Legislature(2015 - 2016)SENATE FINANCE 532
04/13/2016 05:00 PM FINANCE
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SENATE BILL NO. 130 "An Act relating to confidential information status and public record status of information in the possession of the Department of Revenue; relating to interest applicable to delinquent tax; relating to disclosure of oil and gas production tax credit information; relating to refunds for the gas storage facility tax credit, the liquefied natural gas storage facility tax credit, and the qualified in-state oil refinery infrastructure expenditures tax credit; relating to the minimum tax for certain oil and gas production; relating to the minimum tax calculation for monthly installment payments of estimated tax; relating to interest on monthly installment payments of estimated tax; relating to limitations for the application of tax credits; relating to oil and gas production tax credits for certain losses and expenditures; relating to limitations for nontransferable oil and gas production tax credits based on oil production and the alternative tax credit for oil and gas exploration; relating to purchase of tax credit certificates from the oil and gas tax credit fund; relating to a minimum for gross value at the point of production; relating to lease expenditures and tax credits for municipal entities; adding a definition for "qualified capital expenditure"; adding a definition for "outstanding liability to the state"; repealing oil and gas exploration incentive credits; repealing the limitation on the application of credits against tax liability for lease expenditures incurred before January 1, 2011; repealing provisions related to the monthly installment payments for estimated tax for oil and gas produced before January 1, 2014; repealing the oil and gas production tax credit for qualified capital expenditures and certain well expenditures; repealing the calculation for certain lease expenditures applicable before January 1, 2011; making conforming amendments; and providing for an effective date." 6:23:55 PM BENJAMIN JOHNSON, CEO, BLUECREST ENERGY, DALLAS, TEXAS (via teleconference), read from a prepared statement "BlueCrest Testimony to Senate Finance Committee" (copy on file) on a PowerPoint presentation: Good afternoon Madam Chair and members of the Committee. For the record, my name is J. Benjamin Johnson, and I'm the president and CEO of BlueCrest Energy Inc. Since BlueCrest only has operations in the Cook Inlet at this time, I will only speak to the issues particular to the Cook Inlet, with a specific focus on the following points: First, I want to emphasize that, specifically with regard to what BlueCrest is doing in the Cook Inlet, the tax credit program is an extremely good investment for the State. Second, the State's investment in Cosmopolitan through the credit program will provide significant future positive value to the State, even at low oil prices. And it is the State's investment through the tax credits that has facilitated success in the Cosmopolitan Unit. I'm going to show you that the State's investments in the Cosmopolitan tax credits will provide high returns even at low oil prices. In fact, the tax credit investments under the current laws can actually provide higher rates of return to the State than the average investments in the Permanent Fund. Third, I will speak to several specific issues we have identified in SB 130 and the CS from Resources. Slide 2: For your reference, the Cosmopolitan Unit is located about three miles offshore in the Cook Inlet, a few miles north of Anchor Point. All of the productive area in the unit is on State leases. Slide 3: The Cosmopolitan Unit actually consists of two separate development projects. There are numerous productive gas zones directly above underlying oil zones, and the gas reservoirs are not connected to the oil reservoirs. We haven't yet started developing the Cosmopolitan gas zones. The offshore Cosmopolitan gas development is now on hold, due to economic questions on tax credits, costs and confirmation of stable long-term market demand. But development of the deeper oil reservoirs was more straightforward. And two years ago, based on the tax regime in the Cook Inlet under current laws, we committed to begin development of the oil reserves. BlueCrest is a small private company with a singular focus of developing the Cosmopolitan Unit, and we are very careful in development of our business plans. This is a large project for our company, and we were faced with the challenge of how to pay for development of the new field. We teamed up with a group of oil industry investors, and we very carefully created our plan with them for financing the development of Cosmopolitan. Slide 4: I have shown this conceptual slide in previous testimony, so I won't go into the details. However, the main point to see here is that any oil and gas development is a long process. It takes a lot of spending just to get to the point where we are bringing in enough cash to cover our monthly costs without additional investment or borrowing. We estimate that it will have taken investments of over $500 million to reach that point for Cosmopolitan, and BlueCrest is within about 6-9 months of getting there. As you can see, we still have considerable additional investments to make in drilling a few new wells later this year that should provide enough cash flow to at least make our debt service payments going forward. And we've already committed to that spending, based on the existing tax credit structure. So the timing of any changes over the next few months is very important to us. Slide 5: So let's talk specifically about Cosmopolitan. We've been working on the oil development for over two years, and right now, we are literally a few days away from the very first commercial production of oil. Next, we will bring in our new specialized drilling rig and start drilling new wells to bring on the production that can finally start paying off our loans. And that new drilling cannot begin until the second half of this year. These photos show the progress we have made so far with the onshore Cosmo production facility. The total site is 38 acres, and contains the drill sites for up to 20 wells and the facilities to process the oil. We are almost complete in our construction process, and we are now running the final operational tests today. We will have our new drilling rig in place to begin drilling the new wells by July 1 of this year. Slide 6: So let's look at what the tax credits from a successful development project like Cosmopolitan actually mean to Alaska. When the tax credits are used for development of new proven reserves in the State, they are - without question - a valuable low-risk investment. The tax credits make new projects work, and they bring new sources of long-term revenues to the State for decades into the future. At Cosmo, we are sitting on a large proven resource of future oil and gas that now simply requires additional new investments to bring it to full production. On February 19, the DOR provided its analysis of the financial impact to the State on development of a new Cook Inlet oil field, assuming that no changes are ever made to the existing tax laws. DOR's analysis modeled an "example" Cook Inlet field that happens to be somewhat similar to Cosmopolitan - but is more expensive and less productive than the actual Cosmopolitan oil development. So the DOR's calculations are, in fact, conservative with regard to Cosmo. Slide 7: This chart is a summary of the calculations the DOR provided for their "example" field. It shows the total net future benefit received by the State and municipalities, as a function of various future oil prices. It shows that, even for this conservative example, the State would receive back 100% of its investments in the tax credits if oil prices over the entire field life average only about $35 per barrel (assuming no changes to the current law). At about $59 per barrel average oil price, the State would receive back triple its investment in the tax credits. Slide 8: The DOR also provided discounted-cash-flow calculations for this example field, with a head-to- head comparison to the investments by the Permanent Fund. At any point on this chart greater than zero, the State would earn a better return through its investments in the tax credits than its investments in the Permanent Fund. This chart shows that, even in the case where there are never any changes to the tax system in the Cook Inlet, the State's investment in those tax credits for the example field is still better than the average investment in the Permanent Fund as long as oil prices over the next 30 years average only $44 per barrel. Slide 9: Now I'd like to show you BlueCrest's internal analysis of the value to the State in keeping the Qualified Capital and Well Lease Expenditure credits as they apply to new oil wells drilled at Cosmopolitan. We projected the net return to the State using a conservative calculation including only the incremental royalty for each single new Cosmopolitan oil well drilled. This chart shows the calculated return on investment to the State from the WLE and QCE. A 100% return on investment means that 100% of the tax credit would be repaid to the State at an average oil price of only $24 per barrel. At $40 per barrel, the total return would be about 170%, and at $60 per barrel, the return would be about 250%. So you can see that these credits, at least for Cosmo, are likely to be a very good low-risk investment for the State. Slide 10: The bottom line here is that, in periods of low oil prices, the QCE and WLE credits allow us to continue drilling the Cosmopolitan oil wells at approximately $10 lower oil prices than without the credits. This is likely to be an important factor over the next few years and may allow us to continue drilling instead of shutting down the rig. For us, the NOL credit is less important as we begin producing. So the most important credit for continuation of drilling in a development like Cosmo is the WLE. Slide 11: Under the CS, the tax credit repurchases would receive priority for payment based on the resident hire percentage in the prior year. While we certainly agree that we want to hire Alaskans for our operations, imposition of any reductions in credit payments for expenditures that were made prior to the effective date of a new law is truly a retroactive tax change. For credits filed in 2016 (for 2015 expenditures) and those filed in 2017 (for 2016 expenditures prior to the new law taking effect), there would have been no way for us to even keep records. Retroactively changing the laws is grossly unreasonable. If this provision is adopted, a longer transition time should be considered. Slide 12: For the record, BlueCrest is strongly committed to hiring Alaskans. At this point, 100% of all our long- term operations employees are Alaskans. But making the future credit payments subject to hiring in the past is probably impossible to even measure. We can do it going forward, but I don't know how we go back in time. Slide 13: Another factor in SB 130 was setting a limitation in the credits that can be paid annually. If this limit is too low, it would be particularly damaging to small companies like BlueCrest who have already invested in good faith, based on the tax policy in existence when we entered into the commitments for our investments. We came to Alaska based on the credits. We invested our cash, and we have borrowed a lot of money and committed to spending a lot more - all based on the tax credits. And the timing of the receipt of those payments for the credits is paramount in our ability to make the payments on the loan obtained for those investments. Slide 14: Most important of any of these provisions to BlueCrest is the timing of implementation of any changes, whatever they may be. It is now April, and the proposed changes in the original SB130 were supposed to take place on July 1. The CS has somewhat moved that date back, which would certainly help but may not completely solve the problem. It's important to understand that, before we ever started the oil development project, we made sure that we would have enough funds to allow us to complete construction of the onshore drill site, production facilities, bring in the most powerful drilling rig in Alaska, and use that rig to drill at least the first two new oil wells. We calculated that we would need approximately $525 million to reach that point of self-sufficiency (where we no longer have to keep borrowing additional money to put into the project). The timing here is very important, because we expect that should happen in the first half of 2017. As I mentioned a few minutes ago, based on existing law, we very carefully planned how we could pay for development of the Cosmo project before we ever started. Our shareholders invested approximately $200 million in cash. We borrowed $30 million from AIDEA for a loan on the drilling rig (kind of like a car loan but for a drilling rig). We have already received a total of $24 million to date in tax credits. Under current laws, $121 million would come from future payment of credits earned for 2015 and 2016 spending (that's the total for two years). We then made up the difference by securing a $150 million high-interest development loan. We have spent a lot of money to get to the point where we can now start drilling these new wells, but an abrupt termination of the tax credits on which we have based our entire financial planning would be devastating. Any reduction in the credits for our spending through at least early 2017 would mean that we have to come up with that money from some other source. That's not easy in this oil price environment, and it may just simply be unworkable. We have finally reached the point - by completing all this work and spending all this money- to where we will finally have our rig ready to drill in the second half of this year. We need the production from the first new wells to pay for the costs we have spent so far. Those drilling costs - at least through early 2017 - are all based upon the assumption that we will be able to obtain the credits under existing law for those investments. We have done all this work and spent all this money to date, and it seems only reasonable for us to be able to claim the existing credits for the spending that is the result of our investments based on the expectation that the State would honor its share of the investments. We need to be able to be able to get to the finish line. If the date for changes is too soon, we won't have the full funding for finishing the project, although we have already committed those investments. We've signed contracts, bought a drilling rig, built facilities - all based on the current laws in effect. Slide 15: In conclusion, I'd like to reemphasize the importance of phasing-into any changes over a reasonable time period. Everyone in Alaska understands that when we are driving on slippery icy roads, the most dangerous thing we can do is suddenly slam on the brakes. Thank you. 6:33:44 PM Co-Chair MacKinnon pointed to slide 14 and mentioned the Alaska Industrial Development and Export Authority (AIDEA) loan that the state provided for $30 million. She wondered if the development loan was with an entity other than the State of Alaska. Mr. Johnson responded, "Yes, the development loan is with a private lender". Co-Chair MacKinnon referred to the tax credits received to- date wondering if she should subtract the amount from the 2015-2016 time period or if it was in addition. Mr. Johnson replied that it was in addition and that the total credits associated with the project would equal $145 million. Co-Chair MacKinnon wanted to confirm her math. Vice-Chair Micciche asked if Mr. Johnson could provide slide 7 and slide 8 without the municipal revenues. He wanted to see the state royalty figures by themselves. Mr. Johnson explained that the slides were a result of the Department of Revenue's calculations. He thought Director Alper would be able to supply the information. He did not have the underlying data, only the final numbers. 6:35:48 PM BRUCE WEBB, FURIE OPERATING ALASKA, ANCHORAGE (via teleconference), relayed that Furie came into existence through Escopeta Oil Company in 2010. Since that time, Furie brought the first jack-up rig to Alaska. Furie recently installed the first offshore platform in about 2 decades. It was comprised of 16 miles of subsea pipeline and a new gas processing facility in Nikiski, Alaska. Over the previous 5 years the company had invested approximately $700 million in the wells, pipeline, and processing facility. During the peak of construction the company employed over 300 people in Alaska and invested about $200 million. He mentioned that the offshore season in the Cook Inlet was from April 15th to October 31st of every year. During the period outside of the drilling season Furie still had to pay for storage for the jack-up drilling rig. Offshore development was very expensive. At the beginning of the project Furie viewed the State of Alaska as a partner. The company made all of its financial decisions based on the tax system in effect at the time. Mr. Webb continued that the result of the company's impacts on exploration and development was the local Cook Inlet gas market. The company recently signed contracts with Homer Electric Association, Inc. and ENSTAR Natural Gas Company. As a result of those contracts beginning in April 2016 the cost of energy to consumers in the Kenai Peninsula was lowered by 12 percent. In 2018 the cost would be about 16 percent lower than the cost in 2015. He furthered that Furies' contract with ENSTAR Natural Gas Company would begin in 2018. In 2018 the cost of gas to ENSTAR customers, roughly half of the population of Alaska, would be reduced by 17 percent. Aside from the direct influence Furie has had on the local gas market the company had also seen it trickle down to other companies. The Chugach Electric - Hilcorp contract resulted and would lead to an 8 percent reduction in costs to their customers. He explained that the reductions were due to the competition Furie and other small independents brought to the market. Mr. Webb opined that without the tax credit program Furie would not have been able to undertake the project. Otherwise, it would have been too risky in the beginning and too expensive towards the end of development. The tax program was needed in order to meet obligations Furie entered into years ago. Going forward, if there was a change in the tax credit program the company would have time to adjust. He noted that the way the governor's bill was currently structured. The tax credit program would change in 2016 and would be devastating to the company. Some certainty through the rest of the current year was necessary in order for Furie to fulfill its commitments that were made in 2013 and 2014. He deferred to David Elder to provide further testimony on Furie's behalf. 6:39:37 PM DAVID ELDER, CEO, FURIE OPERATING ALASKA, HOUSTON, TEXAS (via teleconference), had three important points he wanted to cover in terms of tax credits and the proposed changes. The tax credits were intended to incentivize companies to make investments in the industry. Furie moved quickly and raised capital to come to Alaska. The company brought the first major production to Nikiski and the Anchorage area from the Cook Inlet since the 80's. Mr. Elder relayed his second point. Furie was in the final phases of its project that began in 2013. In Furie's business it had to plan several years ahead in order to meet logistics of such a project. In addition, the company had to enter into financing commitments in 2013 and 2014. Furie needed certainty going forward and the opportunity to at least finish what it started based on the existing law. Mr. Elder' third point was that the tax credits had been an important source of liquidity and had enabled Furie, a development stage company, to obtained economical financing. Thanks to the tax credit program Furie had seen its financing costs drop from about a 20 percent range to an 8 percent financing cost. As a result of the uncertainty of what legislation might pass and whether credits filed for in the previous year would be paid, it was more difficult to secure financing. People had pulled away from the markets. The most recent bid for financing off of the current year's tax credits was about 60 percent of the face value of the credits. He was certain the legislature and the people of Alaska would rather see the additional 40 percent invested in important infrastructure and energy production which would result in employment and other activities. Moving forward, Furie was asking the legislature for some certainty to make sure Furie was funded for expenditures already made and to allow the company to complete the project without mid-year changes to the tax credit structure. He was available for questions. Co-Chair MacKinnon indicated that there were no questions for members and thanked him for his statement. She invited the next testifier to begin his testimony. 6:43:25 PM TONY IZZO, GENERAL MANAGER, MATANUSKA ELECTRIC ASSOCIATION, ANCHORAGE (via teleconference), explained that the utility was the second largest electric utility and the third largest buyer of natural gas in the Cook Inlet. His background included having been at ENSTAR Natural Gas (ENSTAR) from the late 90's to about 2007, serving as the president from 2001 through 2006. His testimony was intended to give his perspective as a buyer of gas in the Cook Inlet and about cause and effect. The business was a long lead time capital-intensive business. He spoke to witnessing the changes in the Cook Inlet market. He noticed that the excess natural gas discovered while exploring for oil in the late 50's and 60's was coming to an end. Gas could not be purchased under the terms the state had been able to for prior decades nor could gas be found for sale under legacy terms. He continued that something different occurred when the market shifted - a Henry Hubb linked contract in the amount of 450 Bcf [billions of cubic feet] was entered into in 2000 or 2001. It had a trailing average of Lower 48 prices which was currently in the $2 range. Unfortunately, regulators, some members of the public, and certain legislators responded negatively about linking Cook Inlet gas to a market that the state was not physically connected to. As a buyer he was negotiating with entities based outside of Alaska who had choices of where they were going to invest their capital such as Alaska, the Lower 48, or in other places in the world. He reported being able to enter into a long-term contract that required millions of dollars in investment. He thought the number was exceeded by a factor of three. As a result of some negative public reactions to prices being linked to the Lower 48, ENSTAR entered into another 36-month contract in 2005 with Marathon and would have filled all of ENSTAR's gas requirements through 2016 at a price of the 12 month trailing average of the Lower 48. As a buyer he was currently paying $7.42 for gas. If Lower 48 prices were available he would pay about $2.00 for gas. The perception of the contract and the pricing mechanism was so negative that it was not approved. He observed that the state sent a signal to the market and to investors that it was no longer open for business. Over the following few years the investments slowly dried up and assets in the inlet were sold. In 2009 and 2010 the utility was looking at importing LNG because only 20 percent of the contract fulfilled the utility's demand for more than 1 or 2 years at a time. To the legislature's credit the Cook Inlet Recovery Act created and fostered an environment that brought investment and new players back to Alaska. He found that prior to Hilcorp purchasing the Marathon and Chevron assets he could only purchase 20 percent to 25 percent of the gas Matanuska Electric at about $10 per MCF [million cubic feet]. Upon Hilcorp's arrival in the aging and mature fields they improved production and made gas supply available for purchase to utilities through 2018 which Matanuska Electric took part. 6:49:30 PM Mr. Izzo continued that the price was negotiated by the attorney general through a consent decree to address a Federal Trade Commission concern. He thought Hilcorp had done a great job. However, currently the state had new players investing real capitol. He reviewed some of the industry companies that have brought on production. He was afraid of sending the wrong signal to industry investors which would likely lead to dried up investment. The unintended consequence was insecurity. He thought the good and bad news was that the state had temporary energy security. Many of the new reserves were not behind pipe which required millions of dollars in investments. It would be in the better interest of his customers for him to purchase imported LNG at the right price than to risk entering into the exploration and production business to bring new reserves online. He concluded that, based on his experience, uncertainty was the enemy of energy security. He believed the state was very close to seeing real results from the Cook Inlet Recovery Act and the tax credits in place currently. He clarified his understanding of the monumental task before the legislature regarding the state's fiscal gap. He hoped the legislature would take action that would minimize uncertainty and help to get to the results that were sought in growing the market. 6:52:41 PM Co-Chair MacKinnon wondered if the legislature should institute a tax on all rate payers so the state could pay the credits to secure the energy. Mr. Izzo replied that a tax would be like a fuel surcharge. He was not taking a position that the state should leave the credits alone or significantly change them. His recommendation was that whatever action, it should be taken sooner rather than later to eliminate uncertainty. He added that when the governor postponed paying the $200 million in tax credits with a veto a gas deal between Matanuska Electric and a new Cook Inlet producer evaporated. It was a combined supply with another utility that would have saved $10 million per year. SCOTT JEPSON, VICE PRESIDENT, EXTERNAL AFFAIRS, CONOCO PHILLIPS, ANCHORAGE (via teleconference), noted that Conoco Phillips was not a member of AOGA. He introduced the PowerPoint presentation, "Senate Finance Committee CSSB130 - April 13, 2016." He turned to slide 2: "Agenda." He took a few minutes to discuss the current economic environment and what had happened since the passage of SB 21 [Legislation passed in 2013 - Short Title: Oil and Gas Production Tax]. He relayed he would also be talking about the company's concerns with SB130 and the committee substitute. Mr. Jepsen addressed slide 3, "Activities Since Tax Reform (MAPA) Passed." He reported that since MAPA was passed Conoco Phillips had followed through on what the company stated could happen with a more attractive investment climate on the North Slope. The company had added a number of rigs to its fleet as well as two new-build rigs. Conoco had taken delivery of one of the rigs and was expecting to take possession of the second later in the current year. Since the passage of SB 21 the company had gone from 3 rigs in the western North Slope rig fleet to between 5 and 6 rigs. Currently, Conoco had 4 running and anticipated 5 running later in the year when it took delivery of one of its new rigs. Mr. Jepsen continued reporting that Conoco only had 3 rigs operating in the remainder of the United States. The company's activities in Alaska were differential at present. He had a list of other investments that Conoco Phillips had made since the passage of SB 21. He would not review it but would briefly discuss activities in the National Petroleum Reserve Alaska (NPRA). The company currently had a new field in progress, Greater Moose's Tooth 1 (GMT1), and there was another field 9 miles from GMT1 called Greater Moose's Tooth 2 (GMT2) which was in the process of being permitted. He noted that none of Conoco's new fields that came on stream since SB 21 was passed were receiving the gross value reduction (GVR). Some of the production on CD5 and drill site 2S could qualify for the GVR. However, some of the requirements necessary made it not cost effective for Conoco to pursue. 6:57:14 PM Mr. Jepsen advanced to slide 4, "Capital Spending Trends." He explained that the slide addressed what was happening with the capital spend as a corporation operating in Alaska as well as oil price. He figured everyone was very familiar with what had happened with oil prices. He pointed to the plot in the upper left-hand corner which showed the effects of the decrease in oil prices on Conoco's capital investment. There was a commensurate drop in the company's capital investments. On the right-hand side there were some statistics outlining the company's activities in Alaska. The company's capital spend peaked in 2014, but even with the decline in oil prices it still anticipated spending about $1 billion in 2016. He noted that the amount spent during the years of Alaska's Clear and Equitable Share (ACES), a time when oil prices were considerably higher, was about 25 percent less that in 2016. He directed attention to the bottom right-hand part of the slide that showed what percentage of Conoco's corporate capital was being spent in Alaska. It was clear the company was making a substantial investment in the state. Mr. Jepsen discussed slide 5, "North Slope Investors Negative at Current Pricing." He explained that the slide was derived from the 2016 Revenue Sources Book. The left side, the "Y" axis, represented net cash flow, and the "X" axis represented ANS West Coast price. The chart showed the relative position of the state compared to the producers at current pricing as prices increased. Regardless of oil price the state was always in a positive cash flow position excluding reimbursable tax credits that might pay out. The chart did not include the tax credits but included the per barrel credits. Investors were in a negative cash flow position. He stressed that it would difficult to increase taxes on an industry that was in a negative cash flow position without it impacting investments. In 2015, Conoco Phillips experienced a negative cash flow of more than a $1 million negative cash flow in Alaska. The company did not incur any net operating losses (NOL's). He was uncertain if the company would be in the same position in 2016. 6:59:41 PM PAUL RUSCH, VICE PRESIDENT, FINANCE DIVISION, CONOCO PHILLIPS, ANCHORAGE (via teleconference), turned to slide 6, "Key Concerns with Original SB 130 Bill." The slide identified areas associated with SB 130 that caused the greatest concerns for Conoco Phillips and had the greatest potential to negatively impact its investment in Alaska. His comments would address the original bill but, he would make a few comments regarding the committee substitute. He relayed that the case made against the increase in the minimum from 4 percent to 5 percent was made in the previous slide. He reiterated that the industry was currently in a negative cash flow position and would remain so at prices up to approximately $50 per barrel of oil. Increasing taxes while the company was experiencing losses would lead to reduced investment. Mr. Rusch next argued that hardening the minimum tax floor effectively served as a tax increase. Under SB 21 companies were currently allowed to reduce their tax below the minimum with the use of NOL's resulting directly from losses businesses were incurring in Alaska. The particular treatment was consistent with federal income tax treatment which allowed recognition of losses and periods where a company was no longer in a loss position. Eliminating or delaying the use of the NOL's would result in companies reducing expenditures in Alaska for which they would no longer be receiving a tax deduction. Although it was an important issue for the industry to help support investment during periods of low prices, the size of the future obligation had likely been exaggerated by the DOR in some of their recent testimony. There were companies that would adjust to the lower prices and would not continue to experience losses at the projected levels. Conoco Phillips did not have an NOL in 2015 and current prices were more challenging. Mr. Rusch moved to the next item which surrounded the increase in the interest rate. He highlighted that increasing the interest rate on lower or under paid taxes was an issue due to the lengthy time involved in completing and closing out audits. The issue was caused by the current 6-year statute of limitations. He provided two related examples. Conoco Phillips just recently received its 2009 production tax audit - 6 years and 3 months after the completion of the tax year. The company also recently closed out its 2006 production tax audit - 9 years after the end of the audit. It could lead to tax assessments when the interest component was as much or greater than the underlying audit findings. The Senate Resources' committee substitute was an improvement, as it reduced the interest period to 3 years and could lead to shorter audit periods. The company was concerned that the applicable interest rate was still too high. The federal rate was approximately 3 percent compared to the 7 percent plus the federal discount rate in the committee substitute. Mr. Rusch argued that restricting the use of per barrel and other tax credits to a specific month contradicted the underlying principle of an annual tax. He noted that the slide referenced per barrel credits. However, expressed earlier in Exon's testimony, it potentially had much broader implications. It was discussed in detail in prior testimony by the DOR. The concern the department raised was that companies were migrating per barrel credits between months. Conoco Phillips completely disagreed with the characterization. It was clear in the statutes and in regulations that the production tax was a yearly tax with monthly installments made. He emphasized that it was an annual tax and any attempt to characterize it differently was incorrect. The proposed changes by the administration was a radical from the principle of a yearly tax. Mr. Rusch brought up that the confidentiality and disclosure provisions were much too broad in SB 130. The company recognized the desire for greater transparency, particularly around reimbursable credits. As currently written, SB 130 could potentially lead to the disclosure of all tax payer information which violated competitiveness and potentially conflicted with Internal Revenue Service, FCC, and other regulations. 7:04:48 PM Mr. Jepsen addressed slide 7, "Observations." Conoco Phillips favored the committee substitute over the original bill. However, the company had some concerns. First, there were concerns about the interest terms. There were also concerns about the time limitations on the use of the GVR which negatively impacted the economics of the development of new oil and would be a consideration as the company looked at its new investments. He added that it did not help Alaska compete in Conoco Phillips' overall portfolio. He also questioned the impacts of the removal of the ceiling tax on North Slope gas used in-state. The company was unclear about the goal of the policy and the potential impact of their business on the North Slope. Mr. Jepsen concluded that there had been several tax changes in Alaska over the previous ten years. He advocated for a stable, durable fiscal policy for oil investment and investment on any major North Slope gas project. A stable tax regime would foster confidence and further investment in the state. It had only been 19 months since SB 21 had been ratified by voters and another change to the tax regime was being contemplated. Conoco Phillips appreciated the challenge legislators had in front of them. His goal of the presentation was to provide some insight in terms of how tax policy affected the company's investments. Vice-Chair Micciche wondered about the time limit on the GVR and referred to slide 7. He noted that enalytica [Legislative oil and gas consultant] had shown that the lower the price of oil, the greater the impact for companies over a longer period of time. At a higher price the limit on the GVR would have less of an impact on the value of the project. He wondered if an alternative time limit would be better. Mr. Jepsen answered that any kind of change to the time limit was negative. He thought enalytica had done work to show relative impacts. He would leave it to the committee to determine the appropriate balance point. Obviously, anything that reduced the time period reduced the competitiveness of the project. Co-Chair MacKinnon thanked the presenters from Conoco Phillips. She invited the last presenter to begin his testimony. JARED GREEN, PRESIDENT, ENSTAR NATURAL GAS, ANCHORAGE (via teleconference), introduced the PowerPoint, "Presentation to the Senate Finance Committee, April 13, 2016" (copy on file). ENSTAR was the largest purchaser of natural gas in the Cook Inlet. Ultimately, their customers were beneficiaries of the tax program that had been in place since 2010. Their customers depended on natural gas from the Cook Inlet to heat their homes, businesses, schools, hospitals, and industries. Fundamentally, ENSTAR's interest was in the fostering of a stable and appealing natural gas environment in the Cook Inlet. He claimed that the environment needed to exist in the short-term, medium-term, and the long-term. Mr. Green looked at slide 2, "Natural Gas Supply Needs." 141,075 Customers Anchorage, Anchor Point, Big Lake, Girdwood, Homer, Houston, Kenai, Palmer, Soldotna, Wasilla, and Whittier 33 Bcf/year Peak deliverability 287 MMcf/day ENSTAR's number one priority was safe, reliable natural gas service to its customers. The company was founded in 1959, the same year as statehood. On average their customers used about 33 BCF of Natural gas per year. In a warm year, such as the previous year, use could be as low as 30 Bcf or in a cold year upwards of 35 Bcf. Recently enalytica prepared a report that indicated total state use at about 80 Bcf. 7:09:22 PM Mr. Green addressed slide 3, "Supply and Demand." He remarked that ENSTAR had a very high seasonality to its gas needs. The company generally varied by roughly a 12 to 1 ratio of winter to summer gas needs which meant that their customers burned about 12 times more gas on average in the winter as what they did in the summer. He reported ENSTAR's daily variability. Living in Alaska meant living in an environment that could have substantial variability in gas demands due to weather. With the current company customer base they had a potential daily demand of 287 Bcf per day. He pointed to the thin red line on the graph which represented the 287 Bcf per day. Such a level of demand was likely to occur in January of any given year. ENSTAR also had the potential of meeting less than 100 Bcf per day if there was a warm spell happening on the same day. There was a significant variance to what could occur purely due to weather. He highlighted the graph showing the variability in their customers' daily demand as well as ENSTAR's daily supply through the years 2014 and 2015. The chart contained the actual data which the company supplied gas each of the days listed for the years listed. Each of the natural gas suppliers were represented by a different color on the chart as well as how much gas was consumed on each day in the 2-year period represented by the black line that topped off the chart. He noted that the day-to-day variability was marked. ENSTAR's customers' demands changed as weather changed seen as the constant spike up and down. The second piece was the seasonal variability. The 12 to 1 ration could be seen with the summer troughs and the hills through the winter. 7:11:12 PM Mr. Green looked at slide 4, "Supply Contracts 2016-23." He stated that when ENSTAR planned its natural gas portfolio they looked at many years in advance. Operating in such small, closed supply networks such as the Cook Inlet required very long lead times. The company needed to know that there was firm gas supply for their customers at least 2 years in advance. Anything less put the market place at risk of supply shortages. In ENSTAR's business they had to have gas available for their customers on the coldest days no matter the circumstance. He expanded that when it was 20 degrees Fahrenheit below zero on a dark January evening every single one of 141,075 customers had to have their gas needs met. Their number of customers represented over 50 percent of the population of Alaska. Mr. Green posed the question of what it meant to be a natural gas supplier to ENSTAR. There was no doubt that it was challenging to supply natural gas in the Cook Inlet in current times. ENSTAR was the largest purchaser of natural gas and they had very demanding needs. Between the storage facility, Cook Inlet Natural Gas Storage Alaska (CINGSA), and their producer contracts the company needed to have the 287 MMcf of gas available in case it was needed. However, they did not need it every day. It meant producers and CINGSA needed to have significant capacity beyond the average production rates. It also meant that producers needed to have the operational capability to ramp up production and also the ability to throttle it back. Alaska was a very different world than the Lower 48. With the integrated transmission and storage network, producers in the Lower 48 could simply drill a well, open up the taps 100 percent, and the large market simply absorbed it. From a utility perspective it was a nice, easy road. Utilities had a line-up of marketers that were trying to sell them gas. In a case where a contract was not fulfilled for any reason the utility went back to their trading screen and sourced the gas from one of the 1000 other suppliers lined up to sell it to them. ENSTAR did not have that luxury in Alaska. Mr. Green explained that the market was very small and ill- liquid, with only a handful of buyers and an even smaller number of suppliers. Layer on to that the fact that Conoco was selling its assets which would take another supplier out of the market. It would also shrink the buying market with Municipal Light and Power becoming largely self- supplied. It left ENSTAR in an extremely delicate market place. He was not saying that the sky was falling. The company was in a much better place than in 2010. Mr. Green continued that ENSTAR had transitioned from a time where they were looking at shortages, the total supply, and from a deliverability perspective. He was pleased to inform the committee that in the current day ENSTAR received the Regulatory Commission of Alaska's (RCA) approval for their gas supply agreement with Hilcorp which extended through 2023. The contract was a key foundation in the company's supplier portfolio, as it provided both a significant quantity of gas and a significant level of winter deliverability. The Hilcorp contract would supply approximately 70 percent of ENSTAR's customer needs from 2018 through 2023. It had both firm and optional volumes and would supply approximately 22 Bcf per year of firm gas supply. It also offered optional volumes to help the company manage its' weather-related variability. It meant that ENSTAR could ramp-up deliveries up or down depending on customer needs - a key feature in light of their variable annual demand. Mr. Green informed committee members that one of the most important features of the contract had to do with what it did not do. It did not meet all of ENSTAR's gas supply requirements. The company had left 30 percent of their supply portfolio open for other producers to fill in. As a public utility the company valued safety and reliability above all and understood the need to have a diversified supply portfolio. It not only diversified supplier risk but also helped foster investment and drilling which was good for the long-term stability of the Cook Inlet supply. Mr. Green reiterated that the contract took ENSTAR through 2023, just beyond the short-term window. He mentioned ENSTAR's 3-year gas supply contract with Furie. The contract supplied about 20 percent, the signing of the contract was key for Furie to continue the development of its new Kitchen Lights Unit. ENSTAR wanted to see the success of the field and wanted to see it brought into production. Mr. Green thought he had fairly good visibility into the company's supply into 2021. He suggested that with the continuation of activity by Hilcorp and by Furie along with the hope of growth of the others in the Cook Inlet, he was optimistic that the company could see its supply horizon out to 2025. However, it hinged on the continued activities of current and new producers. He opined that encouragement and fostering of the environment would be necessary to keep producers engaged. He strongly believed that the utilities in the inlet had a responsibility for encouraging and fostering the environment. He noted ENSTAR's contribution - the company had provided support for Furie's development of the Kitchen Lights Unit and left 10 percent of its supply portfolio for other producers. The Regulatory Commission of Alaska had also shown its commitment to the viability of the long-term Cook Inlet gas supply with its approval of the Hilcorp contract and its narrative in the letter supporting ENSTAR's gas supply diversification approach. The commission recognized that ENSTAR's approach set aside and carved out a portion of its supply portfolio to encourage the development of small independent producers. Since 2010 the state had provided a huge support to the viability of the gas supply market in the Cook Inlet. Mr. Green acknowledged ENSTAR being cognizant of the short- term budget challenges facing the state. The company would love to see the state continue to help the encouragement of the market place in whatever form that kept it as an attractive investment. Mr. Green concluded that ENSTAR was in a -good place in the Cook Inlet at present. However, the company was sitting in a position where there was one well going into the Kitchen Lakes Unit. He emphasized that there were no production wells in Cosmo. There were 4 large fields in the inlet that were old and aging every year. With cold weather or even if one of the existing platforms or fields had an issue, ENSTAR did not have a large contingency of back-up alternatives. He furthered that there were no interties to the Lower 48 or Canada and they were 100 percent dependent in the small ill-liquid market to keep half of the state's population warm. He thanked members for their time. 7:18:12 PM Vice-Chair Micciche queried the struggles prior to FY 16, and the increase in supplies in Cook Inlet. He wanted to better understand the credits' in improving the outlook as well as the tax structure in Cook Inlet. Mr. Green replied that much of the work that had been going on was with a gas supply group. It was very much a joint project with all of the utilities together from the Cook Inlet looking for the solutions to a marketplace that was just looking for short- -term contracts. Some of the gas the company had been procuring was upwards of $23 per Mcf. The producers in the marketplace were not willing to commit to long-term contracts. ENSTAR was dancing along on a month-by-basis not knowing whether the future would come together. There were a few things that came into alignment with a lot of work. There was the significant commitment and investment made by ENSTAR's shareholders, Northern Natural, Siri, and First Alaskan. They came together for the development of the CINGSA storage facility, a key aspect in enhancing deliverability in the inlet. The first winter that CINGSA came online in 2012 was very cold. If the facility had not been in operation both ENSTAR and Chugach Electric would have had delivery shortfalls. Hilcorp coming to the market place was also a very large component as well and their commitment to getting their facilities working quickly. The consent decree contracts that were put in place secured ENSTAR's gas supply out to the first quarter of 2018. It fashioned with some of the power utilities also. It was a very real activity for the gas supply group to look at LNG imports because ENSTAR was committed making sure its customers had gas running through their meters. ENSTAR had previously been in very dire straits looking for any mechanism to get the methane molecules going through the meters. The tax credits were integral in shoring up the local market place with Hilcorp. Since then, Buccaneer (currently in bankruptcy) drilled a well. Even though the company was going bankrupt the molecules coming from their well had been uninterrupted to ENSTAR for their contract. Although there were financial challenges, the gas came through. Vice-Chair Micciche interrupted Mr. Green's testimony and requested that he provide an illustration of the history due to time constraints. Mr. Green agreed to provide that information in the form of a timeline summary. Co-Chair MacKinnon concluded the invited public testimony. SB 130 was HEARD and HELD in committee for further consideration. She reviewed the agenda for the following day.