in hotels instead of camps. He stressed the high cost of operating in Alaska. He concluded with slide 11 titled "The Way Ahead." He stressed the need for more oil in the pipeline in order for Alaska to remain competitive; it was also necessary to find a way to lower costs for companies. The companies needed the state to issue the tax credits in a timely manner and for companies to know when they would be paid. He referred to the third bullet point on slide 11 and explained that if full and timely payment was not an option for the state, it needed to ensure the secondary market was available for the selling of credits. In order to do that, the secondary market needed to have confidence and a clear understanding of the statutes and regulations. He stated the company needed a sustainable, lasting tax structure going forward - one that encouraged new development and innovation, while maximizing value to the state. Mr. Hastings discussed that many people involved had made difficult choices and he recognized that many legislators had inherited the issue. He continued that everyone was facing the low commodity price situation. Companies had laid people off and were continuing to cut costs. He spoke to HB 111 and the fair share. He offered that every dollar the state attempted to put on its side of the fair share pile was probably a dollar that would not be spent on the types of things needed to put another barrel of oil in the pipeline. 7:44:08 PM Representative Wilson relayed she had not ever heard of the company and noted the presentation was very good. She asked how the company's process worked - she wondered if it got hired by oil companies. Mr. Hastings answered that SAExploration was a prime contractor - oil and gas companies hired it to shoot particular seismic programs. He referred to an earlier comment by Co-Chair Seaton and explained that the company also collected speculative seismic data. He used the Aklaq survey as an example, which was probably the highest resolution seismic survey ever shot on the North Slope. The survey was also shot over acreage with six or seven different leasees. The goal was to find enough underwriting to drive the cost of the program. In the specific case, the expiration side of the tax credit gave a credit, which could lower the company's cost to its end purchasers. The NOLs were decreased for every dollar the company brought in - the data was licensed. Every dollar brought in lowered the NOL credit. It was also important to note that all of the data became property of the state in order for the company to apply for the credit; after ten years the state could use the data for additional leasing incentive. 7:46:25 PM Vice-Chair Gara referred to Mr. Hastings comment that he would address Vice-Chair Gara's question on cost. He was interested in whether cost in Alaska or something else that had made ConocoPhillips' profits much higher in Alaska than in almost any other region in the world. Mr. Hastings explained that the Aklaq survey at that cost $57 million to shoot in Alaska would cost about $19 million to shoot in the Permian Basin. Vice-Chair Gara spoke to his frustration that some were suggesting the state should tax similarly to North Dakota or Louisiana with a 10 to 12.5 percent gross tax no matter what the price was. He stated it could put companies in the red up until $70 to $90 per barrel. He did not believe the idea was good. He reasoned that he was interested in getting a small increase when companies were profitable. He noted that many legislators were trying to explore that concept. He did not believe he would ever be able to do anything that would make an oil company say it would pay the amount. Mr. Hastings explained that his comments were more about the delicate situation in Alaska at present - many companies were competing for global dollars. Although there were great opportunities in Alaska, it was extremely difficult for investors, shareholders, and public equity to continue to invest in the state. His point had been there was currently a dangerous balance and he did not believe anyone understood where the tipping point was. He surmised the tipping point would be different for every company. He shared that his company was already working at or below cost at the current oil price of $45 per barrel. Many contractors had agreed to work at cost in exchange for something in the future. When the state looked at raising taxes or hardening the [tax] floor, which was a cash flow problem at the end of the day, there had to be more avenues open to the state than taking another dollar it needed to be spent on the types of things it would take to get more oil in the pipeline. The state had assets, which surely allowed the state to find different ways to bridge itself across the fiscal gap. 7:50:40 PM Co-Chair Seaton referred to the language indicating the bill would reduce the cap on the state purchase of credits from $70 million credit to $35 million (slide 10). He remarked that during the meeting the committee had heard from several companies with over $100 million or more in credits. Currently the structure was first in, first out. He needed clarification on the slide. He believed the slide indicated amount of money going to more companies. Mr. Hastings replied that he could not speak for all other companies, but currently SAExploration did not know where it fell in the queue. The company may have to come before the committee the following year and relay it had missed the funding. He explained that if all players were leveled and credit 1 was the same as credit 21 in timing, everyone would be looking at $35 million per year. There were numerous outstanding credits that had not been issued that had the potential to fall in the next year or following year's queue that had been earned in 2014 and 2015. He explained it was a problem. Co-Chair Seaton asked for clarification on Mr. Hasting's position. He asked if the legislature should keep the number at the higher amount so fewer companies received the money or reduce the number to $35 million as in HB 111 in order for the money to stretch [across all companies]. He surmised if there was $300 million, it would stretch through twice as many companies with a $35 million cap per year instead of a $70 million cap per year. He thought the slide appeared to recommend paying the higher amount to fewer companies. 7:53:41 PM Mr. Hastings explained there were numerous companies with a lot of different financing criteria at present. For example, if a company had $120 million in tax credits, under the current $70 million limit the company would be paid in two years. He could only speak for SAExploration, but obviously getting the money faster was much easier to sell to stock and bond holders than having to wait for the funds over a four year period. He underscored that having a plan was the important thing - something that gave people visibility. He explained that it was not possible to keep telling the board or bond holders that the state was working on it, because it had been saying that for two years already. He believed they needed to come up with a plan people felt confident in. It was currently a total unknown and to continue the unknown would mean only one outcome for many companies. Co-Chair Seaton wanted to hear from other companies about whether they recommended the $70 million or the lower amount of $35 million. 7:56:03 PM Representative Tilton thanked Mr. Hastings for providing a different perspective. She appreciated the company for employing Alaskans. She referred to the confidence and clear understanding of statutes and regulations on slide 11. She believed she had heard that the bill made it hard to have confidence. She asked for the accuracy of her statement. Mr. Hastings answered that the secondary market had been very thin to begin with; there had not been significant opportunity in the secondary market. He referred to an advisory bulletin - the secondary market was paralyzed at the current point. The market did not know whether credits earned and taken below the floor were allowable under the new interpretation. He stated that it could be back to the passage of SB 21 - the regulation was a significant issue that needed to be clarified. There was already paranoia and now there was no cash payment for an NOL. He provided a hypothetical scenario where the credits that were supposed to go to everyone August 31 were pushed to January 2018. In that scenario the explorers without any ability to roll forward the credits based on expenditures would be done. The bill was written based on the date of issuance, not the date the credit was earned. Feasibly, $15 million to $40 million in tax credits could roll across the date and the state would no longer make the cash payment. Representative Tilton surmised the bill would be unhelpful to the company, especially since it had already had to reorganize. Mr. Hastings replied that the graphs on slides 6 and 7 were a clear barometer. He stated that people would take their feet off the investment accelerator. Companies had created new opportunities, increased production, and had invested in Alaska's oil and gas future. The vetoed appropriations in conjunction with a declining oil price and HB 111 meant companies would decelerate and move cautiously going forward. He continued that the bill would mean taking time and analyzing business decisions. He concluded that for Alaska's future, the business decisions needed to be aligned. 8:01:20 PM Representative Thompson noted that Armstrong Oil and Gas had provided written testimony to the committee. HB 111 was HEARD and HELD in committee for further consideration. Co-Chair Foster provided the schedule for the following day.