SB 104-NATURAL GAS PIPELINE PROJECT  CHAIR FRENCH announced the consideration of SB 104. He relayed that the plan for the day is to bracket discussions of the constitutionality of the long term tax freeze with a presentation by Antony Scott on the broader question of whether the freeze is necessary from an economic perspective. He recapped that at the end of the last meeting, Mr. Ostrovsky drew a distinction between special legislation and general law. In his view this is general legislation rather than special legislation and because of that it is constitutionally permissible. 1:41:18 PM LARRY OSTROVSKY, Chief Assistant Attorney General, Oil, Gas & Mining Section, Department of Law (DOL), summarized that last week he gave the legal basis for the exemption, which is in Article 3 of AGIA. Because this is an unsettled legal issue, the intention was to craft a provision in AGIA that would be most likely to survive a constitutional challenge. To that end the bill is limited in scope, limited in time, and consistent with past practices of the state. "Similar, in our view, to the scope and duration to the Industrial Incentive Acts in 1949, 1957, and 1968," he stated. In a number of ways the bill deals with the fact that there is a wide variety of opinions on this subject and that the court could strike down the provision. The first is in the severability clause in Article 5, which provides that if any portion of AGIA is held invalid, the remainder is left intact. The second way is that the bill allows the process to move forward regardless of a court decision. If there is a final judicial determination on the issue by the first open season, then the participating parties will know whether or not it is constitutional. But if there is not a final judicial determination by that time, the parties would need to individually assess the likelihood of it passing constitutional muster. In any event, gas must be committed in the first binding open season to take advantage of the inducement. MR. OSTROVSKY explained that this is significantly different than the stranded gas contract, which had the entire contract balanced on this issue. Under Article 27 of the stranded gas contract, a party could terminate if any part of the contract or the authorizing act was found to be unconstitutional or unenforceable. Some legislators were concerned that under the Stranded Gas Act the process could be derailed years down the road and so AGIA takes a different approach. If there has been a determination and the state can not provide fiscal certainty, "well the bill can't provide what's not constitutionally allowed and parties have to take that into account and see where they are," he stated. If there has not been a determination, the parties will need to assess whether the court will uphold it or not. MR. OSTROVSKY said the administration believes the provision will provide a measure of certainty that is likely to pass constitutional muster. If that is not the case, the bill has been crafted such that the structure of AGIA remains intact. 1:45:30 PM CHAIR FRENCH asked him to explain how the exemption works in terms of when it comes into play, to whom it applies, and when it is used. MR. OSTROVSKY explained that a party that commits gas in the first open season is entitled to the gas production tax rate in existence at that time for the first ten years that gas flows. If the gas tax rate goes up, the party receives a credit for the difference. CHAIR FRENCH asked if the time between the first open season and the first flow of gas would be a span of 6 or 7 years. MR. OSTROVSKY deferred to Mr. Scott. ANTONY SCOTT, Commercial Section, Division of Oil & Gas, Department of Natural Resources, agreed with the estimate and said potentially it could take 8 years. CHAIR FRENCH asked if the idea is to take the gas tax that is set on the day of the first successful open season, hold it for 5-7 years until gas starts flowing, and then hold it for an another 10 years. MR. SCOTT said that's correct. CHAIR FRENCH asked if gas taxes could be raised between the open season and the flow of gas and apply to everybody including the party that eventually gets the exemption. But then the exemption would go into effect when the first gas begins to flow. MR. OSTROVSKY added that the exemption is limited to the gas that is nominated at that first open season. CHAIR FRENCH clearly stated that for all intents and purposes the state is not raising any money through gas taxes now. MR. SCOTT acknowledged that North Slope gas taxes are extremely limited at this time. CHAIR FRENCH said he wants everyone to understand that this does not foreclose a huge revenue stream to which the state might otherwise have access. SENATOR THERRIAULT asked if you really give anything up during the construction phase if the taxes are frozen on gas that isn't flowing to market anyway. Since it's tied to the gas that was proposed to flow in the pipe that is being constructed, then nothing has really been relinquished for that period of time. "You're right to point out that taxes on other gas can go up during that period, if in fact it is flowing to market," he stated. SENATOR HUGGINS said but taxes have been frozen for some players for some gas for up to 18 years under Mr. Scott's scenario. MR. SCOTT restated and agreed. "You have frozen your ability to change the gas that would flow in the pipeline." SENATOR WIELECHOWSKI asked if any other state constitutions have a similar no surrender taxation provision. MR. OSTROVSKY relayed that many states have a similar provision, but the most common model is one that the National Municipal League proposed to Alaska. SENATOR WIELECHOWSKI clarified he is interested in how other state supreme courts or federal district courts have interpreted no surrender provisions. MR. OSTROVSKY said it's pretty clear if it says "the power of taxation shall never be surrendered nor suspended or contracted away." SENATOR WIELECHOWSKI asked if any comparable constitutions have an exception clause that is similar to Alaska's. MR. OSTROVSKY said most of the case law does not support a contract. There are a few exceptions, and the North Carolina case is an example that has been cited. 1:51:09 PM SENATOR McGUIRE said she has three points. First, a matrix showing what other states do would be a helpful comparative analysis. Second, she asked if the bill has a severability clause and Mr. Ostrovsky responded in the affirmative. The third point relates to inducements as part of the package and she questioned why freezing rates would be the kind of inducement that is necessary. MR. OSTROVSKY advised that the entire 9-10 volume file that the Department of Law has on the issue of fiscal certainty is across the street and available for the legislative review. A survey of all 50 states is included, he stated. CHAIR FRENCH said he would take advantage of Senator McGuire's last question to segue to Mr. Antony Scott who would talk about the fiscal reasons for the tax freeze and the degree to which it may or may not be necessary. 1:55:15 PM ANTONY SCOTT said he would provide some context in terms of the question of whether the tax freeze is necessary. We think in terms of the bill it is necessary. We think fiscal certainty of the sort that we are proposing certainly helps improve the bill as a commercially viable vehicle to get this project moving. As to whether we believe fiscal certainty is absolutely necessary as an economic matter, I think the answer is probably no. But certainly reasonable people could disagree about that and what I hope to do in the presentation that follows is provide some context to allow you to evaluate that question. There are a number of building block issues that it's important to look at in terms of trying to answer, from an economic perspective, whether fiscal certainty is necessary for the producers to invest in this project. The first, of course, has to do with the degree to which the state's fiscal regime is shown a pattern of stability and or whether we have been confiscatory. There's no question that on this investment there will be a large upfront investment made - very large - and the returns are earned over a period of time and so I think there's a commercial fear on the part of the producers that once the investment is made, the state might act as an evil actor and then try to expropriate an unreasonable share of the rents off the project. One way to address whether that seems like a reasonable fear is to look at our past behavior. But another - importantly - is to look at the question of what sort of fiscal position we are likely to be in at the time of first gas. If the state were indeed in dire fiscal straits, the risk that the state would raise taxes significantly to cover its fiscal gap increases. That picture of the state's relative fiscal stability and our fiscal needs at the time of first gas, which…realistically probably at the earliest…is 2017. MR. SCOTT said he was counting on the Department of Revenue to provide some context for the foregoing question. Because Roger Marks is not on line, he said he would continue with his presentation and come back to that point later. 1:59:29 PM MR. SCOTT said he intended to have Mr. Marks also address slide 2, which shows the history of the state's effective tax rate on oil. Generally there is a downward trend with a couple of significant spikes. CHAIR FRENCH asked him to address the spike occurring around 1989. MR. SCOTT said he believes it reflects the amendment to the ELF formula. Before the change there was a strong downward trend and after the amendment there was a 2 percent increase in the state's effective tax rate. "In percentage terms that's less than 15 percent - more than 10." The chart also shows a small increase in the effective tax rate in 2003, which reflects former Governor Murkowski's aggregation decision at Prudhoe Bay. After that there is a relatively large spike reflecting the recently adopted PPT on oil. CHAIR FRENCH summarized that between 1980 and now the production tax exceeded 14 percent only three years and since about 1987 it has never gone above that. The tax increase last year resulted in a change from about 7 percent to about 12 percent, but the prediction is for it to go down. He asked why the production tax is predicted to decrease in the future. MR. SCOTT qualified that he is not a tax expert but he believes it reflects the increasing decline at Prudhoe Bay, which has a relatively high effective tax rate compared to new fields. Under PPT the state shares the costs for new fields in a considerable way-including investment tax credits. As new discoveries play a larger role, the effective tax rate for the North Slope will probably show an overall decline, he stated. SENATOR WIELECHOWSKI asked for a brief explanation of the effective tax rate. 2:03:10 PM MR. SCOTT deferred to Roger Marks "because it's not my slide and it's politically and economically an important and sensitive subject," he said. CHAIR FRENCH agreed the committee could come back to that later. MR. SCOTT showed a bar graph to demonstrate the significant size of annual firm transportation commitments that shippers make. The explanation provided says: "The total financial commitment for the producers would be around $3.4 billion per year, increasing to approximately $4 billion per year for a 20% cost overrun. A producer with one-third of shipping capacity would make a financial commitment of between $1.1 and $1.33 billion per year." MR. SCOTT explained that the figures reflect a prototypical project that assumes a 4.3 bcf/day pipeline into Alberta with project costs of $20.5 billion or $25 billion expressed in 2007 dollars. He noted that generally firm transportation commitments are made on a nominal dollar basis-they do not inflate. In economic terms, the burden is largest in the early years and then it declines over time. He highlighted the fact that shippers have expressed concern about taking out a huge shipping commitment when the state has the ability to raise taxes because that would reduce their ability to earn a reasonable rate of return. CHAIR FRENCH asked what $1.1 to $1.33 billion per year actually represents. 2:06:03 PM MR. SCOTT said one-third of the capacity on a $20 billion project purchases the shipper the right to ship gas and the responsibility to pay for it regardless of whether the gas is shipped or not. CHAIR FRENCH asked if a producer that commits will pay $1.1 billion to the pipeline company every year to have one-third of the pipeline reserved to its gas. MR. SCOTT said yes. CHAIR FRENCH added that in theory the pipeline company would use that money to move the gas. MR. SCOTT clarified that the pipeline company would use the money primarily to pay down its debt. "The vast majority of costs on a pipeline are the up-front capital costs, which are then amortized over a period of time." CHAIR FRENCH asked what might be the worst thing that could happen to that $1.1 billion payment. MR. SCOTT said if for whatever reason the pipeline isn't completed, the pipeline company bears the risk and so the shipper's risk never comes due. Another possibility might involve a force majeure event [major disaster] of some sort making it impossible for the pipeline to operate for some period of time. If the pipeline company and the shippers are separate entities, there will be a distribution of the risk, but quite often the pipeline company bears force majeure risk. Unplanned pipeline maintenance needs is yet another type of risk that is typically shared, but most of the time the pipeline company bears a majority of that sort of risk. "And again it differs from pipeline to pipeline and the particular terms of the tariff and what has been negotiated between the parties," he stated. 2:08:55 PM MR. SCOTT said the producers typically talk about price risk, reserve risk, and fiscal risk and the slide showing the tariff in the context of revenues goes to two of those risks. He explained the following: What I show is the state's price projections. After a great deal of price modeling the state has come up with a distribution of possible future prices with some being more likely than others. The green [lower] line represents a price path where there is a 95 percent likelihood that prices will be greater than indicated. The green is not actually showing price itself, it is showing revenues from gas sales in Alberta. CHAIR FRENCH asked if that's with or without tariff. MR. SCOTT said the graph reflects gross revenue from final sales. It's not a measure of profit so it does not include the tariff. He added that he could provide measures of profit at a later date. He continued to explain that the lower line on the graph shows gross revenue resulting from a price path that is in the bottom 5 percent likelihood. That means that it is 95 percent likely that in any given year the prices will be the level shown or higher. MR. SCOTT said the graph also shows reserve risk. The projection assumes no new gas finds by the three major producers and it indicates declining revenue after about 2032. That is the result of natural field declines in Prudhoe Bay and other proven reserves. The blue [top] line represents gross revenues when it is 85 percent likely that in any given year the prices would be at the level indicated or higher. 2:11:57 PM CHAIR FRENCH, noting that Mr. Marks is now online, said the committee would continue with Mr. Scott's presentation and come back to Mr. Marks afterward. MR. SCOTT advised that the next group of slides is in response to questions from the Chair. They speak to: producer returns; the relative investment attractiveness of this project; the consequences of not having fiscal certainty; the consequences of having fiscal certainty for different periods of time; and the assumption of different tax rates. The following terms would be used: · NPV = "net present value" - The current value of future profits · IRR = "internal rate of return" - The discount rate that makes NPV = 0 · P/I = "profitability index" - [present value of cash inflows]/[present value of outflows] · NPV/Boe = "NPV per barrel oil equivalent" - Measure of how much cash flow is generated from reserves MR. SCOTT noted that last year Anthony Finizza from Econ One Research, Inc. provided an excellent discourse on the relative importance of these measures from an investment perspective. CHAIR FRENCH asked him to provide the committee members with copies. 2:14:03 PM MR. SCOTT said the next slide shows producer returns under the metrics defined above and assuming that they do not own the pipe. He clarified that NPV is measured in billions of dollars; that the different price assumptions are fictitious; and that gas prices are really highly volatile. He explained the slide as follows: It assumes for example that at a $5.50 price today, if that exact price were maintained each and every day for the next 40 years-so you had 30 years of operations under this price-and if that price then were escalating at 2 percent inflation rate each and every year-so just keeping track of inflation. Then these are the terms it would generate. CHAIR FRENCH highlighted that the numbers are for the life of the project rather than on an annual basis. MR. SCOTT concurred adding that the assumption is a 30-year project life and a 25-year commitment. 2:15:34 PM SENATOR WIELECHOWSKI asked how the rates of return compare to other large pipeline projects that have been done around the world. MR. SCOTT said he would address that in subsequent slides. He noted that he had been advised of the need to highlight the assumption that the base case cost is $20.5 million. Essentially the numbers come from Exxon's recent representation that the project is expected to cost about $30 billion into Chicago. That cost estimate is then scaled for a project that terminates in Alberta. He explained that the profitability index is basically a measure of capital efficiency, which is the NPV of cash inflow divided by cash outflow. The chart indicates that at a real price of $5.50 gas there is a profitability index (P/I) of 7.5. That means that for every dollar that a shipper spends on upstream investment to get its gas into the pipe, $7.50 is returned to the shipper in profit. MR. SCOTT clarified that in terms of upstream returns the assumption is that the producers own, build, and operate the gas treatment plant. The same would apply for Pt. Thomson. "And finally we assume that PPT is clear and that the state pays for none of the GTP through the PPT," he said. SENATOR WIELECHOWSKI asked if it also assumes the current gas tax remains at 22.5 percent. MR. SCOTT said yes. He explained that the next slide shows the same table, but it assumes a 50 percent cost increase or $30.1 billion in today's dollars. He reminded the committee that because of cost escalation, the final costs would be larger in nominal dollars. CHAIR FRENCH asked what the price of gas is now. 2:18:30 PM MR. SCOTT estimated the Henry Hub price to be about $6.50. MR. SCOTT showed the same table looking at the producer investment measures when the shippers and pipeline owners are combined. All the measures come down because of the enormous upfront investment in the pipe and the relatively low rate of return that the pipe earns. He noted that the NPV for the integrated project, including the pipeline, is significantly less than the NPV when looking at just the upstream. The example of $5.50 gas shows that for producer upstream returns the NPV is $12.1 billion, but on an integrated basis the NPV goes down [to $10.6 billion]. The reason is that when calculating the NPV at 10 percent, the weighted average cost of capital generated by the pipeline is less than that. So the pipeline returns are less than the discount rate that is used to value the pipeline profits. That is the appropriate way to look at this for unleveraged economics, which for comparative investment purposes is the right way to go about it, he said. SENATOR WIELECHOWSKI questioned why the producers would have any incentive to build the pipeline when they would get a rate of return of 17.9 percent on $5.50 gas when they could put the gas in the pipeline and receive a 60-70 percent rate of return. MR. SCOTT said there are several reasons but basically there is a dispute about how to evaluate the economics. The producers view is that making a firm transportation commitment is equivalent to investing in the project. The administration doesn't look at it that way and doesn't believe that view is borne out by accounting or tax treatment. Furthermore, based on extensive conversations with rating agencies and equity analysts it doesn't appear as though the market views it that way either. There are other reasons. It has been said that committing to go forward on this project is like walking between two buildings on a tightrope, and "The producers would prefer to walk across that tightrope on their own feet rather than on the shoulders of somebody else." Some people have stated that if a shipper makes a firm transportation commitment then it bear all the cost overrun risk. We don't believe the facts support that statement and commercial practice in gas pipelines does not bear that out, he said. The evidence simply does not support that assertion for the gas pipeline business today. "It might have been in your father's day, but it's not today," he stated. 2:24:15 PM MR. SCOTT showed a slide that presents the same data from the perspective of the state's view of the relative likelihood of prices. It shows the distribution of upstream returns on an NPV basis and the distribution of the integrated upstream and midstream returns. He noted that the tables he showed previously are deceptive in that they could lead one to believe that a $7.50 real price is as likely as a $5 real price. That isn't the case; there is a distribution of possible price paths, he said. MR. SCOTT said the next slides look at the distribution of possible internal rates of return (IRR) and the distribution of profitability rations. Noting that the integrated project is more tightly clustered, he explained that it is because the large investment, that is earning a relatively low rate of return, functions as a buffer to price swings. Generally though the economics on upstream only shows higher means and the spread is greater and farther to the right. MR. SCOTT clarified that the next slide showing the distribution of alternative investment projects comes from work that Mr. Finizza did for the legislature a year ago. The projects are indicated by the red and blue lines while the green dots reflect the current expected returns under the PPT fiscal regime. He highlighted the fact that he is showing upstream only returns whereas the large red diamonds and large blue boxes show the gasline economics on an integrated basis. If he were to show the integrated returns, they would be to the right of the measures that are shown, he said. MR. SCOTT addressed Senator Wielechowski's previous question: "Why would you choose to own the midstream entity if without owning it you have, on a comparative basis, very excellent investment measures?" The reasons relate to things such as cost control, but they raise the question about the state's role in meeting the desire for cost control. "That's just a policy question," he said. MR. SCOTT explained that the next slide shows profitability index ratios. On an upstream basis he described the Alaska project as "off the scale." The next slide looks at NPV. It shows that the effects of the PPT on gas take, particularly at Prudhoe Bay, reduced the returns on the project. The graph clearly shows that PPT moved a lot of the NPV from the producers' side of the ledger to the benefit of the state. 2:29:24 PM MR. SCOTT said the next slide shows NPV for BOE. A reason that the numbers for the project are low is because a lot of the expected production will be far in the future. He explained that NPV involves discounting future revenues, but the barrel of oil equivalent is not discounted. Because this project generates BOEs on a steady basis far into the future, the figures are relatively low. MR. SCOTT said since he talked about project economics without fiscal certainty, next he would talk about what fiscal certainty does for the project economics. He clarified this is only on gas and the assumptions are that there is no fiscal certainty and that there was a tax change at the start of the project. The tax changes are modeled at 15 percent, 30 percent, and 50 percent above the existing 22.5 percent PPT rate on gas. The 50 percent tax increase would represent a base PPT rate of almost 34 percent, he said. CHAIR FRENCH observed that that is a huge tax increase. MR. SCOTT agreed it would be very significant particularly given worldwide standards. Continuing, he pointed out that there are material affects on the change in the producers' NPV. For example, a 15 percent increase in tax on the hypothetical $5.50 real price of gas sustained for 25 years would reduce the NPV by 5.2 percent. CHAIR FRENCH asked if the starting percentage is 11.3. MR. SCOTT responded that the NPV would drop from 11.3 percent to 10.7 percent with a 15 percent increase in the PPT tax rate. CHAIR FRENCH, using $5.50 gas as an example, asked if a 50 percent increase in gas tax in the first year of commercial gas sales would reduce the NPV from 11.3 percent down to 9.3 percent. MR. SCOTT said yes. It's nearly a 17.5 percent change in producers' NPV, which is a lot. He noted that the slide puts the issue of fiscal risk in the context of price risk. "Any analyst is clear that the price risk on this project is the biggest risk that we face." But, if you were to look at a sustained difference in gas prices between $5 and $5.50, the swing would be very similar to a 50 percent tax change. CHAIR FRENCH asked Mr. Scott to restate the last point. MR. SCOTT said, "At a sustained $5 real gas price, the NPV to the producers off of this project-again the project as we've modeled it-would be $9.4 billion, which is pretty darn close to a 50 percent tax increase at $5.50 gas." MR. SCOTT said slide 18 shows similar tax changes and the resulting NPV assuming 10 years of fiscal certainty under AGIA. The assumption is that there can be no change in the tax rate for the first 10 years of gas flow. After that time the tax rate can change and the slide shows the differences in NPV associated with the changing tax rates. For example, a 50 percent tax increase would reduce the NPV from 11.3 percent to 10.5 percent, which is about a 7.1 percent change. No question about it, he said, that is a material change. 2:35:42 PM SENATOR THERRIAULT commented that if you were justifying the 10- year freeze and the court asked for the compelling reason, this is the kind of information you would provide. MR. SCOTT concurred. He said the next slide shows fiscal certainty for a five-year period. The changes in tax rates do not have as large an effect as with no fiscal certainty, but they are significantly larger than if there were fiscal certainty for ten-years. CHAIR FRENCH noted that it didn't look as though the changes are linear. MR. SCOTT agreed they aren't. The next slide assumes 15-years of fiscal stability. Under that scenario even with a 50 percent tax increase, the NPV is reduced by about 3.5 percent. No one would be happy if the tax was to increase in year 16, but we're looking at the question of whether or not to make the investment, he said. MR. SCOTT explained that "the next bunch of slides go to other investment measures-namely internal rate of return and profitability ratio" under the same scenarios. He noted that the slide showing "no fiscal certainty" gives absolute differences in the last three columns instead of the percentage change. CHAIR FRENCH used the example of $5.50 gas in the first year of production and calculated that "If taxes were increased 15 percent, the producer internal rate of return would be reduced from 57.9 percent down to 56.1 percent." MR. SCOTT agreed. SENATOR THERRIAULT asked if this assumes a 30-year life. MR. SCOTT replied the project life is 30-years, but looking at only upstream returns it assumes a 25-year contract. MR. SCOTT said that the next slide looks at 10-years of fiscal certainty, which is what is currently in the bill. He noted the absolute differences in the internal rate of return in year 11 are small. He emphasized that the internal rate of return is fine from an upstream perspective, but the reason to invest in the project would not be made on that basis because NPV is king. Profitability ratio helps in ranking which projects to invest in and when. Although the numbers here are eye-popping he cautioned not to make too much of them. Certainly, he said "my good friends in the back of the room would dispute them." 2:40:42 PM MR. SCOTT said the next slide shows internal rates of return with fiscal certainty over five-years. Again, absolute difference is reported in the last three columns. The next slide shows that after 15-years a tax increase generates essentially no increase in the internal rate of return. SENATOR THERRIAULT referenced the statement that IRR would be used to rank and compare projects, but that that is not the best way to look at a project. "Is it just because it's cash flow so far out in the future and that's what you're correcting with NPV view?" MR. SCOTT said there are a number of problems associated with an IRR measure. First, it's implicitly assumed that the proceeds of a project can be reinvested at that same rate of return, but that isn't realistic. "There are not lots of projects lying around which generate these sorts of numbers." Also, it is easy to misallocate capital if projects are ranked in terms of IRR as a way to allocate capital. "At the end of the day every firm's goal is to maximize profits as opposed to rates of return. Profits are measured in terms of net present value." If you had a limited capital budget and you were ranking projects by IRR you would generate fewer profits than if you were allocating on the basis of a profitability ratio. 2:42:50 PM SENATOR WIELECHOWSKI observed that the rates of return and NPV are staggering. Although there has been a great deal of talk about a failed open season, it seems highly unlikely if the figures are to be believed, he said. "Should we be focusing more on incentives for the midstream where there appears to be more likelihood of difficulty?" MR. SCOTT said he believes that's the administration's position and there are a number of reasons for doing that. Incentives provided on the midstream will go to all shippers, but right now equity issues related to taxes on gas are being looked at to make sure that it's fair. "If there is a problem in general with the tax rate on gas, that is something that should be revisited in the relatively near future, but not as part of this bill," he stated. 2:44:55 PM SENATOR HUGGINS commented that a case could be made that the best scenario for the state is a coalition that has the deep pockets of the producers and the expertise of the pipeline company and others because "you look at the internal rate of return, you look at the potential for running into financial difficulties and you minimize most of your risk." If the coalition builds the gas pipeline, then you have a "quasi- commitment" for the gas to put in the pipe, he said. MR. SCOTT responded that kind of coalition would be very powerful. SENATOR HUGGINS asked if that is a yes or a no. 2:46:19 PM MARTY RUTHERFORD, Deputy Commissioner, Department of Natural Resources, said what Senator Huggins is speaking to is what the administration is attempting to do within AGIA. That is to provide a balance of incentives to the various parties that will play a role in creating a successful project. To that end the administration realizes the project that's in the state's overall best interest is one that has the elements of a third- party pipeline such as mandatory expansion provisions, a reasonable tariff structure, and is created so that upstream producers have incentive to commit their gas in the earliest open season. To the degree that those two goals are accomplished, the outcome would be the same regardless of whether it is through a coalition or a single party. SENATOR HUGGINS asked if Donald Trump would view this as optimum from the state's interests. MS. RUTHERFORD said yes, AGIA protects the state's interest by inducing participation in the first binding open season. "And the resulting project will protect the overall state's interest and get it moving forward." MR. SCOTT spoke to a perceived misconception related to the financial strength of the producers. Acknowledging that the producers have tremendous strength, he suggested that it is unlikely that those parent company balance sheets will be put on the line to build this project. "The project is very likely to be financed on a project-finance basis." That means that the project attracts lending support based on promised future revenues. Although the federal government debt guarantee on the project is contingent on the completion guarantee, no one expects it to be a hell-or-high-water completion guarantee. Rather, it will be some limited recourse to the parent company. Typically that means that some measure of total cost overruns will be pledged, through negotiation between DOE and the pipeline entity with a certificate. Ultimately what provides credit for the project is the tremendous reserves in the ground and not the parent companies. "At the end of the day an independent pipeline company of the sort who you have had testify in front of you, is fully capable of handling the non- completion risk that this project would generate," he stated. 2:51:10 PM SENATOR HUGGINS asked him to highlight some of the variables that are important for success from the different perspectives. MR. SCOTT said securing firm transportation commitments is by far the most important for any midstream entity. Essentially that is the commitment of the reserves in the ground. Building and attracting without firm transportation commitments will not be possible unless there is another means of credit support like the federal government. He said the producers are best positioned to say what they need, but they have been saying they would like fiscal certainty. He couldn't speak to whether or not it is a requirement from a corporate perspective. "The producers are intensely interested in ensuring that costs of the project are adequately controlled." It they don't control construction they'll be interested in the negotiations with a midstream entity in terms of their willingness to "put skin in the game." SENATOR HUGGINS said it appears that all entities want certainty. He recalled that most pipeline companies said they wouldn't want to have an open season if it was going to fail and the producers said they needed certainty for some number of years and other variables. "We're trying to figure out how to balance this teeter-totter of certainty so that we get the requisite players to come to the table. Is that semi-accurate?" MR. SCOTT agreed that's the policy matter the legislature is wrestling with. 2:54:31 PM CHAIR FRENCH told Mr. Scott he had another 5-10 minutes to complete the presentation on whether fiscal certainty is necessary. MR. SCOTT said he would not address the slides on profitability ratio, but that they would be available to the committee. Responding to a question about the cost of delay to the state if fiscal certainty is found to be unconstitutional, he showed a slide titled "Cost of delay to state - Discounted at 5 percent per year." The explanation states that "AGIA [is] designed to ensure that litigation over fiscal certainty does not delay [the] project." CHAIR FRENCH noted that at $5.50 gas, the cost of delay to the state would be $1.8 billion for 1 year, $3.5 billion for two years and $5.1 billion for three years. MR. SCOTT agreed. The next slide indicates how quickly TAPS paid off. He noted the misprint, which says 13 years. How quickly TAPS tariffs paid for the pipeline depends on determinations of appropriate rates of return, capital structure and other variables. When the Regulatory Commission of Alaska (RCA) looked at this in the context of a litigated rate case it determined that TAPS was paid off fully by 1989. It went into service in 1977 so it took between 12 and 13 years. The final slide lists the project assumptions that underlie the economics unless otherwise noted on the individual slides. Those include: · 4.3 bcf/day to Alberta · $20.5 billion base case cost ($2007) · 70/30 debt to equity, 14 percent ROE · Current PPT tax structure (no GTP credit) · Oil impacts of gas production included · 30 year project life · 25 year FT commitments · Gas flow 2016-2046 · Oil price of $36.50 fixed real for project life · $ values increase at 2 percent/year MR. SCOTT said Mr. Marks would go through the remaining questions. CHAIR FRENCH found that Mr. Marks was not available online. He announced that the committee would next hear from Mr. Bullock who would present some of the opposite case with respect to the constitutionality of a long-term tax freeze. 2:57:33 PM DON BULLOCK, Attorney, Legislative Legal and Research Services Division, Legislative Affairs Agency, introduced himself. CHAIR FRENCH asked if the long-term tax freeze envisioned by the AGIA bill is constitutional. MR. BULLOCK opined that making the tax freeze a matter of contract makes it unconstitutional. On the other hand, he believes the original version that identified a period of 10- years would survive constitutional scrutiny in that it would be enacted by general law and would be subject to repeal by the legislature. It does not raise any issues under Article 1, Section 15, which prohibits the passage of any law that impairs the obligation of a contract, he stated. SENATOR THERRIAULT asked if he said that the original structure would survive. MR. BULLOCK said yes, and the PPT actually repealed a similar provision that was in the severance tax. Under 43.55.011(a) and (b), for the first five-years of new production that came on line after June 30, 1981, the applicable production tax rate was 12.25 percent and then it went up to 15 percent. That is similar to the proposal in the governor's original bill, which was to hold the level of the tax for a ten-year period. CHAIR FRENCH asked what happens if the tax rate changed during that ten-year period. MR. BULLOCK explained that the constitution is written to provide the legislature maximum flexibility in fiscal matters. Article 9, Section 1 says: The power of taxation shall never be surrendered. This power shall not be suspended or contracted away, except as provided in this article. CHAIR FRENCH asked for an explanation for that being in the constitution. 3:00:03 PM MR. BULLOCK explained that the provision is there so that the legislature has flexibility to raise revenue for the state when unforeseeable crises arise. Such events include: the Fairbanks flood in 1967, the earthquake in 1964, the TAPS delay that resulted in a special session in October 1973, and the imposition of the reserves tax in 1975 when the state needed money to cover expenses until TAPS was completed and oil could be produced. MR. BULLOCK continued to say that this is similar to the prohibition against dedicated funds that is also in Article 9. The idea is to not lock up funds. "Conceivably at some point you could have so many dedicated funds that you would be scrambling for money to keep the lights on." MR. BULLOCK pointed out that tax credits were historically in the statutes. For example AS 43.26.020, which was repealed in 1986, granted a tax credit. It said that "A grant of tax credit under this chapter shall be considered a contract between the grantee and the state." He clarified that it was a credit and not an exemption, but the issue has never been tested in the supreme court. Three supreme court decisions related to that tax credit but none of them dealt with the issue of whether it was something in violation of Article 9, Sections 1 and 4. 3:01:52 PM SENATOR THERRIAULT asked if he was talking about the original language in the governor's bill versus the current committee substitute (CS) [25-GS1060\K]. MR. BULLOCK provided the following explanation: As the bill was introduced it was a matter of general law, there was no contract language. It was presented, I think, in terms that it would amount to a contract, but it's not a contract. It was just a matter of general law. The CS that you have before you says in the opening paragraph providing for the opening section, providing for the inducements that it's contractual. And as far as the tax inducement goes, it provides for a credit certificate or exemption certificate that would be issued by the commissioner of revenue. And it directs that that use contract language and that it does amount to a contract between the state and the person receiving the inducement. SENATOR THERRIAULT asked if he had issued a caution as he worked with legislators to draft that particular language. "Did you write a memo as we quite often get?" MR. BULLOCK said he couldn't say who he cautioned about that. But "if you gave it to me and asked me to write it, I would caution you that it raises serious constitutional issues," he stated. SENATOR THERRIAULT asked the Chair if the committee could ask for a memo comparing the original language to the language in the current CS. CHAIR FRENCH said that seems wise and he would make that request. 3:04:03 PM CHAIR FRENCH asked Mr. Bullock if he would return at 5:30 pm to continue to address the constitutional issue. After receiving an affirmative answer, he recessed the committee until 5:30 pm.