SB 3001-OIL/GAS PROD. TAX  SB 3002-STRANDED GAS AMENDMENTS  CHAIR SEEKINS opened the hearing on SB 3001 and SB 3002, which included a presentation on access to the gas pipeline and basin control. He invited Commissioner Bill Corbus and Ms. Robynn Wilson to present SB 3001. 9:17:44 AM ^Bill Corbus, Commissioner, Department of Revenue WILLIAM A. CORBUS, Commissioner, Department of Revenue, informed members he was appearing on behalf of the administration in support of this petroleum production tax (PPT) legislation, proposed to replace the broken tax system currently based on the economic limit factor (ELF). It would provide incentives for badly needed investment; special incentives for small companies to explore Alaska; and increased revenues, especially at higher prices. He specified that the governor and his administration strongly support the PPT tax as proposed, the "20/20" - with a 20 percent tax rate and a 20 percent tax credit - and don't support a gross tax. He highlighted the need to encourage investment and resultant oil production. Commissioner Corbus said the Trans-Alaska Pipeline System (TAPS) now operates at less than 50 percent of capacity. Recent investment, development and production have been inadequate. Predicting that higher tax rates will discourage new investment, he cautioned against emphasizing short-term state revenues instead of long-term wealth. He opined that the 20/20 formula is appropriate to arrest this trend, but said although the PPT includes investment incentives, the stronger link for investment is the tax rate. He emphasized that high oil prices eventually will drop. Combined with lower production, this will mean substantially lower revenues. Commissioner Corbus closed by saying investment is attracted not by price, but by how Alaska's fiscal regime and geology compare with other opportunities around the world. 9:22:45 AM ^Robynn Wilson, Department of Revenue ROBYNN WILSON, Director, Tax Division, Department of Revenue (DOR), brought attention to a matrix comparing different tax methods under consideration: the governor's bill, Version A; the conference committee substitute (CCS) for SB 2001 from the last special session; and, for informational purposes, the versions of SB 2001 that passed the Senate and House. She noted the governor's bill maintains the same regions of the state: the Alaska North Slope (ANS); Cook Inlet, where oil and gas each still have a separate rule; and other "south" developments. Ms. Wilson said the governor continues to believe 20 percent is the appropriate tax rate for a balanced fiscal system, with a credit rate of 20 percent that she hadn't put on the matrix because it was fairly constant throughout the versions. She explained that the tax on Cook Inlet oil and gas has a ceiling and can never be above the ELF rate. In the governor's bill there is no progressivity, and credits for annual loss are at 20 percent - when a loss coming forward is converted to a credit, it is done at that tax rate. Neither is there a tax floor. Ms. Wilson reported that the CCS, by contrast, has a credit-usage floor such that capital expenditure (CAPEX) credits cannot reduce the tax below 3 percent of the gross. She referred to the line labeled "Gas (GRE)" and said it isn't applicable under the governor's bill, but remains on the matrix because it was in the version that passed the Senate. Ms. Wilson indicated the transitional investment expenditures (TIE) credit is for the last five years' capital expenditures brought forward. She pointed out that consistent with the last several versions is a two-for-one provision, maintained from the CCS. The base allowance credit, still $12 million, equates to a $60 million deduction under the governor's bill. Originally that was a deduction; throughout the matrix, therefore, Ms. Wilson said she has shown an equal amount in terms of a deduction. It depends strictly on the tax rate. The tax rate is different in the CCS version, although the credit is the same; hence the equivalent deduction is different. She noted that is also based on production, maintaining the CCS language; also maintaining that language is the new-area development credit, $500,000 a month, for areas other than Cook Inlet or the North Slope, with a 10-year rolling sunset. Oil spill language and the 10-month transition period are consistent with the CCS. Furthermore, the April 1 effective date is consistent with the last several versions. Ms. Wilson offered to answer questions on other bill sections. 9:30:00 AM SENATOR OLSON asked: If the numbers are essentially the same as previous versions, what makes the administration optimistic that this will pass? MS. WILSON opined that as more information is explored and explained, it becomes increasingly clear that 20 percent is the correct tax rate. Referring to discussion of the PPT with respect to the contract, she pointed out that in the original legislative session, the contract hadn't been made public; in the first special session, people hadn't had much time to look at it. SENATOR OLSON reported that in his travels throughout the state, he has found this less palatable to the public than when it first was proposed. SENATOR BEN STEVENS said he has found the exact opposite and believes it is a question of political opinion. CHAIR SEEKINS surmised most people are interested in trying to get gas to market. However, he characterized SB 3001 as stand- alone legislation, not part of a particular gas line project. He suggested keeping questions out of the political arena as much as possible. 9:33:46 AM SENATOR ELTON asked what the administration's objection would be to a gross tax structured to bring in an equivalent amount of revenue. MS. WILSON deferred to Mr. Dickinson to give a presentation, but opined that a net tax encourages investment, which is needed to boost production. CHAIR SEEKINS asked Mr. Dickinson what precisely is meant by a net tax or gross tax, and why the administration continues to propose a net tax. 9:35:54 AM ^Dan Dickinson, CPA, Consultant to the Governor DAN DICKINSON, CPA, Consultant to the Governor, noted he is former director of DOR's Tax Division and its Oil and Gas Audit Division. He provided a four-page document he'd prepared, "Net vs. Gross Oil Tax - Why anyone should care," dated 7/10/06, as well as a graph labeled "ANS West Coast Price & Oil Production." Mr. Dickinson pointed out whereas 2 million barrels a day once went into TAPS, the amount has declined over 18 years and now is less than 900,000 barrels a day; this trend affects jobs and revenue in the state. However, revenue has risen dramatically over the last two years because of prices. He explained that a net tax makes investment more attractive because there is a tax break for investing; for more difficult projects, with higher costs, the taxes are lower. A gross tax doesn't reflect the costs and investments necessary. SENATOR DYSON observed that one way to incentivize investment for expensive oil under a gross-tax system can be royalty relief. He asked Mr. Dickinson to provide an historical perspective in traditional oil fields worldwide and in Alaska, and to address whether it is a viable option for the producers to go through the process of petitioning for royalty relief for difficult or expensive oil production. MR. DICKINSON replied that the oil and gas production tax is the state's largest single tax. Until 2000, it was the largest source of general fund dollars; because the ELF has eaten away at it every year, however, royalties now take that position. Most places in the world have one dominant way that wealth from oil and gas resources is shared with the government - a production share, a tax without a royalty or a royalty without a tax. In Alaska, however, probably there should be both a royalty and a tax in order to provide effective incentives. Noting Ken Griffin of the Department of Natural Resources (DNR) would be there later, Mr. Dickinson said he himself didn't know about royalty relief for heavy oil in particular, but knew about royalty relief in other situations. 9:43:59 AM SENATOR DYSON related his understanding that royalty relief has worked in Cook Inlet, but the process is cumbersome and doesn't work well from the producers' perspective. He asked whether it is unduly burdensome from the state's perspective. MR. DICKINSON acknowledged he hadn't studied this issue thoroughly, but opined that when the royalty-relief process was set up, it had a fairly high standard that must be met: DNR must be able to demonstrate royalty relief will bring about the desired result. He surmised this is difficult and burdensome to meet, and deferred to someone from DNR such as Ken Griffin for further response. 9:46:16 AM SENATOR BEN STEVENS asked Dr. Pedro van Meurs whether his presentation at Centennial Hall in May had included the following: Alaska has the only regime with both royalty and severance tax, and when other regions grant royalty relief, they don't have a severance system that backs it up. 9:48:02 AM ^Dr. Pedro van Meurs, Consultant to the Governor DR. PEDRO VAN MEURS, Consultant to the Governor, affirmed that. He clarified that internationally there normally aren't severance taxes; those are a unique U.S. feature. He said a number of countries have royalty relief to make royalties more flexible, including Canada with its oil sands and Columbia and Venezuela with their heavy oils. In addition, there are sliding scales linked to production and so forth. A number have some form of royalty relief for heavy oils, long-distance gas or local wells or fields. SENATOR BEN STEVENS emphasized the complexity of the tax system in Alaska and North America. Saying there hadn't been adequate information disseminated in this regard, he surmised the public believes this system under AS 43.55 is the only tax system in place. However, there are five systems: 1) bonus bidding on the lease itself; 2) royalty, never changed on the North Slope and not proposed for change; 3) severance tax, being changed; 4) property tax; and 5) corporate income tax. He characterized it as the state holding five levers attached to the purse strings of the oil companies and yet only pulling one; he said people are concerned that the one isn't being pulled hard enough, and they forget about the other four, which offer no incentives. MR. DICKINSON thanked him for that insight, agreeing this is new information for citizen groups. CHAIR SEEKINS reported that has been his experience as well. 9:51:07 AM SENATOR STEDMAN noted many Alaskans are concerned that companies' records will be manipulated under a net-tax system and thus the taxes collected by the state will be lower than anticipated. He said the proposed tax will rely on Internal Revenue Service (IRS) regulations with respect to inclusion of allowable expenses and capital expenses. He asked whether it is correct that if the books were altered to drive apparent income down, that would likely violate federal Securities and Exchange Commission (SEC) and IRS laws and regulations. MR. DICKINSON answered that he believes, in general, there already are fairly strict criminal penalties for misreporting amounts for tax purposes. Noting companies keep separate accounts for tax and financial records purposes, he opined that Sarbanes-Oxley and the associated strictures that apply to financial accounting don't extend into the tax world. Mr. Dickinson said he would provide five reasons why the concern about being snookered is invalid, and would give a presentation to put those expenses into perspective. 9:53:40 AM MR. DICKINSON offered his first point: "Net versus gross" isn't a totally accurate depiction. Rather, the state is just substantially increasing the pool of costs that the taxpayer can deduct and which the state must then audit and check. A gross- receipts tax typically is based on what something is sold for, for example, without deductions. Under the current method, however, "gross value at the wellhead" comes from selling it in Los Angeles and deducting close to $2 billion in costs between there and the point at which it is measured. It's not a pure system with a simple number that can be looked up; billions of dollars' worth of costs are deducted under the system. Similarly, "net" typically means all costs are deducted, and yet several pages in this legislation specify costs that aren't deductible, in order to limit them to specific areas. He addressed his second point: DOR already has audited many of these costs. For example, from 1979-1981 the state had separate accounting income tax, and all these costs had to be audited by DOR. In addition, net profit share leases (NPSLs) were audited by DOR. Relating his third point, Mr. Dickinson said capital costs make up the largest portion of the costs. Having a gross tax and allowing capital credits doesn't avoid auditing, since it already is required. He discussed his fourth point: Historically, billions of dollars in the Constitutional Budget Reserve Fund (CBRF) came about as a consequence of disputes being resolved. There have been huge disputes, Mr. Dickinson told members, some relating to royalties, but primarily relating to taxes. Those issues can be grouped into two areas: valuation and costs. Elaborating on valuation issues, he recalled that during the era of price controls and no transparent spot prices announced on the markets every day, there were huge differences with respect to the value of crudes; this was in 1981-1982, but the amounts didn't go into the CBRF until 1996. He noted that experts could differ as to the value of a barrel of oil by as much as $25 a barrel. 9:58:21 AM MR. DICKINSON continued with valuation issues, saying although there still are disputes, they are about 10 cents and 15 cents, relating to premiums and deductions based on transparent spot prices. Thus that whole set of billion-dollar issues is off the table. He turned to costs, noting such issues haven't related to audits, for instance, but have been differences of opinion on transparent issues such as depreciation, return on investment or allocation of overhead. Costs weren't being hidden or manufactured. Although at one point the state alleged fraud, he said those allegations were withdrawn and no fraud was proven. Looking at the history, including the Amerada Hess case and the litigation which created the $7 billion set of settlements in the CBRF, Mr. Dickinson discounted the idea that the earlier scenario would return. He offered his fifth point: The state has an 11 percent interest rate. If a later audit finds a company has been too aggressive, the company will pay high amounts of cumulative interest on the difference. That rate was put in to try to resolve some large outstanding amounts at the time, and it specifically exists to try to keep self-reporting in line with what the state wants to see. Mr. Dickinson concluded by again disagreeing that the state will be snookered and somehow will head into murky waters that will cost billions of dollars in tax revenues, for all the aforementioned reasons. 10:00:45 AM SENATOR STEDMAN requested discussion about the whole accounting cycle of a field or particular drilling venture, and the fact that amortization and depreciation loaded on the front end are subsequently lost on the back end. MS. WILSON pointed out there are tensions - which are a good thing - for bookkeeping purposes. Any manipulation generally will be to drive up income, since companies want to present financial statements in the best possible light; there are rules, and independent accountants go in and ensure those are properly stated. The other side of the tension is for tax purposes: companies look for ways to legally take advantage of the tax code in order to show a lower income. She noted Schedule M-1 of the federal income tax return shows the book/tax differences, item by item; it typically is the first place auditors go to examine those differences between book and tax. Generally, taxable income is lower than the book income, but the question is why. It may be about depreciation, and Ms. Wilson said there are numerous legitimate differences. In the PPT, however, capital investments are written off on day one; they aren't depreciated. This is specifically to encourage investment. That book/tax difference won't be audited for PPT purposes because it isn't applicable and there was a policy consideration behind it. She deferred to Mr. Dickinson for further explanation. 10:04:56 AM SENATOR STEDMAN reiterated his desire to show the public the ramifications through the full accounting cycle when the state gives up revenue at the beginning under a net-tax system. MR. DICKINSON replied that a frequent issue is timing. There are real economic effects from being able to take a loss or receive tax benefits when the money is spent. If a producer comes in new, the IRS will say - with certain exceptions - that costs cannot be recognized until there are revenues, and the income can be lowered a little each year over the useful life of that asset. To encourage investment and the resulting economic benefits, however, the state is saying all that investment can be taken up front, which provides the "time value" of the money from the tax break at the beginning. In the out years, consequently, higher revenues will be taxable. In contrast, the IRS and SEC attempt to match the effect of the costs with the revenues derived from those costs. 10:07:46 AM MR. DICKINSON, in further response, said royalties, income taxes and property taxes would accrue as well. He emphasized making active investment more attractive through the net-tax system, particularly with dollars generated from profits within Alaska already, thus keeping the money in Alaska for reinvestment because of the tax advantage. Under a gross tax, by contrast, money earned in Alaska can be invested anywhere in the world without affecting the taxes. That is the distinction this legislation tries to address. In response to Senator Dyson, he agreed some historical problems have been solved, but said companies properly spend a lot of effort on tax-planning opportunities. SENATOR DYSON asked whether they are tax-avoidance opportunities. MR. DICKINSON pointed out that if there are rules, a company must follow those. He also indicated that if the desire is to provide incentives, a line must be straddled by the state, trying to not distort the economics but positively affect them. The vast majority of decisions that companies make are looked at and appear to make sense; the state doesn't even look at those every year. The focus is on the small number where there is a challenge. He provided details of his history working on tax issues and settlements. Mr. Dickinson observed that the areas for dispute have narrowed considerably, especially with respect to valuation. If a new set of costs is brought in, new issues will arise and the state will try to narrow those down; however, he offered his belief that those couldn't possibly rival the kinds of dollar-per-barrel issues that arose during the late 1970s and early 1980s, when there were price-control issues. He concluded by saying the answer to Senator Dyson's question was yes. 10:14:40 AM SENATOR DYSON expressed hope that the front-end credits will simplify the accounting as well as provide great incentive. He asked whether the administration has quantified and studied the range of those credits. He reported hearing that the high side of credits for the industry might approach $13 billion. MR. DICKINSON affirmed it has been quantified and studied. He pointed out that the analyses do consider the credits. While $13 billion - if that's the right number - sounds like a lot, he surmised everyone agrees it is worthwhile if it's part of the investments. SENATOR DYSON said he'd like to see the administration's numbers. MR. DICKINSON replied that if there is $1 billion in investment a year, for instance, with a 20 percent credit and 20 percent deduction, that is 40 percent or $400 million a year - about $13 billion over 30 years, which in broad strokes sounds about right. At today's prices, it would bring in over $100 billion. Interpreting Senator Dyson's concern to be that this might not work out in practice, Mr. Dickinson suggested that Dr. Pedro van Meurs speak about the frequency with which net taxes and credits for investment are used as tools internationally. 10:18:42 AM DR. VAN MEURS pointed out that Alaska already has a highly important feature that collects half the royalties, which are based on gross. The decision was made that combining two systems based on gross would be negative to an investment climate, and would hit very hard all the marginal fields, heavy oils and so forth when prices are low. Dr. van Meurs reported almost 100 nations have royalties, and most nations recognize the benefit of collecting a significant share of income from a gross feature like royalties. About 70 nations believe anything in addition to a royalty must be profit-based. If costs are high or prices are low, having two systems based on gross doesn't work effectively. He emphasized the desirability of a total package with one feature based on gross and another on net. Dr. van Meurs said the system based on gross gives protection when prices are low, providing at least a minimum amount of income no matter what, and the net feature provides benefits when prices are high. Nothing stops Alaska from asking for 20 percent royalties on new leases if prices stay high; thus Alaska is well served with a good royalty system. He related his international experience that, yes, companies might overcharge now and then or slip something in. However, that is the reason for having auditors, and Alaska is better prepared in this respect than other places using a net system. Dr. van Meurs said governments seem to reasonably collect what needs to be collected - even governments far less skilled than the State of Alaska. Thus he denied the possibility that major amounts of money could be siphoned off. Apart from that, the rules contained in the law are patterned on the best rules in the world; it isn't an open-ended system. 10:24:08 AM DR. VAN MEURS opined that all possible loopholes have been closed, including ones through which other nations sometimes lose money, and that the system can be administered well. However, he then acknowledged something always slips through the cracks, but said on balance it will be a good opportunity to create high revenues if economic conditions are favorable. Most important, the 70 nations using similar systems have concluded this formula encourages reinvestment in the same jurisdiction; otherwise, investors will naturally take their capital to where they get the deductions. He said that's why it is so important to combine the system based on gross - the royalty that will continue to serve Alaska well - with one based on net, which will serve Alaska well in the future. Dr. van Meurs indicated other options were looked at, including sliding scales for a gross tax and improvements to the ELF, even by the previous administration. For the aforementioned reasons, however, and because it is difficult to design a simple system based on gross that captures all these variables, it was decided to base this on net. SENATOR DYSON asked how well it has worked for regimes to give large investment credits on the front end, hoping to incentivize further investment and production, with greatly increased revenues resulting in the out years. DR. VAN MEURS replied that typically, in other regimes, the concept of a cash flow-based system as proposed here, rather than one based on depreciation, has worked well. Of the 70 nations he'd mentioned, the vast majority have such a system. If capital is invested, 100 percent of the deductions - plus, in this case, the credits - are taken in the year that costs are incurred. This creates an enormous incentive to reinvest; in most countries using that system, it has resulted in significant investment. Pointing out that Alaska has 5 billion barrels of heavy oil and yet remarkably low activity compared with other areas in the world, he lauded features of the proposed PPT legislation and suggested focusing on new investment, since more oil will increase revenues. 10:31:04 AM SENATOR ELTON said he understands the arguments, but asked why it is simpler to create a whole new way of doing things instead of duplicating what is being done under royalty with gross, without the ELF component. Highlighting the importance of Mr. Dickinson's graph that shows production declining and prices rising, he said it seems there could be a two-for-one clawback under gross as well as under net, which would get to the issue raised in the graph. DR. VAN MEURS agreed a simple system would be to just forget the production tax and add another 12.5 percent royalty. Venezuela did something similar in 2002; Venezuela is on tidewater, however, has costs of $2 or $3 a barrel and is near the market. In Alaska, by contract, there are light and heavy oils as well as a large distance for transportation; such a system would hit the heavy oils and smaller fields so much that nobody would be interested in them. If the price dropped, the oil industry would come back to the legislature and ask for a lower rate. Thus it wouldn't work economically in Alaska. He noted the ELF worked well for a number of years, and theoretically could be modified to be more sophisticated, formula-based system based on the gross. However, it would have many friction points such as defining what a field is or what heavy oil is. It would become so difficult to administer from a technical standpoint that it would fall apart. Dr. van Meurs indicated this is why the ELF system became broken. He offered his sense that a simple net system that automatically takes into account these variations, without having to define them or set formulas or sliding scales, is easier to administer than a sophisticated system based on gross. While an unsophisticated system like Venezuela's is easier still, Dr. van Meurs opined that it would ruin the oil industry in Alaska at prices under $40. Thus he stated his belief that the proposed PPT system is simpler than a formula-based system on gross for the production tax. 10:38:29 AM SENATOR STEDMAN highlighted the concern that as prices rise under the current system, the state's percentage declines. He said one drawback to the gross-based system is it doesn't address it without including so-called progressivity. Whatever system is instituted needs to ensure that as prices rise, the percentage either rises or stays the same, to protect the interests of the people of Alaska. CHAIR SEEKINS expressed the need to define "net" and the proposed deductions in order to address concerns among his constituents, who believe a gross-tax system is much simpler. The committee took an at-ease from 10:41:42 AM to 1:29:30 PM. MS. WILSON illustrated gross versus net through an analogy involving a construction business. The net is calculated using direct expenses associated with each home, including nails, lumber and wages; that is akin to lease expenditures in SB 3001. Once the homes are built, however, the company has expenses that cannot be tied to a particular home, including marketing expenses or contributions to the Little League. If a house is sold, a tax on gross would take the sales price times the tax rate, without deductions. A net tax - including the PPT - is calculated after the allowable deductions, which in this case would include nails, lumber and wages, but not advertisement costs or donations to the Little League. 1:33:59 PM MR. DICKINSON turned the focus to Alaska. He showed a series of slides, duplicated in a handout, that approximate what a PPT would have done in 2005. He told members the first slide, "Sale at Market," shows an outdated price of about $43 a barrel; if the 300 million barrels were sold this year for $70 a barrel, the total of $14.5 billion for North Slope oil instead would be $21 billion. This is the value of the oil in the marketplace prior to deducting any costs. Mr. Dickinson noted the slide also shows Cook Inlet oil and gas, and North Slope gas. He addressed the second slide, "Gross Value at Point of Production." Mr. Dickinson explained that this shows what is done today, subtracting the cost of transporting it to market from the North Slope or Cook Inlet; the roughly $1.7 billion is a fairly small percentage overall. Under the current method, a percentage is taken of what remains; however, what it costs to get the oil to the wellhead or to get it ready to transport isn't an allowable deduction. In response to Chair Seekins, Mr. Dickinson agreed this is as adjusted by the current ELF. He added that even though the nominal tax rate is about 15 percent, once the ELF is figured in and barrels are taken out, the amount taken would be about 7 percent of the orange area on the chart, which depicts $14.5 billion for North Slope oil. 1:37:39 PM MR. DICKINSON showed the third slide, "Net Value or Production Tax Value." He pointed out that among the deductions the producers should be allowed to take is $1.7 billion in capital costs - investments needed to continue to get oil out of the ground - and $1.1 billion in operating costs on the North Slope. While there will be an increase in the amount audited - compared with the $1.7 billion for transportation to market, discussed previously and also shown on this chart - it is a question of degree, since auditing has been required all along and people have always been required to calculate expenses. He also noted there are different companies. Some might have a lot of heavy oil in their portfolio and thus higher capital costs. Under a net system, the amount taxed would shrink; with a gross system, Mr. Dickinson said, it would be identical to someone who had production from the Prudhoe Bay reservoir at low cost and didn't have to make many more capital investments. He addressed concerns about clever schemes. Mr. Dickinson indicated a company would have to somehow show capital costs five times higher than in reality, which isn't what happens. The larger piece, $14.5 billion from North Slope oil, wouldn't be wiped out from some item in the operating costs, capital costs or transportation-to-market categories. Mr. Dickinson reiterated that the slide shows $40 a barrel; if the price were higher or lower, it would affect those amounts. Even so, the total dollars spent getting the oil up and out and to market wouldn't come anywhere near the total value. He showed the fourth slide, also labeled "Net Value or Production Tax Value," with a checkered area depicting a 22.5 percent tax. Noting the governor has suggested it should be 20 percent, Mr. Dickinson explained that this is what the state would take in production tax, simply a percentage of the $14.5 billion for North Slope oil. The remaining portion is used by a producer to pay royalties, property taxes and income taxes to the state; to pay federal taxes; to pay back any borrowed money for capital costs or investments; and to show a return to shareholders. He emphasized that a small shift in the capital cost or operating cost piece won't wipe out the tax. 1:41:52 PM MR. DICKINSON showed the fifth slide, "Tax Before Credits." He told members that had the PPT been in place, at these current values the checkered portion on the previous slide would have been $2.4 billion. He then showed the sixth slide, "Tax After Credits," which depicts tax after credits at $1.7 billion. As to whether the tax will be wiped out if someone finds a way to show larger credits, he said no. This graph shows the period of the "5,000-barrel equivalent," and has a bar labeled "5,000 bbl equivalent credit, 8 users at max of 14 million - 112 million." He said this is about the size of that credit in relation to the total taxes against which the credits are being taken. He turned to the transitional investment expenditures, depicted on the same slide as "TIE credit 1.7 x .5 x .2 - 170 million." Mr. Dickinson explained, in response to Chair Seekins, that the TIE portion of SB 3001 looks at investments made for five years prior to when the legislation comes into effect; producers are allowed to get a credit for those, provided they can match it with new dollars being spent. If a producer is in a "harvest" mode and not spending new dollars, there is no TIE. If a producer increases expenditures by about 40 percent - so they're about 140 percent of what they were - the full TIE can be claimed in the first seven years of the legislation. He noted the other piece shown is the direct qualified capital expenditure credits. Mr. Dickinson indicated the previous Senate bill had those at 25 percent, whereas the governor's bill is at 20 percent; thus that bar on the slide would be a little smaller. Mr. Dickinson made the point that if someone comes up with a different way of doing credits, it won't wipe out the entire tax burden; it is small in relation to the totals. He presented the final slide, showing information from the sixth slide - including tax after credits at $1.7 billion - as well as a new box depicting the tax under the status quo at about $0.9 billion. Mr. Dickinson pointed out that if legislators accept what the administration and a number of experts have said, this tax will create incentives for further production and investment. Whereas under the existing ELF it would collect about $0.9 billion, the system with credits and a higher rate - even with quite a bit of movement in the other categories - would still give a better result than the status quo. 1:45:00 PM MR. DICKINSON encouraged legislators to not let concerns about how to administer this overwhelm the economic considerations. If the state is helping to make investment more attractive through the tax system, he surmised more investment will happen, which is really all a net tax is doing. CHAIR SEEKINS returned to the third and fourth slides, showing $1.1 billion in operating costs and $1.7 in capital costs. He requested confirmation that these costs would be directly attributed to North Slope operations, with no way a company could use deductions from another state or nation against taxes owed under this system. MR. DICKINSON affirmed that, but pointed out that if BP had a technical problem with heavy oil on the North Slope, for example, and the best lab to resolve it was its own lab overseas, it would be charged internally against the North Slope. In further response, he indicated losses carried forward from elsewhere wouldn't affect the North Slope operation. CHAIR SEEKINS noted his constituents are concerned that deductions applied against taxes in Alaska will be company-wide expenses, such as a bonus paid to the chief executive officer. He surmised those would be deductible in terms of state income tax, but not the severance tax or whatever this will be called. 1:48:04 PM MR. DICKINSON concurred. He mentioned the structuring of the bill and pointed out that in the Prudhoe Bay Unit, BP does the check writing and hiring. However, BP only has a 26 percent interest, and so only 26 cents of every dollar actually comes from its pockets. ExxonMobil and ConocoPhillips each have something over one-third; some of their employees do nothing but look over BP's shoulder and say, "We're not going to spend this, we're not going to spend that." Mr. Dickinson suggested any bonus to Lord Browne of BP would catch their attention. Furthermore, the state could say that one test which must be passed is that the other partners must have been willing to pay for it; then the state would apply its own tests. CHAIR SEEKINS asked whether deductions for operating costs and capital costs, particularly the latter, are limited to actual dollars spent, rather than reclassification of the asset. For example, if an oil-producing well is converted to a gas well, can it be recapitalized at that point for what it would cost to install a gas-producing well? Or does it not qualify as a capital cost in terms of deductions because it already has been spent and recaptured other ways? MR. DICKINSON said it is a good question. One test in the PPT for a capital cost is whether it could have been capitalized on the federal tax return. He noted additional dollars at the time of conversion might apply, but indicated the IRS guards against arguments when companies show a series of invoices in order to prove a transaction carries weight that it perhaps shouldn't. CHAIR SEEKINS reported hearing that Federal Energy Regulatory Commission (FERC) rules might allow for rolling an already deducted asset into that process. He said there is a lot of suspicion that the State of Alaska might be gamed with respect to the PPT as well. MR. DICKINSON acknowledged this issue can arise. However, he indicated the administration isn't looking at the rules of FERC, which generally aims toward treating consumers fairly, but is looking at those of the IRS, which generally doesn't allow a deduction for depreciation more than once. CHAIR SEEKINS summarized that these two deductible expenses - capital costs and operation costs - are actual dollars spent that are directly attributable to Alaska North Slope (ANS) operations. MR. DICKINSON affirmed that as the intention, noting it is contained in several places, in several ways, in the PPT. 1:53:16 PM SENATOR HOFFMAN inquired about other North Slope fields such as the NPSLs in the Beaufort Sea; he mentioned Amerada Hess and drilling that led to discovery of the Northstar field. MR. DICKINSON said he would have to get specific information. There may be an issue about an "affiliate charge" when an affiliate comes in. Federal tax rules are looked at with respect to who is spending that money; those rules might not have been as clarified in the NPSL regulations. In general, the costs will be allowed, and the only question that arises, from the sound of it, is whether an Amerada Hess affiliate was doing the drilling and then the costs were passed through to the Amerada Hess affiliate in whose name the development account was being kept. SENATOR HOFFMAN asked whether that would be acceptable under current regulations. MR. DICKINSON answered it isn't done currently for production tax. In the income tax rules that will come in, typically the entire entity is looked at, and cross-selling between them "just cancels itself out" if it's part of the unitary group. He offered to respond further if Senator Hoffman provided more specific information. 1:55:29 PM CHAIR SEEKINS surmised a gross tax would drop some deductions and would be applied at an earlier point and different rate. MR. DICKINSON commended that observation, saying gross taxes around the world typically are at a smaller rate, since the numbers they apply to are larger. CHAIR SEEKINS asked whether expenses that would end up in these two categories - operating costs and capital costs - are already published or otherwise available to the state. He noted both BP and ConocoPhillips had published in their financial statements their "operating profits" in Alaska. MR. DICKINSON replied yes and no. Operating costs, which are immediately deductible, are deducted annually, and the state gets access to federal returns. In addition, in looking at the PPT the state has pulled together statements from the Prudhoe Bay Unit, for example, where the operator bills the owner. Each is constituted as a separate partnership, and the state looks at those partnership returns and the documents behind them. That will also include cash calls for capital expenditures. He pointed out that capital expenditures won't be seen in the IRS returns until the asset is placed in service. There will be reconciliations, but basically under the IRS rules if it takes three years to develop an asset and there isn't any productive income from it, none of it can be deducted until it is placed in service; it has to be set aside and doesn't show up as either an expense or a deduction. Mr. Dickinson said what a producer will present to the IRS as a capital expense or an operating expense won't be verifiable by the state until some years down the road. He noted another way is through financial statements. ConocoPhillips historically has broken out Alaska as a separate area, and someone can go through the "M-1 exercise" to compare financial statements with taxes. On something like operating costs, Mr. Dickinson said it isn't controversial. However, drilling expenses are treated differently under financial and tax accounting. Thus there is access to information, and if it could be provided through the PPT, it would be available all in one piece. 1:59:38 PM CHAIR SEEKINS asked if there are federal penalties for misrepresentation on a company's financial statements. MR. DICKINSON replied yes. The rules that would apply are SEC rules and civil fraud that would arise from misstating a financial accounting document. Under SEC rules, which to his belief follow financial accounting rules, a business must show whether each segment has a material effect, as it is defined; misstating that is misstating part of the financials. He indicated ExxonMobil uses the segment rules, and the Alaska piece wouldn't have a material effect on its performance; the same isn't true for ConocoPhillips. "That's why some companies do and some companies don't," he added. CHAIR SEEKINS asked whether there is access to the capital costs if there is only a single entity. MR. DICKINSON answered no, although those expenses could be found in the federal income tax return if one looked deep enough. He added that companies like to share risk, so few sole operations are found on the North Slope. Right now, BP operates two fields - Milne Point and Northstar - that are the only fields there without significant minority partners. CHAIR SEEKINS asked whether the companies' accounting of expenses would be available for the state for auditing purposes. MR. DICKINSON affirmed that, noting they'd be available directly from the IRS through cooperative agreements that the state has entered into, and through the regular course of business. He highlighted a tension that the PPT takes good advantage of: a company wants to deduct expenses immediately, classifying them as operating expenses, whereas the IRS forces capitalization of expenses that will produce benefits over a period of time, and allows incremental deductions accordingly. 2:04:24 PM CHAIR SEEKINS asked Ms. Wilson whether DOR is able to determine the amount of taxes owed under this system. MS. WILSON replied yes. She noted DOR has people with experience in auditing NPSLs and has income-tax auditors familiar with IRS provisions and tax books. She related her expectation that the information discussed by Chair Seekins, including subledgers, would be provided through course-of- business audit requests. CHAIR SEEKINS indicated the commissioner, in Fairbanks, had said a few more employees would be needed, at higher pay. 2:05:33 PM MR. DICKINSON, in response to Senator Elton, said the $1.7 billion in capital costs shown on the third slide represents dollars spent in 2005 on the leases on the North Slope and in Cook Inlet to get further development. They are deductible "as they are being made" and don't include pipeline costs or the kinds of expenditures seen for a gas line, other than the ones for the lease. He used the year 2009 as an example, as suggested by Senator Elton. Mr. Dickinson explained that if there is a gas line, there would be developments at Point Thomson. Although the billions spent there would appear on the graph, neither the gas line itself nor the gas-transmission plant would be shown. When those are operating, they would flow into the operating costs; they'd have been paid for out-of-pocket, going along. He said not much would need to be done at Prudhoe Bay with respect to capital costs. As to whether operating costs, shown in gold on the graph, would increase in 2009, he suggested 2011 would be more realistic. CHAIR SEEKINS indicated that hopefully production will increase. MR. DICKINSON pointed out that the graph shows 334 million barrels, but this year fewer than 300 million would be produced. Barring further capital investment, it is predicted to shrink even further. 2:10:43 PM ^Roger Marks, Economist, Department of Revenue ROGER MARKS, Economist, Department of Revenue, referenced a one- page document showing light oil and heavy oil under a gross system versus a net system. He explained the scenario shown, with the West Coast ANS price at $30.00, until recently considered high; shipping from Valdez to Los Angeles at $2.00; and the tax tariff at $3.00. The gross value would be $30.00 minus the shipping and tariff, $25.00 at the lease boundary. Both light oil and heavy oil are put into the pipeline and sold as a mixture at the same price, Mr. Marks explained. He pointed out that upstream costs differ, however. Mr. Marks estimated light oil would cost about $7.50 to produce, including both capital and operating costs; heavy oil would cost about $15.00, since it is much more difficult to produce. The North Slope has different classes of heavy oil, he noted, and the number could be higher or lower. Light oil under this example would have a net value of $17.50; heavy oil, $10.00. He continued with the example. If a straight 15 percent tax on gross were enacted and the ELF eliminated, it would be 15 percent of $25.00, or $3.75; this would be 37.5 percent of the net value for heavy oil, Mr. Marks noted, whereas people have been talking about a tax on net of 20 to 25 percent. Under a gross system that doesn't differentiate upstream realities, heavy oil, which needs the most help, would get the biggest "kick in the stomach" under a simple gross tax like this. CHAIR SEEKINS asked what the royalty would be at the West Coast ANS price, on average. He gave the example of $30.00. MR. MARKS replied that if this were West Sak in the Kuparuk Unit, which he believes has about a 12.5 percent royalty, it would be 12.5 percent of the gross amount of $25.00, for a total of $3.13. CHAIR SEEKINS surmised on heavy oil it would be under $7.00. MR. MARKS noted the royalty would be deductible from the severance tax, so it would be a little less. CHAIR SEEKINS suggested these numbers might be a disincentive to develop that field. MR. MARKS cautioned that merely taxing on the gross to provide simplicity ignores a very complicated problem: not all oil is created the same. 2:17:50 PM MR. MARKS turned to exploration economics, noting the main drivers are geology and exploration costs. He said the question is how the fiscal system can help to spur exploration. Because TAPS is 60 percent empty, finding new oil is important. The tax rate on oil doesn't have that big a role in exploration economics because no tax is paid if it comes up dry, which happens most of the time. There is a 100 percent chance of incurring exploration costs, but if there is only a 5 percent chance of success, the tax rate from finding oil only comes into play only 5 percent of the time. He said while the state cannot affect geology directly, it can share the dry-hole risk and thus affect costs by sharing them. Mr. Marks recalled a point made by the governor in a speech: Under the status quo, a wildcatter pays for everything if the well comes up dry. Under a PPT system where upstream costs are deductible, in contrast, the state picks up 40 percent of the dry-hole costs and incurs 40 percent of the dry-hole risk through deductions, converting losses to credits and marketing those credits. In a gross system, this is bypassed completely. He reported that an average exploration well on the North Slope costs $10 million to $20 million. If the state picks up 40 percent of $20 million, it costs $8 million. Sharing that risk can make a big difference in whether the well gets drilled, Mr. Marks said, since it materially affects the exploration economics. All it takes is to find one field like Alpine - where a $20 million exploration well found half a billion barrels, worth $30 billion - for that kind of policy to pay off enormously for the state. Mr. Marks emphasized that a gross system would bypass that risk sharing completely. CHAIR SEEKINS returned to the chart provided by Mr. Marks. He surmised the differential isn't as great at higher prices. MR. MARKS agreed. 2:22:51 PM ^Ken Griffin, Deputy Commissioner, DNR KEN GRIFFIN, Deputy Commissioner, Department of Natural Resources, offered feedback on issues raised this morning. He informed members there are a number of NPSLs on the North Slope, administered by DNR. These are a "net profit royalty" to the state, and they require an audit process similar to what is envisioned on the PPT side. Seven of these leases are in "payout," meaning the operator makes a net profit from them as defined in regulation; those seven return about $7 million a month to the state. They are audited by DNR's royalty and auditing section. He reported about 95 percent of the value audited, in general, is closed without dispute. Historically, the state and producers have successfully resolved the remaining issues. To his knowledge, Mr. Griffin said, none have been elevated to the level of the commissioner or have gone to court. There is concern about setting up PPT rules that will last a long time. These NPSL rules were set up in 1979 and 1982, are archaic and don't fit well with how the companies operate today. Nevertheless, DNR and the companies manage to resolve issues and come to a common understanding of how to interpret and apply the rules to meet the needs of the producers and the state. SENATOR DYSON asked whether statutory authority is needed to update those rules. MR. GRIFFIN affirmed that as his personal view. He reiterated it has been workable and thus isn't urgent. He noted the rules are written into the leases and thus it is a contractual relationship rather than a statutory or regulatory one. 2:28:21 PM MR. GRIFFIN addressed the relationship of royalty reduction to tax credits. He explained that the purpose of royalty-reduction regulations, as well as tax-credit provisions in the PPT, is to change a project's bottom-line economics in order to change companies' investment behavior. The goal is long-term benefits to the state by increasing exploration and production, and thus long-term revenues. The tax credits are designed to shift broad investment patterns in Alaska. There is a 6 percent decline in oil, and yet companies invest more than a billion dollars a year; to arrest this decline and monetize gas reserves, a broad- based, substantial increase in investment in oil is needed, perhaps two to three times the current amount, in addition to gas-related investments including the proposed pipeline. He contrasted that with royalty relief, a specific, project- oriented opportunity intended to provide incremental encouragement to a specific project. Mr. Griffin said the result of that royalty relief should be that a project becomes feasible, where without the relief it would not. If relief won't change the result, it isn't the right answer. SENATOR WAGONER asked: If the PPT is passed, what will guarantee that the major producers on the North Slope will use it to do more exploration? He said ExxonMobil isn't doing any exploration, for instance. MR. GRIFFIN replied there are no guarantees, but in his 25 years of industry experience he has seen significant growth in areas that have adopted tax regimes such as this. First, if a company isn't doing exploration and investing, it will have no deductions and will pay the full tax rate, which is a substantial increase over what is being paid today. Second, there isn't sole dependence on these three companies for exploration; other companies are here or want to be here, and some are the most aggressive explorers in North America. Third, the type of tax regime being talked about under PPT has been used in Norway, England and Alberta to stimulate investment in some higher-risk, higher-cost projects. He suggested the need to hear from someone with expertise on those, perhaps Dr. van Meurs or Mr. Johnston. SENATOR WAGONER questioned whether Alberta has a production tax. MR. GRIFFIN clarified that Alberta has a credit system. SENATOR WAGONER specified it's a 25 percent royalty system, with only a 1 percent royalty charged until the company recoups its costs. MR. GRIFFIN suggested that is something Alaska could do as well. SENATOR WAGONER said Alaska already has the ability to do that with its royalty for heavy oil. He indicated it has worked well for Alberta's tar sands. CHAIR SEEKINS concluded discussion of SB 3001. The committee took an at-ease from 2:35:09 PM to 2:50:53 PM. ^Presentation on access to the gas pipeline and basin control CHAIR SEEKINS informed members there would be a presentation on access to the gas pipeline and basin control, as requested during the roundtable discussions. 2:51:28 PM ^Jim Clark, Office of the Governor JIM CLARK, Chief Negotiator, Office of the Governor, informed listeners that Mr. Loeffler has been the state's attorney on oil and gas, particularly FERC matters, since 1974. He said Mr. Loeffler and Mr. Griffin of DNR are the right people to address these elements. Thus there would be an extensive presentation to assure members of what the rules of the road are, in order to help in assessing the problem. ^Bob Loeffler, Morrison and Foerster, Consultant to the Governor BOB LOEFFLER, Morrison and Foerster, Consultant to the Governor, noted when this topic came up the previous week, Chair Seekins and Senator Ben Stevens had requested that materials be made available for the record. Accordingly, he was providing: 1) FERC Orders 2005 and 2005-A, regulations governing an open season for an Alaska gas pipeline; 2) excerpts from the Energy Policy Act of 2005, which increases penalties under the Natural Gas Act and other relevant Acts from $5,000 to potentially $1 million a day; 3) a chapter describing lengthy Order 636, from a treatise entitled "Energy Law and Transactions"; 4) excerpts relating to the federal Minerals Management Service (MMS) royalty-in-kind (RIK) program and some results showing improved performance; and 5) Monday's report from FERC to Congress on progress on the Alaska natural gas pipeline, which has good projections but warns of threats to this project from the increasing role of liquefied natural gas (LNG). 2:55:37 PM MR. LOEFFLER told members he would talk about the framework for regulation of pipelines and their marketing affiliates; penalty schemes; special additional requirements that apply to an Alaska gas pipeline; and two related concepts that have gained some currency, so-called basin control and basin mastery. Following that, Mr. Griffin would provide observations gained from his experience in the industry. He gave an overview from his handout, "Access to Alaska Gas Pipeline and 'Basin Control.'" Mr. Loeffler noted an Alaska gas pipeline will be a tightly regulated, open-access pipeline, meaning capacity is available to all comers through an open season auction process. The pipeline sells "transportation tickets" and by law, since Order 636, gas must be sold as a separate product; FERC no longer regulates the price of gas, and has separated gas and the transportation on the pipeline. He explained that there are restrictions on passing advantageous information between the pipeline and the marketing affiliate, if a pipeline has one. Last year, Congress enacted heavy penalties - up to $1 million a day - in reaction to problems with Enron in California. Mr. Loeffler said FERC will review competitive issues when the open season notice comes through; when the pipeline application comes through after that; and later on. In addition, FERC has unique powers to mandate expansion of this pipeline to protect shippers, potential shippers or independents not affiliated with the pipeline. Mr. Loeffler emphasized that over its life this pipeline will be the most scrutinized pipeline in the U.S. and probably Canada. He provided some history, including that then-President Carter wanted to ban producers from equity ownership in an Alaska gas transportation system, and that Congress, by contrast, passed legislation in 2004 making the application process open to anyone, including a producer. 2:59:44 PM MR. LOEFFLER highlighted core features of Order 636 from 1992, a fundamental restructuring of the U.S. gas pipeline business. He said pipeline companies provide transportation services and don't own or sell gas, although they could have marketing affiliates. Separate companies, some affiliated and some not, sell gas. Owning a pipeline doesn't give an automatic right to capacity, or a bidding advantage; the affiliated production interest must bid in the open season to get capacity to ship gas. Similarly, owning the gas in the basin connected to the pipeline doesn't give an automatic right to capacity. Many FERC requirements for this pipeline are designed so bidders are on equal footing for the open season. Mr. Loeffler said Order 636 went to the court of appeals and was sustained in all major aspects; it has been the basis of the modern gas pipeline industry in the Lower 48 since 1992. 3:03:02 PM MR. LOEFFLER, in response to Senator Ben Stevens, explained that widely used in the industry is a "net present value" methodology that looks at the present value of a bid, including how long someone is willing to bid, and for how much capacity. The FERC open season regulations require disclosure of that methodology, by the pipeline, to all bidders. The pipeline chooses the methodology, but in the case of this particular pipeline must put out notice in advance of the open season, with a similar notice to FERC, that contains 21 kinds of information including, to his belief, the valuation methodology. SENATOR BEN STEVENS requested clarification about the meaning of "bid" in this instance. MR. LOEFFLER suggested thinking of a train, acknowledging it's a bit simplified. He said it's how many seats on the train one wants to buy, for how long. Each unit of gas is akin to a seat. In the open season notice, the pipeline also puts out its estimate of the tariff, the cost of the seat. Then an entity bids for how many seats it will buy, for how many years. In further response, he said the pipeline proposes a price consistent with FERC rate making. If the pipeline doesn't come through at this estimated price, then the deal is off and shippers usually can get out of the contract. 3:08:02 PM MR. LOEFFLER returned to his overview. With respect to the application for this certificate to build the pipeline, he said FERC reviews it to a fare-thee-well. An application is volumes, going into engineering design; permitting; size, including expandability; and proposed tariff rates. One cannot add compressor stations or even go out of the natural gas pipeline business without permission from FERC. Typically, this isn't true of an oil pipeline. Under its regulations for this gas pipeline, FERC will look at how the project design considers the capacity needs of future shippers as well as the first shippers. When the open season ends, if successful, there will be bidding for capacity. If some bidders are a bit late but have a good reason, FERC has said it will make the pipeline show why that cannot be accommodated. He characterized the open season process as the first public step, groundwork preceding an application to FERC. The pipeline tests the market, ensuring there are enough shippers that want to ship gas. Mr. Loeffler said those commitments are like leases for anchor tenants in a shopping center that can be taken to the bank to permit financing. He reported that FERC's expectation is that an Alaska gas- transportation project will be designed and built, to the extent possible, to accommodate all qualified shippers ready to sign these firm transportation (FT) agreements, since this will be the only pipeline for many years to bring gas from the North Slope. Mr. Loeffler noted that bidding methodology in the Lower 48 usually includes tie-breaking methodology; net present value is one way of deciding that. 3:12:42 PM MR. LOEFFLER gave some history and then explained that the Alaska Natural Gas Pipeline Act (ANGPA) of 2004 is a special set of provisions removing some bureaucratic hurdles and ensuring competitive access. It also provides regulations for an open season; such regulations don't exist in the Lower 48, although there is a lot of case law. For this pipeline, Congress wanted regulations that control access to the pipeline, and a level playing field for potential shippers. He continued, saying the Energy Policy Act of 2005 vastly strengthened the penalties. It also created a new section 4(a) of the Natural Gas Act, which prohibits market manipulation, covering not only jurisdictional entities, but also related activities. It makes it unlawful for any entity, directly or indirectly, to use in connection with the purchase or sale of natural gas - or the purchase or sale of related transportation services subject to FERC jurisdiction - any manipulative or deceptive device or contrivance. Mr. Loeffler referenced the SEC Act and said the commission has implemented this with a definition of fraud that he'd show members later. 3:15:02 PM MR. LOEFFLER discussed FERC orders. He informed members that the only FERC orders specific to Alaska are Orders 2005 and 2005-A; the others apply to all interstate pipelines. He characterized FERC as the "cop on the beat" at the various stages: 1) the open season notice, 2) the application to FERC resulting in a certificate, 3) pipeline construction and 4) pipeline operations. A FERC certificate typically has pages of construction conditions, and a notice-to-proceed process will be done with other federal agencies. Typical in the Lower 48 is that a deadline is established by which the pipeline must be built after the certificate is accepted. He noted Order 436 was the predecessor to Order 636, which required that any transportation offered must be nondiscriminatory. Pipeline customers that used to buy bundled service thus could contract directly with producers; this was to encourage competition. Mr. Loeffler referred to the Alberta Hub and said the whole idea of trading natural gas evolved from the separation of transportation and gas markets; that was what FERC wanted, and people quickly set up affiliates. With respect to independent pipelines, he pointed out that many have marketing affiliates that sell gas. He skipped over capacity release, turning to Order 637, which put in more stringent standards on proper conduct and scheduling, for instance, separating it into fine gradations of service. Mr. Loeffler said Order 2004 filled in the content of the standards of conduct; the idea was to not give preferential treatment to the affiliated gas marketer. Some were expressly adopted in Order 2005, but apply regardless; he gave details. Before the most recent statute, he noted, FERC could order discouragement of unjust profits and could revoke various authorities including the basic certificate of public convenience and necessity. He reported that the penalty or forfeiture provisions, however, were trivial and lacked teeth. In 2005, Mr. Loeffler said, penalties increased to $1 million a day for civil penalties and the same for criminal penalties, in addition to possible prison time of five years. 3:20:06 PM MR. LOEFFLER elaborated, pointing out that anyone who improperly manipulated transportation rights or contrived to manipulate gas sales could face huge penalties and a lot of time in jail. He said FERC would look at how the markets were harmed, what the harm was, whether the company did anything to cure it, whether it was fraudulent and whether it was a repeat offense. He highlighted improvement at FERC following what happened in California, noting FERC has become strict in enforcing even some of its simplest rules, a real change from Chairman Wood to the current chairman. He said Order 670, the latest one, implements new 4(a), on energy market manipulation, which applies if something is even connected with a jurisdictional transaction and makes it unlawful to: defraud using a device, scheme or artifice; make any untrue statement of material fact or omit a material fact; or operate or engage in any act, practice or course of business that operates as a fraud or deceit. Mr. Loeffler also emphasized the breadth of the definition of fraud: any action, transaction or conspiracy for the purpose of impairing, obstructing or defeating the honest functioning of the market. He turned to special regulations for an Alaska gas pipeline, summarized in Part IV of his handout. Mr. Loeffler said the orders themselves exceed 100 pages and are specific. For enforcing penalties, the more specific the regulation is, the easier it is to show whether a violation occurred. He indicated FERC wanted to: provide certainty for this pipeline; promote competition and prevent unduly discriminatory behavior; and prevent a project applicant from unduly favoring its affiliate. With respect to the words "undue" and "unjust," he reported that the federal statutes use those terms, as well as "unreasonable." He explained that the pipeline must construct an open season notice that complies with the 21 requirements. To put everyone on equal footing, this is given to bidders in advance so they can prepare by running economic models and so forth. Then FERC will review that, in advance of the open season, to ensure its regulations are complied with. Mr. Loeffler noted FERC reserves the right to reject the certificate application. 3:25:56 PM MR. LOEFFLER advised members that in the open season, by law, information must be provided about in-state bidding and tariffs, because interested parties must be ready to bid when the open season notice goes out. He cited 18 C.F.R. 157.34 as an important catch-all that says all information regarding the proposed service to be offered - including pipeline capacity, the proposed tariff, design and cost projections - must be available to, or in the hands of, any potential shipper prior to public notice of an open season; this is to provide equal footing. For the same reason, affiliated marketing units must be identified and are prohibited from obtaining nonpublic information. The open season during which parties can bid is open at least 90 days by regulation. Usually there is a fine- tuning period for the bids. He referred to undue preference and discrimination, saying general requirements under 18 C.F.R. 157.35 include that there shall be no preference in rates, terms, conditions of service or allocation of capacity, and that the commission shall use its fast-track procedures to resolve any complaint. In addition, (c) provides that those connected with the pipeline who conduct the open season must function independent of any other division of the project applicant. Mr. Loeffler alluded to information in his handout relating to subsections (d) through (g) of 18 C.F.R. 157.35. 3:29:30 PM MR. LOEFFLER turned to basin control, the idea that those with warehouse capacity would sign up for more "tickets" than they need, for a longer time than needed, thus excluding independents. Although there might be a business reason, it might be done to lock out a competitor. He said FERC will look for that and be suspicious if someone takes capacity for a long time while having no more resource to ship. He noted FERC has suggested it wouldn't be in the shipper's economic interest to bid for capacity beyond the projected life of its reserves. He expressed confidence that there is a big tool kit to respond to this concern. For example, FERC can force separation of the marketing affiliate from the pipeline affiliate and from the entity that conducts the open season. In addition to the special requirements for this gas pipeline he'd discussed, Mr. Loeffler indicated FERC has said it will review anti- competitive behavior - both in a letter from former Chairman Wood in response to a query from the Alaska State Legislature and "because it will do it naturally" - and will be on the lookout for unusual occurrences. He emphasized that FERC has the power to order expansion of this pipeline - which isn't true for any pipeline in the Lower 48 - if someone is excluded down the road, at a time when there is more gas to ship than there is capacity. Showing a slide labeled "Daniel Johnston Testimony on SB 305 and HB 488, April 9, 2006," Mr. Loeffler recalled Mr. Johnston's use of the term "basin master" in the context of projects around the world where there are cozy relationships between governments and project developers, for instance. Mr. Loeffler recapped points from Mr. Johnston's testimony, emphasizing that whereas Mr. Johnston had said early infrastructure corridors often are overbuilt, the concern for this current project has been the opposite, that it won't have enough capacity. He quickly addressed the appendix to his presentation, showing open season notice requirements in 18 C.F.R. 157.34. Mr. Loeffler explained that those are so detailed because the state, the legislature and the shippers wanted to know there was a fair playing field. He drew attention to item (15), specifying to Senator Ben Stevens that one requirement is disclosure of the methodology by which capacity will be awarded. Mr. Loeffler turned the presentation over to Ken Griffin, deputy commissioner of DNR. 3:35:16 PM ^Ken Griffin, Deputy Commissioner, DNR MR. GRIFFIN said he didn't have much to add, but emphasized his belief that explorer access has been dealt with effectively through this. Equal opportunity on the North Slope is maintained, largely through DNR's leasing program; that is unchanged by the proposed fiscal contract. In addition, primary lease terms, royalties and so forth remain under DNR's purview. The uniform upstream fiscal contract, proposed through separate legislation in the past session, provides "equal footing to the economic benefits of exploration," Mr. Griffin said, agreeing with Mr. Loeffler that FERC rules provide equal access to the infrastructure system through the open season process and FERC's unique expansion authority. He turned the presentation back to Mr. Loeffler. MR. LOEFFLER recalled that FERC's open season rules say, in essence, that in any expansion it will look to be sure that shippers other than for Point Thomson and Prudhoe Bay have capacity available to them. He characterized it as another check, since FERC will look at who has the gas today and who might have it in the future. 3:37:23 PM SENATOR BEN STEVENS referred to the open season notice requirements in 18 C.F.R. 157.34 in the appendix to Mr. Loeffler's presentation. He called attention to item (15), which read: (15) The methodology by which capacity will be awarded, in the case of over-subscription, clearly stating all terms that will be considered, including price and contract term. If capacity is oversubscribed and the prospective applicant does not redesign the project to accommodate all capacity requests, only capacity that has been acquired through pre- subscription or was bid in the open season on the same rates, terms, and conditions as any of the pre- subscription agreements shall be subject to allocation on a pro rata basis; no capacity acquired through the open season shall be allocated; He asked whether "applicant" in the second sentence of item (15) would be the state and the producer group. MR. LOEFFLER affirmed that, specifying it would be the pipeline LLC. SENATOR BEN STEVENS requested a definition of "pre- subscription." MR. LOEFFLER replied there was a lot of comment about whether "anchor shipper" agreements should be permitted on this pipeline. The commission struck a balance. An anchor shipper is someone willing to sign up before the open season, and there are special requirements. The competitive concern was that large North Slope producer marketing affiliates would strike deals with the pipeline prior to an open season. Mr. Loeffler indicated "pre-subscription" refers to those anchor shippers. SENATOR BEN STEVENS interpreted the language following "pre- subscription" in item (15) to mean that any pre-subscription or open season subscription is treated the same way. 3:40:29 PM MR. LOEFFLER answered by highlighting the clause "no capacity acquired through the open season shall be allocated". He explained that while FERC has said it would permit these controversial pre-subscriptions, the terms must be disclosed within 10 days of execution, and other shippers can piggyback and get the same terms. Thus someone could either bid independently in the open season or acquire those same terms on a pro-rata basis if there were a shortage of capacity. SENATOR BEN STEVENS asked: If there is over-subscription, are all subscriptions, whether pre-subscription or post- subscription, treated the same? MR. LOEFFLER said the set isn't 100 percent. While it is true that pre-subscribers can get less capacity, as is true for anyone who piggybacks, there is a third class of people who didn't piggyback and aren't "cut down." CHAIR SEEKINS surmised that someone who bids in the open season and thereby causes over-subscription isn't subject to proration. MR. LOEFFLER affirmed that. SENATOR BEN STEVENS asked: If an independent company waits until the open season and puts in a bid that causes over- subscription, that later bid isn't prorated, whereas the previous bid is? MR. LOEFFLER affirmed that as the design. He said the idea is that prior bids are potentially anti-competitive and hence should be subject to proration. 3:42:51 PM SENATOR BEN STEVENS suggested the later someone comes into the bidding process, then, the better. A person would know the rates and that there wouldn't be proration. MR. LOEFFLER responded that someone wouldn't know whether there would be over-subscription. Noting there was a qualification that he would put aside, he explained that if there are a lot of roughly equal bids, too many for the available capacity, the pre-subscribers are the ones subject to being reduced. He noted there had been an argument that pre-subscribers are entitled to equal or better treatment because of being the first to sign up; the argument against that, however, was that those would be the North Slope producers, who would have more information and shouldn't receive an advantage. Then FERC said it wouldn't prohibit pre-subscriptions, but would require disclosure within 10 days of execution, and in case of a shortage those would be the ones reduced. He said there is another catch in the clause, if the prospective applicant doesn't redesign the project to accommodate all. Mr. Loeffler added that he believes the pressure from FERC would be to ensure it could be large enough to accommodate everyone so the "cut down" situation isn't reached. 3:45:14 PM SENATOR BEN STEVENS voiced his understanding, then, that the intent is to build the project to meet capacity, but if that doesn't happen, it will be addressed such that those who make the commitment first will be prorated, as opposed to those who make a commitment at the same rates later on, with the caveat that it won't be known whether there is over-subscription. MR. LOEFFLER indicated there was a technical point he'd have to work on, relating to whether the bids would be exactly the same. SENATOR BEN STEVENS requested a written answer from Mr. Harper and Econ One to the following: Given (15), how can anybody exercise basin control? MR. LOEFFLER replied by reading the last sentence of his slide 5, a quotation from FERC Order 2005-A: "Our expectation is that an Alaska gas transportation project will be designed and built, to the extent possible, to accommodate all qualified shippers who are ready to sign firm transportation agreements." He remarked, "Hopefully, you don't get to the prorationing step." SENATOR BEN STEVENS restated his request: If Mr. Harper is hired to say how to manage basin control, perhaps he could outline something to be taken to FERC so that FERC could implement the changes on basin control, since FERC - and not the Alaska State Legislature - obviously controls the basin and the regulations surrounding access to the pipeline. CHAIR SEEKINS suggested that be looked at. He noted one question has been where FERC control begins and thus where the equal-access point begins. SENATOR BEN STEVENS also asked what level of authority the state has in basin control related to this project. CHAIR SEEKINS opined that the state has no authority, but said it could be looked at. Elaborating on the open question of where FERC control comes into play - whether for the gathering system or upstream or downstream from the gas-treatment plant - he indicated that if entities conspired to block out a competitor at the pre-subscription point, for example, he believed they would be the ones to pay the price. 3:49:29 PM MR. LOEFFLER, with respect to where FERC jurisdiction begins, clarified that all the open season orders deal with jurisdictional facilities. When Congress amended the Natural Gas Act, adding 4(a) in the Energy Policy Act of 2005, it created a new tool in the toolbox. The order bars energy market manipulation by any entity, not just jurisdictional entities, if it's in connection with a jurisdictional transaction and if there is contrivance, manipulation or fraud. SENATOR HOFFMAN asked if a producer can participate in both the pre-subscription and the open season. MR. LOEFFLER replied yes. SENATOR HOFFMAN asked whether someone could participate more than once in either one, submitting separate proposals. MR. LOEFFLER answered, "In some sense, yes." He said he was struggling with how it would operate. He surmised there could be a pre-subscription agreement for some part of the capacity, and then a bid with a different term, a longer time, for example. Mr. Loeffler recalled a practice in some Lower 48 open seasons of getting local farmers to submit artificial bids, which Enron did, but said he believed the 2005 statute would prohibit that. 3:52:38 PM REPRESENTATIVE RALPH SAMUELS, Alaska State Legislature, asked whether BP, for example, could come in with a low bid as an anchor shipper and then a high bid in the open season that couldn't be prorated. He asked why someone would want to be an anchor shipper at all. If the price was unknown and there was the possibility of proration, why not just wait? MR. LOEFFLER noted this gets into bidding theory and indicated he'd have someone else answer. He added that in the pre- regulation world, anchor shippers helped to get pipelines built; thus they got a preference. Because agreements must be disclosed and so forth, however, he wasn't sure why someone would want to be a pre-subscriber in this pipeline. CHAIR SEEKINS said he didn't know their bidding strategy either, but would be nervous about it. 3:54:28 PM SENATOR GENE THERRIAULT, Alaska State Legislature, recalled that the state, federal agencies, independents and the legislature had submitted comments to FERC during its development of this package. While he was satisfied with the results, the producers initiated litigation to get FERC to back off on issues they believed problematic; that was deemed untimely and was dismissed, and the producers came back after paring it down to one issue. He explained that a concern of his, and of the independents in Alaska, is how the contractual language may limit full application of the FERC rules detailed here. Senator Therriault indicated the independents' success, through robust exploration and unfettered access to the means to ship gas to market, would be good for the state. Noting he'd asked Mr. Harper and Mr. Shepler to attend today, he agreed with Senator Ben Stevens that it would be good to have something submitted in writing. 3:57:30 PM MR. CLARK, with regard to the contract, reported there was a recent full-day discussion at the Resource Development Council (RDC) that representatives from Anadarko and Tesoro attended. Two issues raised are relevant to Senator Therriault's concern. One involves Article 8.7, state-sponsored access for expansion, which provides opportunity for both voluntary expansion - covered in FERC regulations - and mandatory expansion, unique to the Alaska situation. Anadarko had concerns about the state- sponsored opportunity, while recognizing the intent to provide a third means of access pursuant to dispute resolution provisions of the contract. In that forum, and in other forums attended by Anadarko, Mr. Clark said no other issues were raised by Anadarko regarding this issue. He explained that, second, Tesoro was concerned about availability of access prior to the open season. Mr. Clark noted the state said several things in terms of policies to be developed, which can be found in the fiscal interest finding; these aren't in the contract because how the state uses its gas, taken in kind, is up to the state and not the producers. He indicated the state, as it develops its policies, intends to make state gas available for in-state use, which is the in-state portion Tesoro is concerned about; it also intends to assist anyone wanting to bid in that first open season in understanding the rules if there is in-state usage for which there is a separate open season under FERC. He specified that the aforementioned concerns are the two the state has heard up to this point. Mr. Clark concluded by saying, "We are aggressively addressing those concerns, and will address any others that come up as we get to the end of the public comment period." SENATOR THERRIAULT opined that Mr. Harper would bring a good perspective to the discussion, as former head of a pipeline operation, and could speak to how a company can use its influence, for example. 4:01:46 PM SENATOR BEN STEVENS returned to earlier discussion and asked Mr. Loeffler: Do the rates submitted by the pipeline in a pre- subscription period have to be approved by FERC? And if FERC does an analysis of the applied-for rate and says it isn't adequately developed, can it say to go back and change it? MR. LOEFFLER replied it's more complicated than that. The open season rates that are offered are subject to a lot of conditions, and the rates proposed with the application ought to be consistent with the successful bids in the open season. He said FERC really reviews the rates in the application, although it has the power, to his belief, under the open season regulations, to look at the proposed rates that are put in the open season notice. He added that this was untested ground, from his experience, and he wasn't sure. SENATOR BEN STEVENS clarified his point: The applied-for rates must be approved by FERC. They must be legitimate and detailed, and must meet criteria on how the rates are determined. MR. LOEFFLER affirmed that, but explained that when FERC grants an application for a new pipeline usually there is a settlement with FERC staff that requires the pipeline to come in with a rate case within three years. The Section 7 rates that are approved are "public interest" rates, rather than the "just and reasonable" rates under Section 4 or 5. As general law, FERC approves the project, grants the certificate and approves the rates initially, but the pipeline must come back with the rate case - that is the usual compromise, he said - within three years of the startup of operations, to see how experience has affected those rates. CHAIR SEEKINS surmised FERC looks to see whether those rates are in the best public interest. MR. LOEFFLER answered that it starts out "in the public interest," but "just and reasonable" is a higher standard. There is a lot of scrutiny. CHAIR SEEKINS invited Donald Shepler and Rick Harper to the witness table. 4:05:57 PM ^Donald Shepler, Greenberg Traurig, Consultant to the Legislature DONALD SHEPLER, Greenberg Traurig, LLP, Consultant to the Legislature, explained that he is an attorney from Washington, D.C., who represented the Legislative Budget and Audit Committee in the FERC proceedings that gave rise to the regulations being discussed today. Speaking in favor of addressing expansion issues in the contract, he told members that, with all due respect to Mr. Loeffler, he believed the problem to be further down the road than suggested. He proposed thinking of basin control as exercising control over this essential pipeline facility so as to disadvantage competitors in producing natural gas on the North Slope; this could include trying to drive competitors out of the business or acquiring a competitor's leases over time. After a pipeline is built, the risk is that owners will engage in practices which make it difficult to obtain access, or will delay or refuse to engage in expansion; thus in later years producers would have no place to take their production. He asked to put this in writing at a later date, as requested by Senator Ben Stevens and seconded by Senator Therriault, but offered an oral summary. Mr. Shepler agreed that in the 1970s there was a prohibition of producer ownership of any interest in the pipeline; this was waived in the 1980s, but with the condition that there be no risk of basin control by any producer-owners with a stake in the pipeline. That was under the guise of the 1977 statute. He said now, in addition to the 2004 statute, there is FERC's reaction to the January 2005 letter from Representative Ethan Berkowitz to the chairman, asking about the status of the 25- year-old prohibition and waiver; the chairman had responded that this will be addressed by FERC when it issues its orders in this proceeding. Mr. Shepler made the point that the issue of basin control, in one form or another, goes back 30 years. He agreed FERC extensively regulates the gas-pipeline business, as summarized by Mr. Loeffler, and has regulations specific to the Alaska pipeline. Mr. Shepler pointed out, however, that FERC is far away; its proceedings are expensive and time- consuming; and the final outcome is always uncertain. Therefore, he suggested the simpler fix to the risk of basin control is to address it in the contract now under negotiation. He proposed that the state negotiate firm, binding commitments with the producers that voluntary expansions will occur in commercially reasonable circumstances, in "engineeringly reasonable increments of capacity," with rates that accommodate the FERC presumption of rolled-in pricing. Thus Mr. Shepler said future explorers, in later years, would know they could gain access to the pipeline under reasonable terms, with reasonable, nondiscriminatory rates that don't put 100 percent of the burden of expanding the pipeline - once it gets to be an expensive expansion - on newcomers. He suggested dealing with this in the negotiation phase would put the state in the best position. It could take control of its own destiny, rather than relying on the vagaries of expensive and lengthy FERC proceedings where the outcome is uncertain. Although FERC is a powerful agency with extensive tools and regulations, Mr. Shepler pointed out that such a contractual provision could ensure expansion under reasonable terms through the life of the pipeline, and FERC regulations would exist as backup. He reiterated his desire to flesh this out in writing. 4:14:05 PM SENATOR BEN STEVENS suggested "future access" is perhaps a better term than "basin control" for the issue. He requested that Mr. Shepler's written comments include that the designed pipe would have cheap expansion built in. He said proven gas is only two-thirds of what is needed at 4.2 billion cubic feet (Bcf) a day, at this point. He asked to see justification for concern about future expansion above 6.0 Bcf, since there is about a 40 percent expansion capacity already. He opined that this allows for "exploration capacity" as well. He expressed appreciation for the deliberations behind FERC decisions and their longevity, but pointed out FERC was given direction by Congress in 2004, came up with two major decisions and is about ready to make a third and has submitted two reports to Congress on the Alaska natural gas pipeline. Yet legislators are still struggling through their own first decision. Senator Ben Stevens commented, "We may be the more expensive and the more uncertain body in determination of what's the outcome of this process, versus the FERC." 4:18:04 PM MR. SHEPLER responded to Senator Ben Stevens' first comment. He said during last week's conversation he was pleased to hear the project characterized as a 5.9 Bcf pipeline, starting at 4.2 but anticipated to expand to 5.9 or 6.0. He related his first reaction: If that's the intention of all the parties, then the adage "trust but verify" from former President Reagan suggests putting it in the contract. He also pointed out differences between deliverability and reserves. Mr. Shepler explained that the level of deliverability - how much gas can come out of the ground on a given day - is used to size a pipeline, but reserves are relied upon for a pipeline's longevity. The problem now is reserves. Deliverability, however, is an issue down the road as new gas wells are drilled, perhaps adding to the reserves, but adding to the gas available to flow on a day-to-day basis. He said the expansion issue doesn't need to wait for an extra 15 trillion cubic feet (Tcf) to be discovered; it can appear now, with the next well drilled. Mr. Shepler also said expandability - up to 6.0 Bcf and beyond, to the maximum capability of the pipeline - is in the long-term interest of the state, a crown jewel the state should capture to guarantee that those expansions take place. He opined that the state is probably better off fixing the problem now, in the contract, rather than relying on either the lengthy Article 8.7 process or FERC's regulatory process. ^Rick Harper, Econ One Research, Inc., Consultant to the Legislature RICK HARPER, Econ One Research, Inc., Consultant to the Legislature, agreed with Mr. Shepler and told members his own comments would preface testimony anticipated from the independents, the real voice in this issue, whom he'd talked with but wouldn't speak for. 4:22:39 PM MR. HARPER concurred with Mr. Loeffler's testimony today relating to FERC, particularly commending the job he'd done of addressing concerns relating to marketing affiliates and so forth. Mr. Harper pointed out that natural gas pipelines are contract carriers, for-profit enterprises that are granted a great deal of latitude in the operation of their businesses through FERC and state regulation. They pursue self-interests with great vigor, although there are checks and balances. He said the business model emerging here is different from what is seen elsewhere in North America; he has no quarrel with that, but it raises issues and concerns. Mr. Harper explained that pipelines must construct tariffs, rate structures and expansion policies on a case-by-case basis. Noting there is a reason companies want to own pipelines, he provided an analogy of being a member of an important committee or chairing such a committee, which gives standing and a seat at the table. He said FERC is an extremely effective body, with a rich history. But this current situation hasn't been seen before, at least not for a long time. Producers want to own a pipeline as well as subscribe to the capacity. Because they have discrete geographic positions at this time, and because others eventually will be involved and will have different positions, Mr. Harper suggested the need to be careful. While agreeing with Mr. Shepler to a great extent, Mr. Harper surmised much of their concern probably arose because the contract itself is silent in a number of key areas. He highlighted crucial elements that should be known from the start: the size of the pipeline; how much compression will be in place from the beginning; how expansions will occur, on a voluntary basis and otherwise; and that there will be an expansion-friendly system. Mr. Harper observed that nothing precludes a change in the configuration of this system. Thus it is important to know these elements from the beginning, to know initial expansions will be inexpensive and friendly to those who don't currently have a seat at the table. He listed unknown factors: the tariff, which he said could be known; the capital structure; and the debt-equity ratio, which will have a significant impact on the tariff. He explained that normally an independent pipeline company without any interest in the production doesn't have a position in consumption like ownership of power generation, and doesn't have an extensive marketing affiliate; one can presume the interests align in a certain way. However, Mr. Harper said, he doesn't come to that same conclusion about large producers such as ExxonMobil and BP. They aren't precluded from owning this pipeline, which he believes is fine. Nonetheless, their interests are different from, and broader than, those of independent pipeline companies. 4:28:21 PM MR. HARPER continued, saying one would presume it would be in their interest to have a high tariff, but they might not seek that. This agreement has gaps and doesn't reveal the tariff structure or the terms of participation in firm capacity, at least as recommended to FERC. He suggested those should be included or, if not, there should be an understanding that the risk exists for the state, and that the disadvantaged ones will be future explorers and developers. He noted there is a reason why a producer wants to be an operator in a field, getting back to his earlier analogy, and why a particular pipeline owner might want to operate the pipeline. There are distinct advantages. While that's okay, Mr. Harper recommended erring on the side of caution, putting the "belt and suspenders" in the agreement in those key areas of tariffs and expansion. He explained that relying on FERC processes can be time- consuming and cumbersome. Characterizing time as both a friend and a weapon, Mr. Harper pointed out there could be a company that discovers a new field and has 3 Tcf of gas. If there is requirement to sign up for 30 years for firm capacity, or to agree to terms that don't fit that company's business regimen - and if the company running the pipeline isn't amenable to changes - then there are remedies, yes, but they are expensive and time-consuming. Thus he indicated it would be advantageous to fill the voids in the agreement now, as mentioned by Mr. Shepler, to the extent reasonable. Mr. Harper requested the right to submit a written document to add to his comments. SENATOR THERRIAULT suggested that as a past chief executive officer of a pipeline company, Mr. Harper could provide a glimpse into how things really operate, with concrete examples. He noted there is a spirited debate going on now about who will be the operator, a position that carries advantages. 4:32:31 PM CHAIR SEEKINS observed that the government process is slow and cumbersome compared with rapid decisions possible in a small business. He offered his experience that all parties in a business relationship, even the independent companies in this situation, are motivated by self-interest, although they must operate within the boundaries of the regulatory process. He opined that the pipeline is fairly low-risk, whereas getting the gas to market carries higher risk; he surmised that balancing those is one motivation. Chair Seekins also said he understands the forces in the business process, but there is a boundary of reasonableness and regulation, which is where he sometimes has a problem. He announced he would ask someone from FERC to speak to the committee on this issue, though not because he was discounting the testimony from the FERC attorneys. Chair Seekins acknowledged the varying interests of the producers and independents, saying that is business - not bad, but sometimes tough. He highlighted the state's need to ensure that whoever finds gas has a way to get it to market so the state can tax it and get its royalty, but without somehow degrading the value of the gas before it is taxed. Chair Seekins concluded by emphasizing the need to balance these interests, expressing hope that this is what the administration is trying to do with the contract as well. MR. CLARK responded, "We are trying to balance these things up." He said it would be helpful when the written comments come in to have more specificity. With regard to looking at Article 8.7, he indicated the administration is doing that. He also noted Anadarko has raised the issue of how to get ready for the first open season, and that the administration's response is that it will provide some help. 4:38:18 PM MR. CLARK continued, saying he'd also heard today that there should be a "tariff target" in the documents, and a bit more on debt-equity structure. In addition, rolled-in rates should be covered, up to the amount of the expansion. He noted he was listing the administration's items for discussion with the producers. He said it would be helpful if that list could be expanded beyond the more general topics, because the administration is trying to find ways to address access, expansion and other highly important issues for the state. CHAIR SEEKINS remarked that he doesn't think it is wrong to ask the state to try to intervene in some of those relationships; otherwise, he himself wouldn't have been before the legislature previously asking for franchise laws to be passed to help protect him from one of the largest corporations in the world. MR. CLARK said that was the purpose of Article 8.7 in the contract. He indicated the administration had asked Anadarko how that might be changed, and he said there are a number of requirements in that article, which is designed to provide a contractual way to speed the process before FERC; it deals with some of the issues raised by Mr. Shepler and Mr. Harper. 4:39:48 PM CHAIR SEEKINS expressed hope that Anadarko would be ready to testify soon on these matters. MR. LOEFFLER added to Mr. Clark's comments, saying a number of issues such as voluntary expansion and a "capital structure target" are addressed in the LLC, which admittedly Mr. Shepler and Mr. Harper hadn't seen. He said more is coming. CHAIR SEEKINS expressed appreciation to the participants and indicated SB 3002 would be discussed specifically tomorrow. He closed the hearing, with both SB 3001 and SB 3002 held over.