ALASKA STATE LEGISLATURE  HOUSE SPECIAL COMMITTEE ON OIL AND GAS  October 23, 2007 9:02 a.m. MEMBERS PRESENT Representative Kurt Olson, Chair Representative Nancy Dahlstrom Representative Mark Neuman Representative Jay Ramras Representative Ralph Samuels Representative Mike Doogan Representative Scott Kawasaki MEMBERS ABSENT  All members present OTHER LEGISLATORS PRESENT Representative Bob Buch Representative John Coghill Representative Bryce Edgmon Representative Anna Fairclough Representative John Harris Representative Lindsey Holmes Representative Craig Johnson Representative Mike Kelly Representative Beth Kerttula Representative Bob Roses Representative Paul Seaton Representative Peggy Wilson COMMITTEE CALENDAR  HOUSE BILL NO. 2001 "An Act relating to the production tax on oil and gas and to conservation surcharges on oil; relating to the issuance of advisory bulletins and the disclosure of certain information relating to the production tax and the sharing between agencies of certain information relating to the production tax and to oil and gas or gas only leases; amending the State Personnel Act to place in the exempt service certain state oil and gas auditors and their immediate supervisors; establishing an oil and gas tax credit fund and authorizing payment from that fund; providing for retroactive application of certain statutory and regulatory provisions relating to the production tax on oil and gas and conservation surcharges on oil; making conforming amendments; and providing for an effective date." - HEARD AND HELD PREVIOUS COMMITTEE ACTION  BILL: HB2001 SHORT TITLE: OIL & GAS TAX AMENDMENTS SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 10/18/07 (H) READ THE FIRST TIME - REFERRALS 10/18/07 (H) O&G, RES, FIN 10/19/07 (H) O&G AT 1:30 PM HOUSE FINANCE 519 10/19/07 (H) Heard & Held 10/19/07 (H) MINUTE(O&G) 10/20/07 (H) O&G AT 12:00 AM HOUSE FINANCE 519 10/20/07 (H) Heard & Held 10/20/07 (H) MINUTE(O&G) 10/21/07 (H) O&G AT 1:00 PM HOUSE FINANCE 519 10/21/07 (H) Heard & Held 10/21/07 (H) MINUTE(O&G) 10/22/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519 10/22/07 (H) Heard & Held 10/22/07 (H) MINUTE(O&G) 10/23/07 (H) O&G AT 9:00 AM HOUSE FINANCE 519 WITNESS REGISTER MARILYN CROCKETT, Executive Director Alaska Oil and Gas Association (AOGA) Anchorage, Alaska POSITION STATEMENT: Presented information from AOGA during the hearing on HB 2001. CRAIG HAYMES, Production Manager - Alaska ExxonMobil Corporation Anchorage, Alaska POSITION STATEMENT: Presented information from ExxonMobil Corporation during the hearing on HB 2001. JOHN P. ZAGER, General Manager, Alaska Chevron (No address provided) POSITION STATEMENT: Presented information from Chevron during the hearing on HB 2001. PAT FOLEY, Manager Lands and External Affairs Pioneer Natural Resources Alaska, Inc. ("Pioneer") (No address provided) POSITION STATEMENT: Offered an outline of the presentation from Pioneer during the hearing on HB 2001. KEN SHEFFIELD, President Pioneer Natural Resources Alaska, Inc. ("Pioneer") (No address provided) POSITION STATEMENT: Presented information from Pioneer during the hearing on HB 2001. MARK HANLEY, Public Affairs Manager Anadarko Petroleum Corporation in Alaska (APC) (No address provided) POSITION STATEMENT: Presented information from APC during the hearing on HB 2001. DAN E. DICKINSON, Certified Public Accountant (CPA) Anchorage, Alaska POSITION STATEMENT: Presented information on behalf of the Legislative Budget and Audit Committee during the hearing on HB 2001. ACTION NARRATIVE CHAIR KURT OLSON called the House Special Committee on Oil and Gas meeting to order at 9:02:48 AM. Representatives Olson, Neuman, Kawasaki, Samuels, Ramras, and Doogan were present at the call to order. Representative Dahlstrom arrived as the meeting was in progress. Also in attendance were Representatives Buch, Coghill, Edgmon, Fairclough, Harris, Holmes, Johnson, Kelly, Kerttula, Roses, Seaton, and Wilson. HB2001-OIL & GAS TAX AMENDMENTS 9:02:58 AM CHAIR OLSON announced that the first order of business would be HOUSE BILL NO. 2001, "An Act relating to the production tax on oil and gas and to conservation surcharges on oil; relating to the issuance of advisory bulletins and the disclosure of certain information relating to the production tax and the sharing between agencies of certain information relating to the production tax and to oil and gas or gas only leases; amending the State Personnel Act to place in the exempt service certain state oil and gas auditors and their immediate supervisors; establishing an oil and gas tax credit fund and authorizing payment from that fund; providing for retroactive application of certain statutory and regulatory provisions relating to the production tax on oil and gas and conservation surcharges on oil; making conforming amendments; and providing for an effective date." MARILYN CROCKETT, Executive Director, Alaska Oil and Gas Association (AOGA), paraphrased from the beginning of a 19-page prepared statement [the corresponding charts and graphs for which are available in the committee packet], which read as follows [original punctuation provided, with some formatting changed: Mr. Chairman and Members of the Committee. Thank you for the opportunity to testify before you today on Senate Bill 2001. My name is Marilyn Crockett and I am the Executive Director of the Alaska Oil and Gas Association ("AOGA"). AOGA is the trade association for the oil and gas industry in Alaska. Our 17 members account for the majority of oil and gas exploration, development, production, transportation, refining and marketing activities in the state. In addition to Alaska's instate refiners, Agrium and Alyeska, our membership includes companies new to Alaska hoping for the opportunity to explore, companies which are exploring today but do not yet have production (but hope to in the future) and those companies which are producing today. One of the important functions the Association performs is to provide a forum for member companies to consider regulatory and legislative proposals, and to reach agreement on an industry position on those proposals. To establish an AOGA position, a 5/6 vote of the members is required. What this means, of course, is that when AOGA voices that position, regulators and legislators can be assured that that position is the position of the overwhelming majority of Alaska's oil and gas industry. But on tax issues, AOGA members have taken this approval process to the highest level. AOGA positions on tax-related issues require 100% consensus of the AOGA Members. Let me be clear: my testimony today reflects the full consensus of the members of the AOGA Tax Committee, with no dissent. The focus of our testimony today will be on the practical impact of declining production levels on industry operations and the State of Alaska. And while we are not in a position at this early date in this Special Session to provide you with a complete analysis of the many components of SB 2001, we will describe for you but a few of the troubling aspects of this legislation. The AOGA Tax Committee is in the midst of a comprehensive review of the legislation and will be in a position at a future date to characterize those concerns. Here we are in Juneau for the fourth time in the past two years to deliberate whether one of the State's taxes on oil and gas should be changed, and if so, what it should be changed to. Last year the Legislature passed the Petroleum Production Tax, or PPT. Now, less than a year later, the Administration is telling you that the PPT is broken. They say it's too complicated to forecast, it isn't bringing in the revenue that was forecast last year, and they don't have enough capable auditors to enforce it. In discussing the merits of SB 2001 versus PPT and the Administration's concerns, we must always keep in mind the real-world situation that Alaska faces. The greatest challenge that confronts this generation of Alaskans and the next is the ongoing decline of oil production, which has been, is today, and promises to remain the cornerstone of the finances of state government. Production decline is eroding this cornerstone. It is a historical fact that even with the massive investments being made, North Slope production declined an average of 6.2% a year from FY 1997 to FY 2007, and Cook Inlet oil production declined at 8.0% a year. Without those investments, decline would have been 15%. With respect to the future of the North Slope, there is going to be a major challenge when ANS production gets down to about 300,000 barrels a day. According to Alyeska Pipeline Service Company, which operates the trans-Alaska oil pipeline (TAPS), the minimum mechanical capacity of the new electronic pumps that are being installed is about 300,000 barrels a day. 9:07:21 AM MS. CROCKETT paraphrased from the next portion of the statement, which read as follows [original punctuation provided]: Here is a graph showing how long we have before ANS production reaches this 300,000 barrel-a-day mechanical threshold, depending on what the rate of decline is. If decline continues at the historical rate of 6%, ANS will decline to 300,000 barrels a day in about 15 years, or FY 2022. On the other hand, if decline can be held to 3% or less as DOR assumes, then we would have 30 years or so before we hit the mechanical threshold. Let me stress that this graph is not a prediction. It merely plots the results of the mathematical calculations of how long it would take to get to 300,000 barrels a day from the level of 740,000 barrels a day in FY 2007, depending on what decline rate you choose. What it does show is how important the rate of production decline is for Alaska's future. The difference between a 6% decline rate and 3% doesn't sound like much, but as you can see from the graph, that difference determines whether the 300,000 barrier is reached around FY 2022 or FY 2037. If you have a child in junior high school, this represents the difference between that child being able to grow up and have a career on the North Slope, and not having this opportunity. Investment in new production is the only way to slow the decline enough to give the children of this state a future with the North Slope similar to what we have enjoyed. That's why new investment is such a crucial question facing the State, both in the context of the proposed tax proposal and in other areas that affect the business climate here. There are three categories of investment that can slow the rate of decline on the North Slope, or at least keep it from getting any worse. These are, first, investment in exploration to discover new fields; second, investment in existing fields to prevent their decline from accelerating; and third, investment in innovation, technology, and new infrastructure to allow development of the vast but challenging resource of heavy and viscous oil that has already been discovered. A great deal of the testimony to the Legislature, and a lot of the questions being asked, have focused on the fiscal terms of the "government take" for exploring in Alaska and the competitiveness of these terms relative to the terms in regimes elsewhere in the world. This kind of "who takes more" analysis is faulty for two fundamental reasons. First, it assumes that the geologic prospects for making a commercial discovery in Alaska are comparable to those other regimes. This assumption is unsound. The North Slope has three major areas of significant oil and gas potential: the state lands in the central North Slope between the Colville and Canning rivers, the federal land in the National Petroleum Reserve - Alaska to the west of the state lands, and the coastal plain of ANWR to the east of the state lands. The exploration potential of the state lands is limited today primarily to the discovery of new satellite fields, as opposed to fields large enough to stand on their own economically. Exploration is still active in NPR-A and by no means over, but the courts have recently blocked federal leasing of the geologically promising lands around Teshekpuk Lake. And even if the Ninth Circuit decides to let that leasing go forward, the pro-leasing Bush Administration has less than 14 months left in office in which to hold the lease sale. Elsewhere in NPR-A, the relinquishment earlier this fall of some 300,000 acres of lands reflects disappointing results from leaseholder exploration efforts there. As for ANWR, despite Republican majorities in both houses of Congress and a pro-development president in the White House, the coastal plain is still closed. 9:10:35 AM MS. CROCKETT continued reading from page four of the handout: And this brings me to the second reason why it is unwise to focus too much on investment in exploration as the solution to production decline. Exploration is a risky business, and there is no assurance that spending money to test a particular prospect will ever yield a dime of payback. Even when exploration succeeds in discovering a commercially viable field, it will take years from the time of its discovery until the time production from it begins. But the challenge of declining production confronts Alaska today - not eight, ten or a dozen years from now. By its nature, investing in exploration can make a significant contribution toward solving the challenge of declining production in the longer term, but not the shorter term when results are urgently needed. Investment in heavy and viscous oil development is also a solution in the mid to long term. The first well ever drilled to test production from the Ugnu Formation was only drilled earlier this year in the Milne Point Unit, and it is still being tested and evaluated to gain a better understanding of the physical characteristics of the Ugnu oil. There are plans to use the results of these tests and evaluations to plan and develop a pilot project for producing Ugnu oil. Until then, West Sak will continue to be the only commercial heavy/viscous opportunity. This gets us to investment in currently producing fields. Fortunately, there are investments that can be made, and are being made, in these fields to slow their decline. In the short term, this is in-fill drilling - that is, drilling new wells into the portions of a reservoir that are between the wells that have already been drilled. This accelerates the drainage of oil from the rock that currently lies in between existing wells. In-fill drilling last year contributed some 70,000 barrels a day to production from the Prudhoe Bay field. To put this into perspective, a 70,000 barrel per day field would be th the 4 largest stand-alone field on the North Slope today. There are also major investments being made, and yet to be made, in "renewal" of the surface facilities for existing fields. For instance, the gathering centers and flow stations for the Prudhoe Bay field have been in service for over 30 years now. For them the situation is not all that different from what yours would be if you bought a minivan van years ago when your children were young, and now that the kids are all grown up and it's just you and your spouse who are driving it, it's time to replace that minivan with a new vehicle that suits your needs better. If Prudhoe Bay and the other producing fields are to continue producing in the decades to come, their original production facilities will need to be overhauled or replaced. Also, as increasing amounts of heavy and viscous oil come into production, even relatively new facilities that were designed for comparatively light "conventional" oil will probably need to be modified, refitted or replaced in order to minimize operating problems in handling that heavy/- viscous oil. Regardless of the stimulus or purpose for making them, renewal investments in production infrastructure present a very similar cash-flow pattern as there is for investments in the original infrastructure to develop a field. And consequently, an incentive that is effective for the initial development infrastructure is equally effective for renewal as well. 9:14:02 AM MS. CROCKETT continued: So, this is the harsh reality in which we - government, industry, the present generation of Alaskans, and the next one - find ourselves. For all of us, decline is the great challenge that we must grapple with. It already threatens us now, and if unaddressed, will only get worse. Massive new investments for additional oil production are the only way to deal with this menace, and there are three areas of investment that can be made to deal with it: exploration, heavy and viscous oil development, and slowing decline of existing fields. The first two are of greatest benefit for the long term, and the other one is of great benefit for the near term. We need all three kinds of investment and don't have the luxury of ignoring one or two of them. I have explained our collective situation in such detail so we can each see for ourselves why declining production is the great issue of the day for Alaska. Turning now to the relative merits of SB 2001 versus PPT, AOGA submits there are several self- evident principles of taxation that should be used to test those merits. First, a tax must be "fit for purpose" - that is, it must do the things it is intended to do, and it should do them well. Second, the administration and enforcement of a tax should be as efficient as possible, consistent with ensuring compliance by taxpayers. Third, for a taxpayer who wants to calculate and pay the correct amount of tax when it comes due, it must be possible to do so. Regarding the first test - achieving what the tax is supposed to achieve - most new taxes have as their primary or only purpose the new revenues that they will bring in for the government. In the case of PPT, however, things were not so simple. In part its purpose certainly was revenue-related, because most legislators viewed the prior [economic limit factor (ELF)]-based production tax as outdated and unduly generous to producers in terms of the reduction in tax rate that the ELF caused. But, as Pedro van Meurs explained repeatedly in his testimony last year and again at the beginning of this special session, the PPT was also designed to provide incentives for investing in production and in that way answering the threat of declining production. With respect to the revenue side, no one disputes that PPT has brought the State more tax revenue since April last year than ELF would have. According to DOR, the increase was more than $800 million in the last nine months of 2006, and at that rate it would have been over a billion dollars in additional production tax revenue for a full year. DOR also said st at the time that the March 31 payments were about $137 million less than the $950 million that it had estimated, and in due course I'll come back to the questions of forecasting the PPT and higher-than- forecasted lease expenditures. For now, my point is that PPT has certainly outperformed the old ELF tax, which is just what it is supposed to do. As a consequence of the fact that field costs are higher than DOR predicted last year, this Administration criticizes PPT for failing to generate all the tax revenues that the fiscal note for HB 3001 predicted. It has even been suggested that Alaskans were somehow promised that PPT would generate $800 million more this year than is now being projected, and that it is therefore necessary to raise the tax rate in order to make good on that promise. That whole line of reasoning is flawed. First of all, DOR is complaining that they can't forecast PPT accurately because it has so many variables that affect the results. However, if they can't forecast it accurately, then why should so much reliance be placed on its current forecast that shows the prior forecast was off by $800 million? If the first forecast was poor, what has changed to make this latest one so good? 9:17:30 AM MS. CROCKETT continued as follows: As I explained just a while ago, the purpose of PPT was more than just the tax revenues it would generate. It was to create incentives for attracting the massive new investments that will be needed in order to meet the threat posed by declining production. The system of tax credits under PPT provides significant incentives for investing in capital assets to explore for, develop, and produce more oil and gas. ƒCurrent capital expenditures generate a 20% tax credit in addition to being immediately deductible as lease expenditures. For the kinds of economic analysis that reflect the time-value of money, these front-end benefits have the greatest possible positive effects on the results of the analysis. ƒThe incentive to invest sooner rather than later is materially increased by the fact that the "transitional investment expenditure" or "TIE" credit for pre-PPT capital investments can only be taken to the extent those prior expenditures are matched two for one by new capital expenditures, and taxpayers have only until the end of 2013 to use up their "TIE" credits. ƒThe 20% tax credit for a carried-forward annual loss particularly benefits explorers and those who are bringing new fields into production for the first time in Alaska and don't have production yet that they can deduct their costs against. ƒThe "section 024(c) credit" of up to $12 million a year for producers with less than 100,000 barrels a day of production is an incentive for independents and other smaller players to come to Alaska for oil and gas. ƒThe $6 million annual credit under AS 43.55.024(c) is an incentive for exploration and development in the areas of Alaska outside the North Slope and Cook Inlet basin. Have these incentives under PPT worked? The rd preliminary results so far say yes. DOR's August 3 report on PPT states that capital investments for FY 2008 are 80% greater than previously estimated, despite the fact that operating expenditures are up by 101% over the prior projections. Of course, it will take time before companies can fully respond to these incentives, and it will take even more time to tell whether the new investments to increase oil production succeed in actually getting more production. But so far things appear to be moving in the right direction. There is the question of whether the inability of explorers and almost-producers to sell their credit certificates near face value has been a material problem. As the Executive Director of AOGA, I can assure you there is no one among AOGA's membership who thinks any problem in selling the certificates has been serious enough to justify amending the PPT. Now, moving on to SB 2001, how well does it stack up under the standard of being fit for purpose? Certainly, it would generate even more tax revenue than the PPT will, at least in the short term. But it is premised on the totally mistaken notion that increasing what the government takes from the economic "pie" will encourage greater investment, or at least not decrease it from what it would be anyway. No one has ever taxed economic growth and development into existence. SB 2001 will not do so, either. The second standard for evaluating SB 2001versus PPT is that the administration and enforcement of the tax must be as efficient as possible, consistent with ensuring compliance by taxpayers. Here, the two chief objections to PPT have been, first, that it is all but impossible to forecast the revenues from it with the accuracy needed for state budget purposes, and second, that the audit challenges of PPT leave DOR's auditors hopelessly outgunned. So the questions that need to be answered are, how much merit do these criticisms have, and how would SB 2001 address these concerns? Regarding forecasts for PPT, DOR cites two major concerns about the forecasts. One is that, "[w]hile costs would be expected to increase, the dramatic difference between what was predicted [in the prior Administration's fiscal note for HB 3001] and what has actually been experienced brings into question whether the legislature made its decisions based upon appropriate information." The other is that DOR needs cost information about current and planned spending from the operators, producers and explorers, and this allegedly has not been forthcoming from them. Let us consider this "dramatic difference" between the projected expenditures behind the fiscal note last year, and what those expenditures have actually been. When the DOR staff in the prior Administration sought information about expenditures, they chose not to rely on the representations about 2006 costs that individual companies gave the Legislature in public testimony at that time. Instead, they looked at what they believed to be more reliable information contained in the most recent partnership tax returns that had been filed with the IRS for fields on the North Slope. 9:22:55 AM MS. CROCKETT continued paraphrasing the statement, which read: Federal partnership returns are not due to be filed with the IRS until October of the following year, so even as late as August 2006 when the Legislature passed HB 3001, the most recent returns available were those for 2004. Here is a chart showing the Producer Price Index for oil and gas field machinery and equipment during the last decade. The highlighted bar in the graph marks 2004, and you can see right away why a fiscal note based on the most recently filed federal tax returns, for 2004, would be way off the mark in predicting what the field costs would be in 2006 and '07. There was nothing sinister about what that Administration did. The companies said the 2006 costs were high, but the latest tax returns at that time indicated the costs were significantly less, with a fairly lengthy track record of gradual increases. DOR went with the reported information on the tax returns. I suspect the DOR staff in the present Administration would do the same in those circumstances. In any event, this is not a reason for casting PPT aside. The other criticism that DOR makes of PPT is that producers and other taxpayers are not providing DOR with the information it needs in order to be able to forecast PPT revenues with sufficient accuracy. Obviously, AOGA is not privy to what these taxpayers are reporting to DOR as they make their monthly installment payments and their annual true-up payment st on March 31. DOR's second chief objection to the administrability and enforceability of PPT is that the audit challenges of PPT leave its auditors hopelessly outgunned. It is not for us to comment about the proposal to put auditors in the "exempt" service. But there is a dimension to PPT audits, however, that we can and should address. This has to do with what the source or starting point for determining how much a producer's deductible lease expenditures are. The PPT statutes currently allow DOR a choice between starting from the joint-interest billings and invoices that operators bill to the other participants in an oil and gas field or venture, or starting from a comprehensive set of accounting rules and principles that DOR writes up. Which choice DOR chooses will determine nothing less than the very success or failure of PPT as a tax - and for SB 2001 as well, if it is enacted. It is like having a tax based on your federal taxable income, and choosing between your federal tax return (as audited by IRS) as the starting point, or starting with the Internal Revenue Code and leaving it up to you and DOR's auditors alike to find what the right answer is under the Code. It is like having a tax based on your financial book income, and choosing between your audited financial statements filed with the SEC as the starting point, or starting with Generally Accepted Accounting Principles and leaving it up to you and DOR's auditors alike to find what the right answer is under GAAP. From the taxpayer's perspective, this means a near certainty of continual assessments year after year for additional tax, interest, and perhaps penalties, and depending on how litigious a company may feel, it may mean a long series of lawsuits and appeals as well. From the State's perspective, these same troubles for the taxpayer will mean that the incentives for investment under PPT, or SB 2001, will be seriously eroded. The greater the uncertainty about how much tax a company owes, the greater the likelihood that the incentives will turn out be less than their face value. A taxpayer's only recourse in this situation will be to discount the face-value of those incentives significantly, perhaps completely, in running the economic analysis about making an investment or not. As a consequence, the effectiveness of those incentives will be less than it should be, and Alaska will fail to realize the full amount of new production that it needs to meet the challenge of decline. The other choice that DOR could make is to start with what an operator bills to the other participants in an oil and gas operation. Note that I said "start" with those billings - not "end." Anything in those billings that is nondeductible under AS 43.55.165(e) would have to be backed out. The central concept of lease expenditures in AS 43.55.165(a) is that they must be "direct" and "ordinary and necessary" costs of exploration, development, or production. It would be most surprising if there [is] anything in those billings that goes outside this standard. How can Alaska be sure of this? Because the participants in an oil and gas operation do not give the operator a license to waste their money. I have heard a great deal of concern expressed during these hearings about how the companies might somehow try to "game the system" in order to reduce the tax they will pay the State. While so many are so worried about efforts by the companies not to overpay the State, why would most of these same people think the companies are somehow more willing to overpay the operator than the State? Clearly they don't want to overpay either one. If anything, since the operator usually is a direct competitor, they probably don't want to overpay it even more than they don't want to overpay the State. In other words, if an operator is exploring a geologic prospect, the non-operating participants don't want to pay any costs that are not for the exploration of that prospect. Similarly, if the operator is operating a producing field, they don't want to pay any costs that aren't for the operation of that field. It is reasonable to rely, in the first instance, on the non-operators' self-interests to police and limit what the operator can spend their money on, and they will do that policing by auditing the operator's invoices to them. 9:31:37 AM MS. CROCKETT continued: In the context of PPT, DOR should "audit the audits" to verify that the non-operators do indeed audit an operator's invoices on a regular basis, and that those audits are rigorous and at arm's length. But once these things have been confirmed by DOR in its verification of the non-operators' audits, there is little point for DOR to spend the time and effort to re-plow the field that the companies' audits have already plowed. Daniel Johnston, a consultant hired during last year's debate on PPT, gave an informal presentation to members of the Legislature on Friday, Oct. 19, 2007. During that meeting, he praised the expertise of joint interest auditors and the ability for the state to utilize unit accounting. He went onto say that it would be "extremely insightful for the state to get unit accounting". Mr. Johnston observed that state auditors can be "vicious", but that joint interest auditors are "even more vicious". Of course, for operations where there is only one participant or where there are no audits of the operator's invoices, this approach will be inapplicable. But there are still things DOR could do to build off the billing systems where there are such audits and extend them to these other fields. However, DOR has not yet adopted the "Phase II" regulations to implement and apply its existing statutory authority to authorize or require taxpayers to follow this approach. A very dismaying thing about SB 2001 is that Section 64 would repeal DOR's explicit statutory authority under AS 43.55.165(c) and (d) to require or authorize the use of operators' joint-interest billings as the starting point for computing the amount of a producer's deductible lease expenditures for that unit or field, while Section 71(b) would make that repeal retroactive to April 1, 2006. We believe that this repeal will mean DOR cannot authorize or require a producer to start with an operator's joint-interest billings, even when DOR wants to allow or require their use. Since these repeals are in the proposed legislation that has been introduced, we expect that DOR, in response to us, will testify that somehow they will still be able to require or authorize the use operator billings even if these present statutory provisions are repealed. However, if you enact a law specifically saying DOR may do something and later on you repeal that law, doesn't that repeal mean DOR can't do it anymore? We think so. But even if you are persuaded by DOR that we're wrong on this point, why should you repeal those statutes and take the chance that the courts won't agree? The reason I've spent so much time about the use of joint-interest billings as the starting point for determining a producer's lease expenditures is this: Consider the situation that a non-operating participant faces. All the information it has about what's being spent for the operation is what it gets from its billings from the operator, plus whatever it may learn by auditing those invoices. But if such a non-operator cannot start from those invoices, how can it figure out what to report as the lease expenditures for that operation? All the books and records of the expenditures are with the operator, and if the non- operator hasn't yet audited the operator, it will have no idea what those books and records show. It is infeasible for a non-operator to be auditing the operator month by month, yet the non-operator will somehow have to be reporting and paying installments month by month throughout the year. Even by the March 31 true-up the following year, it is unlikely that any audit of the operator's books and records will have been begun by that date, much less completed. The penalty for mis-estimating the installment payments is principally in the difference between the rate of interest on overpaid installments and underpaid ones. But the March 31 true-up is very serious business. Interest at an APR not less than 11% compounded quarterly begins to accrue, and penalties of up to 30% for negligence and failure-to-pay can be assessed, on the amount of any underpayment continuing after that true-up date. If a non-operator cannot rely on its billings from the operator as the starting point for these purposes, what is it supposed to use? 9:32:56 AM REPRESENTATIVE SAMUELS asked: I would assume, if you are ... Exxon, and you have to pick BP for operating at Prudhoe Bay, ... you'd have nowhere to go if you didn't use those billings that BP sent you. The way that you're reading the proposed legislation, where would DOR start? 9:33:48 AM MS. CROCKETT emphasized that HB 2001 would repeal the authorization or ability of DOR to use joint interest billings. By repealing that provision, she said, AOGA questions whether or not DOR could use "those joint operative billings as a starting point." 9:34:16 AM REPRESENTATIVE SAMUELS remarked that the commissioner had a different take on that language. 9:34:59 AM REPRESENTATIVE NEUMAN asked for clarification of a paragraph on page [10] of the statement, which begins: "We believe that this repeal will mean DOR cannot authorize or require a producer to start with an operator's joint-interest billings, even when DOR wants to allow or require their use." 9:35:56 AM MS. CROCKETT explained that that paragraph communicates AOGA's belief that the ability currently in statute for the department to use joint interest billings as a starting point for audit purposes would be repealed by HB 2001. In response to a question by Representative Neuman, she said it is not the understanding of AOGA that the bill reinstates that capability. She said AOGA concurs with Representative Samuels' recommendation that clarification be obtained from DOR. Furthermore, she recommended that there be legislative discussion to clarify that it is the intent to continue to allow the department to continue to use those [joint interest billings]. 9:37:47 AM MS. CROCKETT returned to paraphrasing the next portion of the statement, which read as follows [original punctuation provided]: If, as we fear, the repeals of AS 43.55.165(c) and (d) under the proposed bill will indeed take away DOR's discretion to allow or require the use of operators' joint-interest billings, then SB 2001 will completely fail the third standard by which a tax is measured - that it must be possible for a taxpayer to get the tax right when it is due, when the taxpayer wants to do so. This will be impossible for non- operators under the proposed legislation. Even PPT will fail if the "Phase II" regulations do not reasonably implement DOR's present authority under AS 43.55.165(c) and (d) regarding the use of operator billings. Before I close, there are a few confusing things in the SB 2001 I would like to address. The first of these is Section 1, declaring that subsection (b) in the new production-tax statute of limitations being enacted is intended to "confirm by clarification the long-standing interpretation of AS 43.05.260 by the Department of Revenue relating to limitation of assessments for the production tax on oil and gas and conservation surcharges on oil." Does anyone here know why this is in the bill? AS 43.05.260 is the existing statute of limitations for auditing all state taxes under AS 43, and what is it about this present limitations statute that is being "confirm[ed]" by the new AS 43.55.075(b)? If you read this new section 075(b) - which begins on page 35 line 30 and runs through line 15 on page 36 of the bill - you see there are two parts to the subsection. One part is the first two sentences, which address the effects for tax purposes of judicial or administrative decisions that retroactively change parameters for calculating the tax. The other part is the last sentence, including paragraphs (1) and (2), and requires producers to report such decisions to DOR within 60 days and to file amended returns within 120 days. The curious thing is that the existing statute of limitations (AS 43.05.260) - the interpretation of which is to be "confirmed" - has nothing in it pertaining to either of these subjects. Here is the text of AS 43.05.260 and you can see this for yourselves. Subsection (a) sets three years as the period for DOR to audit and assess any additional tax that may be due, and it bars suits to collect any additional tax if that tax is not assessed within the three-year period. Subsection (b) says that, if a taxpayer files its tax return early before it is due, the three-year period starts running from the due date instead of the actual filing date. Subsection (c) creates three exceptions to the rule under subsection (a), which appear as paragraphs (1) - (3) of subsection (c): namely, for false or fraudulent returns to evade tax, for a failure to file any return at all, and for extensions of the three-year period that are mutually agreed upon in writing by DOR and the taxpayer. Which of these provisions has anything to do with tax effects of retroactive decisions? Which has anything to do with having to report such decisions to DOR and filing amended tax returns? It is not immediately clear to us what either of these topics in the new statute of limitations has to do with interpreting any of the provisions in existing statute of limitations I've just reviewed with you. So what's going on with Bill Section 1? 9:41:21 AM MS. CROCKETT continued: We believe Section 1 is a stealthy attempt to legislate an outcome to matters that are already being litigated in the due course of administrative and judicial proceedings. In 1999 DOR amended one of its production tax regulations, 15 AAC 55.200, so that it reads remarkably like AS 43.55.075(b) being enacted in this bill. Here you have the regulation and the proposed new AS 43.55.075(b) side by side, with identical or parallel language in them being under- lined. As you can see, the regulation deals with "decisions of regulatory agencies, courts, or any other preemptive authority" while the proposed new statute addresses any "decision of a regulatory agency, court, or other body with authority to resolve disputes[.]" The regulation deals with "retroactive adjustments in costs of transportation, sales price, prevailing value, or consideration for quality differentials relating to the commingling of oils or of oil and NGLs" while the proposed statute addresses "a retroactive change" to the very same things, plus any change to "a lease expenditure[.]" Both state that retroactive changes in the parameters for calculating the taxable value have "a corresponding effect, either an increase or decrease, as applicable on" that taxable value. Now, the "interpretation" that comes into play here has to do with the question of when interest begins accruing on a tax increase or decrease that results from one of these retroactive decisions - does it begin to accrue as of the date of that decision? Or does it begin to accrue all the way back to the original payment due date? 9:43:10 AM MS. CROCKETT concluded: When DOR adopted the amendment to the regulation in 1999, the director of the Tax Division at that time told AOGA members that DOR was interpreting that amendment to mean interest would start to accrue as of the original payment due date for the tax, not as of the date of the retroactive decision. We believe it is this "interpretation" of its own regulation, which is in the process of being appealed in due course, that the Administration intends to have "confirm[ed]" under Section 1 of SB 2001 as the proper interpretation of the pre-PPT statute of limitations. The question for you is, do you really want to confirm this? Confirming it would set a destabilizing precedent, because it will mean that the laws can effectively be rewritten to deal with subjects that they did not originally deal with, and this can be done clandestinely by "confirming" some purported "interpretation" of it. For one thing, it would be an attempt by the Executive and Legislative branches to determine the outcome of matters that are already before or headed to the Judicial Branch in due course. Can the Legislature intervene in Judicial matters under the Separation of Powers Doctrine, and even if it can, should it attempt to do so here? Second, what does it say to potential investors in this state about our sense of justice, Due Process, and fair play? Now, if the Administration appears before you or any other committee of this Legislature and disavows any and all intention to do such a thing, I would encourage you to ask them to clearly explain what they did intend to achieve with Section 1, so that it will be part of the legislative history of this bill. Then, if it becomes law, the legislative history will be there to establish that the "interpretation" which we fear is not the Legislature's intent, nor the Administration's. A second confusing thing in SB 2001 relates to the new statute of limitations being proposed for production tax only. Why does the limitations period need be six years instead of three, when the three- year period can be extended and re-extended any number of times as appropriate? If the state auditors are anything like me and everyone I know, their work will expand to fill the time allowed - giving them six years to get their audits done will mean they'll take six years to audit even when they could otherwise be done more quickly. Unfortunately, the longer the audit runs, the greater the amount of interest there will be that accrues on any underpayment claimed in the audit. After three years, interest represents 38¢ for each dollar of additional tax claimed, assuming interest is not above its 11% APR floor rate. But after six years the accrued interest is 92¢ for each dollar of additional tax. By raising the stakes so substantially for each audit claim that is raised, the longer limitations period will make it easier to justify litigating claims. The purpose of a statute of limitations is to bar claims when they start to become so old that the records, documents, and recollections of witnesses may well be lost or not readily available by the time those claims are finally raised. The present statute of limitations has worked for all the other taxes under Title 43, including the present worldwide corporate income tax for oil and gas taxpayers, the domestic or "water's edge" income tax for other corporations, even the former separate-accounting income tax. It is worth noting that separate- accounting involved not only determining net income from all of a taxpayer's interests in oil and gas fields and prospects, but also its income from interests in oil or gas pipelines as well. While PPT and SB 2001 are not simple taxes, separate-accounting was probably even more challenging to administer and audit. If Alaska didn't need a longer statute of limitations for separate-accounting, we don't see why one is needed now. In conclusion, SB 2001 fails two of the three standards for evaluating a tax, while PPT passes two of them and would pass the third one as well if DOR adopts the appropriate regulations. SB 2001 in the short term will generate more tax revenue for the State than PPT; however, it will achieve this at the cost of reducing the incentives for new investments, and worsening the overall tax climate for making them here. SB 2001 fails the test of being administrable as efficiently as possible, consistent with ensuring taxpayer compliance. This failure will primarily be due to repealing DOR's existing statutory discretion to allow, as appropriate, joint-interest partners do the auditing of the operator's billings to them. Instead DOR auditors could have to re-invent the wheel for themselves in each audit. SB 2001 also fails the test that a taxpayer who wants to pay the correct amount of tax when it comes due must be able to do so. This will be impossible for every company that owns an interest in a lease or property that it does not operate. This in turn will effectively destroy the value of the remaining tax incentives under this bill that potential investors will perceive. If they cannot tell what they owe, they surely cannot put a reliable figure to the value of the incentives under the tax. All of this brings us back to the fundamental issue facing Alaska today…the decline of Alaska production. Today Alaska's production has fallen from its peak of 2.1 million barrels a day down to the 700,000 range. This means that the trans Alaska pipeline is 2/3 empty. I would remind you of my chart earlier that showed the purely mathematical results about how long we have before hitting the 300,000 barrel-a-day TAPS mechanical threshold, depending on what rate of decline you assume will turn out to come true. And it's important to remember that today's 6% decline rate would be on the order of 15-16% were it not for the substantial investments which continue to be made by operators in existing fields. Further, Alaska is fortunate to have on the nearby horizon Pioneer's Oooguruk project, scheduled to go into production in 2008. The importance of future investment is further emphasized when one looks at the Department of Revenue's forecast of future production levels. In three short years, DOR projects that production will come from projects requiring significant new investment. Draw that timeline out to 2017-ten years from now-and you discover that half of Alaska's production will come from new production-production which will only come from investments yet to be made. The most important policy question is whether SB 2001 provides a framework for encouraging this additional new investment. AOGA's 17 member companies unanimously agree that PPT does accomplish that goal, and as such, should not be changed at this time. 9:50:23 AM REPRESENTATIVE NEUMAN observed that [the endnotes on pages 17- 19] include mathematical calculations. Referring to page [13], he questioned whether the legislature can pass a law that has an effect on matters already in litigation. 9:51:20 AM CHAIR OLSON indicated that the legislature has done so in the past. He added that whether that is right or legal might be a separate issue. 9:52:11 AM MS. CROCKETT, in response to questions from Representative Doogan, confirmed that AOGA would have a more detailed analysis of the bill available as soon as possible. She reiterated that when making decisions related to tax, AOGA's policy requires a unanimous vote of its members. In response to follow-up questions, she said ConocoPhillips Alaska, Inc., is not a member of the association, but BP is. She confirmed that BP's position would match the specifics in AOGA's statement. She stated that when PPT was introduced, AOGA took some time before taking a position on it because its member companies held varying views. She noted that she has been with the association for 37 years. 9:54:34 AM REPRESENTATIVE DOOGAN asked if there has ever been an oil tax increase bill that AOGA has supported. 9:54:39 AM MS. CROCKETT said she does not believe so. 9:54:48 AM REPRESENTATIVE NEUMAN asked Ms. Crockett if it would be possible to condense AOGA's previously presented statement down to one or two pages with bullet points to simplify it. 9:55:27 AM MS. CROCKETT answered probably not in one or two pages, because tax issues are complicated and require a lengthy presentation. However, the key concerns could be consolidated. 9:56:02 AM REPRESENTATIVE NEUMAN indicated that it would be helpful, for example, when using statute citations, to include the subject of that statute. 9:56:21 AM REPRESENTATIVE RAMRAS used Cook Inlet as a discussion point to compare the tax structures for that area. He said he is "on board" with the tax strategy for Cook Inlet. Notwithstanding that, he said it has become commonplace in the legislature to talk about "the cliff of available gas" in Cook Inlet. He said everyone is aware of the tax relaxation that ring fences that area in order to induce exploration, because "even with the posture change for Agrium, natural gas is still at risk." He said the TAPS line could be facing the same cliff as Cook Inlet. He said, "It doesn't take that many years of 6 percent annual declines to reach different crises points." He mentioned available state royalty oil for Flint Hills, batching oil through the TAPS, the economics of maintaining the TAPS line, and the cost per barrel of oil that moves through the TAPS line as production declines. Representative Ramras asked why the current legislature and administration does not seem to want to care for the industry and be mindful of not creating the same scenario for the TAPS line that has happened around the available gas in the Cook Inlet. 9:59:33 AM MS. CROCKETT replied that there are programs currently in place on the books that encourage exploration for oil and gas in the Cook Inlet region, including the state's areawide leasing program - a reliable access to resources by companies; exploration incentive credit programs for Cook Inlet; and the PPT system, which recognizes the challenges facing oil and gas development and a declining resource area, such as the Cook Inlet and Southcentral Region. She said discovery and development of new sources of gas on the Kenai Peninsula and in Cook Inlet would clearly benefit everyone, and she urged the legislature to do everything in its power to support that happening. 10:00:50 AM REPRESENTATIVE RAMRAS questioned why, if that is true for Cook Inlet, and everyone grasps that concept, a different approach is being taken on the North Slope. He asked what is wrong with the administration and members of the legislature that they want to "turn the wrench" until they "wreck the economics of the TAPS line." He explained that he is interested in TAPS because it runs through his community. 10:01:41 AM MS. CROCKETT said decline in production is the single most important issue facing Alaska; it affects the state's revenue stream, but will also start affecting TAPS. That decline will require new ways of transporting the oil through TAPS. She said she would like people to focus on how the decline can be addressed in the short term. Long-term plans include exploration and bringing new fields on line, but the number one, short-term way to address that decline, she proffered, is by investing in the existing fields. If the fiscal regime sends the message that investing in the existing fields will not generate the rate of return needed, then the outcome, she warned, will be to watch those production levels continue to decline. The committee took an at-ease from 10:03:46 AM to 10:17:14 AM. 10:17:29 AM CRAIG HAYMES, Production Manager - Alaska, ExxonMobil Corporation, paraphrased the first portion of his 17-page written statement [the corresponding charts and graphs for which are available in the committee packet], which read as follows [original punctuation provided]: INTRODUCTION  Mr. Chairman, members of the committee: Good morning. For the record, my name is Craig Haymes. I am the Production Manager for ExxonMobil in Alaska, a position I have held since January 2007. I have the pleasure of living in Anchorage with my family. Prior to January this year I was involved with Arctic oil and gas projects on the East coast of Canada for almost five years. I want to thank the committee for the opportunity to express ExxonMobil's views today regarding the Administration's proposed tax increase. Let me state upfront, ExxonMobil believes the current PPT tax rate and the increase proposed by the Administration will have a negative impact on resource investments in Alaska. ExxonMobil does not support the proposed tax increase by the Administration. We believe that Alaska needs to focus on a long-term resource development policy. The policy should encourage increasing investment that is needed to maximize the development of Alaska's resources. Alaska is rich in undiscovered resource potential, yet oil production continues to decline from mature basins. Oil production today is one third of the peak of over 2 million barrels per day in 1988. Alaska faces a significant challenge. We have a common goal to maximize economic resource development and need to work together; Government, industry, and the people of Alaska, to enhance the development of Alaska's rich resources and the future. MR. HAYMES paraphrased the next portion of his written statement, beginning on page 2, which read as follows [original punctuation provided]: EXXONMOBIL IN ALASKA  ExxonMobil invests all over the world to meet the growing need for energy. Over the last 20 years we have invested close to $280 billion dollars to search for new supplies of energy, build new production facilities, expand refinery capacity and deploy new, environmentally sound technologies. ExxonMobil believes technology innovation is the key to meeting the world and Alaska's energy challenges. Technology is the lifeblood of our industry. ExxonMobil currently spends close to $1 billion per year on research and technology. We have consistently applied our technology in Alaska to unlock and develop resources. We have significant arctic experience around the world. Some examples of technology applications that we have contributed to Alaska are · The installation of the ice resistant Granite Point platform in Cook Inlet, which is still producing oil. · Significant research and engineering for the Prudhoe Bay completion designs for permafrost · The installation of the first Concrete Island Drilling System (CIDS) to drill exploration wells in ice covered waters in the Alaska Beaufort Sea. · The first full-field 3-D simulation model of Prudhoe Bay, leading to many enhanced oil recovery and development drilling programs that are still being pursued today. 10:21:04 AM MR. HAYMES' statement continued as follows [original punctuation provided]: The application of technology will continue to be a key to the future of Alaska's resource developments. ExxonMobil has had a presence in Alaska for over 50 years and has been a key player in Alaska's oil industry development, spending and investing over $20 billion dollars. We hold the largest working interest at Prudhoe Bay (36.4%) and our current working interest share of oil production in the state is approximately 150,000 barrels per day. We are also the largest owner of discovered Alaska gas resource. We are currently active with our co-owners at Prudhoe Bay, Kuparuk, Duck Island, Granite Point and Point Thomson. Over the last two years we have participated in the drilling of over 70% of the wells on the North Slope - over 130 wells were drilled at Prudhoe Bay alone - this drilling will add 50,000 B/D of oil production in 2007, an important contribution to help mitigate production decline. We are proud of the role that our company has played in Alaska, which we believe has benefited both the State and the industry, and we look forward to working with Alaska for many years to come. 10:22:31 AM MR. HAYMES addressed Alaska's resource opportunities, paraphrasing from the portion of his written statement beginning on page 4, which read as follows [original punctuation provided]: ALASKA RESOURCE POTENTIAL IS SIGNIFICANT  I would like to take a few moments to discuss Alaska's resource opportunities. Alaska has significant oil and gas resources. According to the US Geological Survey and the US Minerals Management Service, Alaska's undiscovered technically recoverable resources are 53 billion barrels of oil. This is in addition to the Department of Natural Resources estimate for known remaining oil resources of 6 billion barrels. To date Alaska has produced close to 17 billion barrels of oil - this is a world class result - but is less than one fourth of the potential total of 76 billion barrels. That is, Alaska still has the potential to produce another 59 billion barrels of oil. The gas resource potential almost doubles this undiscovered potential on an oil equivalent basis. Whilst Alaska's resource potential is high, the Oil and Gas Journal and Energy Information Administration report that its world ranking of proved reserves has thth declined from 14 in 1977 to a position closer to 30 today. 10:24:01 AM MR. HAYMES addressed the subject of Alaska's future oil production, paraphrasing from that portion of his statement, found on page 5, which read as follows [original punctuation provided]: ALASKA's FUTURE OIL PRODUCTION  Today Alaska is producing approximately 750,000 barrels of oil per day from the North Slope, one third of its peak production. The Department of Revenue's production outlook, from their Spring Revenue Sources Book, shows that they estimate a 9% annual decline in Alaska's current base production. As the chart illustrates, at this decline rate, over the next ten years Alaska's current base production, shown in green, will drop to around 360,000 barrels per day. That is a production level of less than half of today's. The Department of Revenue also forecasts that this base production decline will be partially mitigated with the development and production of oil in categories called "Under Development and Under Evaluation", shown in blue on the chart. These categories include future investments, such as development drilling, satellite developments, and enhanced oil recovery from existing fields. Based on this forecast, over 50% of the projected oil production in 10 years will come from new investments. Let me say that again, 50% of future oil production in 10 years is not even developed or producing today. Considering that most new projects take at least 5-7 years to bring to production on the North Slope, investment decisions for these activities, particularly in the near term, will be critical to underpin the future of Alaska's oil production. As I mentioned earlier, the Department of Revenue forecast is based on a 9% annual decline in Alaska's current base production. However, this decline assumes that production enhancement investments at the core Prudhoe Bay, Kuparuk and Alpine areas continue. The Department of Revenue forecast, as shown, does not highlight that this activity requires investment decisions that are no different from the "Under Development and Under Evaluation" categories. As such, a more accurate representation of the future oil production and investment levels required to achieve the Department of Revenue forecast is illustrated in the following chart. As this chart shows, Alaska's oil production from the North Slope could be as low as 150,000 barrels per day within 10 years, (assuming 15% decline, which is typical for large oil fields such as Prudhoe Bay), without ongoing and increasing investment. Based on this forecast, within 10 years, 75% of production will come from new investments. Conservatively, we estimate that at least $30-40 billion of investment is required within the next 10 years to achieve the Department of Revenue forecast. This does not include the billions of dollars of additional operating expenditures that would be required to support the developments once they are producing. This is a significant level of future investment and spending. The high tax rate in PPT and the proposed tax increase put this investment at significant risk. Alaska needs to encourage the increasing investments required, not only in exploration activities, but also in the ongoing development of existing and new fields. 10:28:01 AM MR. HAYMES talked about Alaska as a high cost region, and he paraphrased his written statement at page 8, which read as follows [original punctuation provided]: ALASKA IS A HIGH COST REGION  Complicating the significant future investments required to mitigate Alaska's production decline is its high costs. Alaska has unique challenges resulting in a high cost environment for exploration and development and very mature producing fields with growing unit costs. Many factors contribute to Alaska's higher costs including: · Severe arctic conditions, placing limitations on when drilling and other operations can be undertaken · A sensitive environment, requiring significant and due diligence measures to protect it · Remote location of the resource and distance to market · Current restrictions for future exploration opportunities All combine to create a unique and high cost environment for Alaska. 10:29:14 AM REPRESENTATIVE NEUMAN mentioned the Department of Revenue's charts. He talked about the estimates of a drop to 360 barrels a day in ten years, and a cost of $30 to $40 billion in new investment "to increase that by 75 percent to maintain the levels that we're at," and he said that means $3 to $4 billion a year in new investment. He asked how much new investment ExxonMobil Corporation has put into Alaska in the last five years. 10:30:31 AM MR. HAYMES replied that the current investment levels in Alaska are approximately $2 to $2.5 billion, and he said that number has been increasing. The UAA web site, he noted, provides statistics showing that the amount has increased from $1 billion. In accordance with the forecast of the Department of Revenue, achieving the level of production that Representative Neuman alluded to would require, conservatively, $3 to $4 billion a year in investment. 10:31:16 AM REPRESENTATIVE NEUMAN asked what assurances Alaska has that the oil industries combined will invest if PPT stays the same. 10:32:08 AM MR. HAYMES said he thinks part of the discussion needs to focus on how to encourage that level of investment to achieve that desired production level. ExxonMobil Corporation, like any other company, he said, will look at the attractiveness of the opportunities and consider many factors. Alaska is a high-cost environment; the investment level required to pursue oil is very high, and projects in the state are capital intensive. The company looks at investments over decades, because they take years to generate a return. Part of that foundation, he said, is fiscal policy and environment, two factors which he said he would cover further into his testimony. 10:33:20 AM REPRESENTATIVE NEUMAN said he would like to know where ExxonMobil Corporation's new investment money comes from and what the company's opinion is as to the effects of PPT on investment in Alaska. 10:33:54 AM MR. HAYMES said ExxonMobil Corporation believes that the tax rate on PPT is too high if Alaska wants to encourage the full development of its resource potential. The company believes that the net structure of PPT will encourage investment at the right tax rate. He said investment levels have increased over the last few years; however, the question that needs to be asked is how high it could have been. He said that is a difficult question to answer, because it is "very hard to know what we haven't achieved when we don't know." He mentioned the U.S. estimate of 76 billion barrels of oil of potential technically recoverable reserves and that not only one quarter of it has been produced. He stated, "That's the prize that we all need to work together to pursue." He said ExxonMobil Corporation has a keen interest to pursue the development of energy across the world, and if the environment and conditions are right, it will do so. 10:35:23 AM MR. HAYMES returned to his presentation. He paraphrased from the portion of the statement beginning on page 9, which read as follows [original punctuation provided]: ALASKA'S SO-CALLED LEGACY FIELDS  The two largest oil fields in Alaska - Prudhoe Bay and Kuparuk, have been producing since 1977 and 1981, respectively. Today these two fields account for over 70% of the State's North Slope oil production. Assuming that exploration and investment activity continues in these fields, they could remain at this level of production contribution for the next decade. These so called legacy fields require continuous investment to keep the oil flowing and the facilities operating at capacity. This is the same for any oil field in the world. During the production phase there are many changes in operating parameters, such as reservoir pressure changes, oil, gas and water production changes, changes in operating conditions, and ongoing technical challenges. In order to keep the oil flowing, these changes require additional investments, such as the addition of water and gas injection and gas compression facilities, which are historical significant investments at Prudhoe Bay. Currently, the owners spend over $2 billion dollars to optimize and enhance production from Prudhoe Bay and Kuparuk. These spending levels are in addition to the capital investments pursuing new wells, projects, and enhanced oil recovery opportunities. These operating expenditures are essential to mitigate production decline at these significant fields, which are critical to the future of Alaska's North Slope oil production.   Many of today's exploration and development activities are occurring in and around Prudhoe Bay and Kuparuk. As an example, since the year 2000 there have been multiple Prudhoe Bay satellite fields developed - Aurora, Borealis, Midnight Sun, Polaris, and Orion - which are currently contributing over 40,000 B/D of oil production. These developments would not have been possible without the infrastructure and facility sharing of Prudhoe Bay, which reduced the development and operating costs of these satellites. As satellite fields are developed it reduces exploration and development costs for future new projects, as the infrastructure on the North Slope expands. If the major Prudhoe Bay and Kuparuk developments did not exist these satellite fields would not have been economic to develop. As another example, for the past seven years over 900 new wells have been drilled in Prudhoe Bay and Kuparuk. The drilling of these new wells has slowed the overall production decline from 12-15% to an estimated 6-9%. Almost 40% of Prudhoe Bay's production today is from these new wells. For the past two years, development drilling at Prudhoe Bay has achieved the equivalent of the important Oooguruk development. This example highlights the importance of exploring for and developing new oil in and around the Prudhoe Bay and Kuparuk fields - all are important to the economic benefit and future of Alaska. Let me re-emphasize that Prudhoe Bay and Kuparuk have the potential to continue to be critical contributors to Alaska's oil production. They have the potential to remain key hubs and enablers for exploration and development of heavy or viscous oil, light oil and gas. Encouraging increasing investment at these key fields is as important as encouraging investment in exploration and development of new fields. Without these two hubs, Alaska will be severely challenged to realize the full potential of its resources. Progressing a tax policy that singles out and penalizes these fields will discourage investment not only at these fields but will also impact future investment attractiveness to explore and develop other Alaska oil and gas resources. MR. HAYMES' statement continued as follows [original punctuation provided]: PROPOSED TAX INCREASE MORE COMPLICATED  In analyzing the Administration's tax proposal, we found that virtually all of the provisions are simply tax rate increases or further increases in complexity.   As an example, under the Administrations proposed tax increase the two so-called Legacy Fields, Prudhoe Bay and Kuparuk, would have a separate 10% gross minimum tax and be segregated from each other and all other North Slope fields. This gross tax would be in addition to the base royalty payments. With this minimum gross tax the State would be insulated from price and cost risks, whilst retaining the upside potential from the progressivity element. The Administration is simply proposing to increase its take while shifting the development risks to the producers. Essentially, at low price, producers are penalized. 10:41:05 AM Companies are willing to accept the risks of long- term, capital intensive investments when there is a corresponding opportunity for upside potential and a sharing of risk should prices fall. Under the Administration's proposed tax increase, investors will need to assume a higher economic risk when making funding decisions for future investments and spending. The Administration has also proposed that all revenues and expenses for the Legacy Fields will have to be accounted for separately, with separate taxes paid for each unit and their satellites. This would include Alaska's heavy or viscous oil reserves produced from those Legacy Fields - a resource that already has significant economic and technical hurdles to overcome. No other fields, units or regions within the state would be subjected to these administrative burdens. The ring-fencing of the Prudhoe Bay and Kuparuk Units makes the tax proposal more complex than the existing PPT. 10:42:28 AM MR. HAYMES paraphrased the portion of his statement that begins on page 13, which read as follows [original punctuation provided]: EXXONMOBIL POSITION ON THE ENACTED PPT  I believe it is important that I clarify ExxonMobil's position on the current PPT. ExxonMobil did not support the PPT that was enacted last year. As we testified last year, we supported the concept of a net based tax but stated that the proposed 20% tax rate, in the original PPT bill, would not encourage the full development of Alaska's resources. We agreed with the 20% tax rate in order to support the progression of a gas pipeline project. The PPT that was ultimately enacted increased the already high 20% base tax rate to 22.5% with progressivity - more than doubling industry's taxation. Alaska's current PPT tax rate is too high. When combined with the gross royalties and the high development and operating costs, it makes Alaska one of the most expensive regions to invest. There has been a lot of discussion recently on PPT revenues and forecasts, which has been used in part to support the Administrations proposal to increase taxes. PPT has only been in existence for slightly more than one year. The Department of Revenue has not completed its PPT regulations or started any PPT audit. ExxonMobil, like a number of the other producers, met with the Department of Revenue several months ago to discuss ways to help the State better forecast its expected PPT revenues and we are willing to continue those efforts. We are also willing to work with DOR auditors to improve their understanding of joint interest billings. 10:44:20 AM MR. HAYMES introduced the topic of fiscal predictability and paraphrased that portion of the statement, beginning on page 14, which read as follows [original punctuation provided]: FISCAL PREDICTABILITY IS IMPORTANT  I would now like to address another important element of the business environment - fiscal predictability. ExxonMobil, and I believe the industry, values a predictable fiscal environment in which to make long term investment decisions. Our investments are capital intensive and are evaluated over timeframes of decades. Any change in the fiscal regime has a direct impact on how we view predictability of the Alaskan fiscal environment, which in turn directly impacts how we evaluate on a risk basis future investment decisions. Let me reemphasize this point. Because of the nature and magnitude of the risks associated with any oil or gas investment, coupled with the amount of time required to recoup that investment, fiscal terms that are predictable are key to any investment decision. The Administrations proposed tax increase would represent the third significant change to Alaska's fiscal terms in the past three years. Changing the fiscal environment for capital intensive projects, that take many years to generate a return, can only reduce the attractiveness of future investments. Each time taxes are raised, the attractiveness of any prospective well or project diminish and the likelihood of it not being funded increases. For every well or project not progressed, additional production and State revenues are lost. As mentioned earlier, to mitigate oil production decline Alaska needs to increase investment. The Administration's proposed tax increase will reduce investment. ExxonMobil expects to be involved in Alaska for many years to come. The policies established today and in the future will impact the attractiveness of future potential projects and the future of Alaska. 10:46:31 AM MR. HAYMES concluded his presentation by addressing the issue of a long-term resource policy. He paraphrased from this portion of his statement, which begins on page 15, and which read as follows [original punctuation provided]: ALASKA NEEDS A LONG-TERM RESOURCE DEVELOPMENT POLICY  As I mentioned earlier, Alaska has significant resource potential, but with many unique cost challenges. It will take significant resources, technology, investment and teamwork from everyone to realize the full potential. Alaska and industry collaboratively need to create a resource development policy that encourages investment for long-term production and growth. This is a complex issue and needs significant time and effort from all parties. It is beneficial to look at what others have done. The Canadian province of Alberta has enormous unconventional crude oil resources. Alberta's oil sands represent the potential of over 170 billion barrels of crude, and, like Alaska's resources, are located in higher cost, remote arctic regions that require significant investments to develop. Alberta adopted a resource development policy approach, designed to increase industry investment and production. Their approach has proven successful due to a number of key factors: · Collaborative pursuit of resource development objectives · Development of technologies jointly with industry to reduce costs, increase oil recovery, and upgrade viscous oil to marketable products · Creation of a level playing field for all projects · Sharing risks with the investors by maintaining a lower gross revenue based tax, that is, lowering royalties significantly · Providing long term fiscal predictability Alberta's success suggests that Alaska should seriously consider what other regions are doing to encourage investment. A long-term sustainable resource development policy is required to enable Alaska to maximize its oil and gas resource. There are many factors that need to be considered. It is a complex issue. I hope that key points addressed in my testimony are considered: · Alaska has significant resource potential, but it is in a high cost environment · Oil production is already one third of its peak, yet we have only produced one fourth of the oil resource potential · In 10 years, 75% of Alaska's future oil production needs over $30-40 billion of new investments - investments that are needed sooner than 10 years. · Prudhoe Bay and Kuparuk are the "hub" of the North Slope, they ¾Represent 70% of North Slope oil production for the next 10+ years ¾Can be the backbone for future exploration and economic developments, whether it is existing production, future light oil, heavy oil, or gas ¾Need increasing investments to achieve their potential · Development drilling at Prudhoe Bay and Kuparuk over the last 2 years has added 50,000 B/D of new oil production in 2007 We propose a collaborative approach to develop a sustainable long term resource policy that will encourage the needed increasing investments and build the future of Alaska for many generations to come. ExxonMobil looks forward to working with the Administration, the legislators, industry and the people of Alaska in the future pursuit and development of its oil and gas resources. To encourage full development of Alaska's resources, the PPT tax rate needs to be lowered, and should not include a gross revenue based component. Increasing investment fuels the economy. Thank you again Mister Chairman for the opportunity to testify today. 10:50:54 AM CHAIR OLSON recollected the discussion two years ago regarding fiscal certainty rather than fiscal predictability, and how many legislators at that time "choked" on the concept of a 20- to 30- year lock-down of the tax structure. He remarked, "Fiscal predictability looks to me like it might be one step down the ladder; more of a reasonable position than fiscal certainty." 10:51:59 AM REPRESENTATIVE SAMUELS asked Mr. Haymes what factors the ExxonMobil Corporation considers to arrive at investment decisions. 10:53:13 AM MR. HAYMES responded that ExxonMobil Corporation looks at investment on a global level. Considerations include: resource potential; technical challenges; investment required to pursue a resource; and costs involved in exploration, appraisal, construction, production, and final site restoration. The criteria involve both controllable and uncontrollable aspects. The latter includes commodity price, tax rates, and fiscal policy. He said there are internal annual budgeting processes and working interest owner budget processes that set the tone for a business plan for future years. Each individual investment goes through the same scrutiny, he emphasized. 10:56:14 AM REPRESENTATIVE SAMUELS clarified that he wants to know specifically what happens when a proposal is handed to Mr. Haymes. 10:57:51 AM MR. HAYMES reviewed how an investment portfolio is established by ExxonMobil Corporation. He explained that a finite amount of money is allocated proportionally around the world based on various factors, and it is ExxonMobil Corporation's duty to its shareholders to maximize return. 11:00:28 AM MR. HAYMES, in response to a question from Representative Neuman, stated that ExxonMobil Corporation is keen on working with the State of Alaska to commercialize its gas resources, and the corporation is and will continue to be active in looking at that opportunity. In response to a follow-up question from Representative Neuman, he confirmed that ExxonMobil Corporation is not involved in any current discussions with the administration. 11:00:52 AM REPRESENTATIVE NEUMAN stated: When ... people from ExxonMobil Corporation came here, and you said that you didn't like what we did in PPT, and you didn't like what the [Alaska's Clear & Equitable Share (ACES)] does, ... it's kind of a punch in the guts for me somehow when I go back to 1989 and the money that's owed to the citizens of the state of Alaska, you know, billions of dollars. So, any good faith effort, if you could pass that up, would go a long ways to this guy, ... [and], I think, for the state. 11:01:42 AM REPRESENTATIVE DOOGAN, recalling Mr. Haymes' testimony that ExxonMobil Corporation did not support the 20 percent rate in PPT, but "did it because it was sort of part of a gas pipeline deal," and he asked Mr. Haymes what rate the company did support before that deal got cut. 11:02:11 AM MR. HAYMES answered, "Lower than 20 percent." He said he thinks the key consideration should be that the resource potential in Alaska is significant. Only 15 billion barrels of oil have been produced. According to federal analysis, there is 250 tcf of gas that is technically recoverable. Alaska's future is not just the gas, but it is the oil as well. He stated, "When you put the gas on oil-equivalent barrel basis, there is as much oil and gas together in the future." He reiterated that the focus needs to be on both. He continued: We cannot control the price - the commodity price; that's the market. We cannot control some of the many fixed costs in Alaska. As we know, it's very unique in many respects. Technology will help on that front, as it has for the industry for many years. The key lever you have to pull is the fiscal policy, and that's a key enabler to try and help encourage more investment, which is needed to really develop the full resource potential. 11:03:32 AM REPRESENTATIVE DOOGAN directed attention to page 14 of Mr. Haymes' statement, to the sentence which read: "Any change in the fiscal regime has a direct impact on how we view predictability of the Alaskan fiscal environment, which in turn directly impacts how we evaluate on a risk basis future investment decisions." He suggested that Mr. Haymes is really referring to increases, rather than changes in that sentence. 11:04:16 AM MR. HAYMES responded that the overall policy needs to be predictable in order to make investments that take decades to generate a return and are capital intensive. 11:04:31 AM REPRESENTATIVE DOOGAN asked, "So, a tax cut would bother you as much as a tax increase?" MR. HAYMES said he thinks any industry would be against a tax cut. 11:04:40 AM REPRESENTATIVE DOOGAN said the other two major North Slope producers "shared their profits on their Alaska operations with us last year." He offered his understanding that ConocoPhillips Alaska, Inc., had reported $2.3 billion, while BP reported $2.15 billion. He asked Mr. Haymes what ExxonMobil Corporation's profits were. 11:05:09 AM MR. HAYMES replied that ExxonMobil Corporation does not report profits on an Alaskan basis; it reports it on a global basis, in accordance with its quarterly earnings summaries. He said the annual report does talk about ExxonMobil Corporation's net oil production for Alaska, and last year there were 150,000 barrels per day. 11:05:33 AM REPRESENTATIVE DAHLSTROM asked Mr. Haymes to comment on the level of predictability ExxonMobil Corporation would like to see in order to stay and do business. She said she would also like to know if a representative of ExxonMobil Corporation such as Mr. Haymes is currently in Alberta, Canada, "fighting this fight." 11:06:27 AM MR. HAYMES said Alberta recognizes the significant challenge of their oil sands. He offered his understanding that Alberta ranked at about thirtieth in the world on "proved reserves," and today it ranks second. Alberta changed its fiscal policy about 15 years ago, and that change spurred a huge economy growth. He noted that recently there has been a recommendation from a panel for Alberta to increase its royalties. That recommendation has not been adopted and is under intense scrutiny and debate. EnCana Corporation has said that if that policy is implemented, it would reduce its spending in [Alberta] by $1 billion. Talisman Energy Inc. and ConocoPhillips Alaska, Inc., have also said they would reduce its expenditure by half a billion dollars. Those withdrawals could potentially delay $8 billion future investments on the oil sands. He said that gives a picture of how tax increases can affect investment. He said the focus should be on what is the right policy to develop the full resource potential of Alaska - to consider how, with Alaska's unique challenges, the state can replicate what is being done in Alberta. He said there needs to be a collaboration between the federal and state government and the industry. 11:09:34 AM REPRESENTATIVE DAHLSTROM noted that one company had told the legislature that in the event the existing bill is passed, it would not pull out from Alaska, but would fulfill its contractual agreements, although it may need to change some of its business strategies. She asked Mr. Haymes to comment on what ExxonMobil Corporation may or may not do. 11:10:14 AM MR. HAYMES replied that ExxonMobil Corporation has been in Alaska for 50 years and would not pull out of the state. He said, "I think it really gets down to: how do you attract an increasing need of investment to mitigate oil production decline ... an hopefully even increase it." 11:11:30 AM REPRESENTATIVE RAMRAS spoke of his recent disclosure of his investment in the ExxonMobil Corporation, and the reaction of his constituents regarding that disclosure. He noted that anyone who enjoys receiving the PFD is supporting ExxonMobil Corporation, because that corporation is the largest single equity holding in the Alaska Permanent Fund Corporation. He said the legislature has had an open debate with the Commissioner Pat Galvin and is in agreement that the state can benefit from short-term horizon gains in tax revenue over the next three to four years. He asked what would happen if Alaska dampens investment opportunities and harvests a surplus in tax revenue for three or four years. He asked how many places in which ExxonMobil Corporation is involved. Representative Ramras stated that there is a difference between being passive and active in terms of resource development. He remarked that the legislature's intent in 2006 was to reward activity and to be punitive toward passive activity of harvesting revenue from the state and allowing it to migrate to other places in the world. He asked how long it would take to regain to revamp the capital should that migration occur. 11:15:37 AM MR. HAYMES said there is no defined time for how long it would take, but it would be a long time - at least 12 to 17 years. In the Alberta example, that province changed its fiscal system and provided predictability back in 1991, but the boom in Alberta has only occurred in the last 3 or 4 years. Mr. Haymes said it takes a long time from discovery to production of oil - easily decades. He reiterated that Alaska is remote and has challenges. Technology is needed to reduce the cost and lower tax rates are necessary in order to encourage more investment. 11:17:37 AM REPRESENTATIVE NEUMAN referred to testimony of 10/22/07 from a small investment company. That company explained that Norway charges a higher tax rate, because it starts taxing after expenses are covered. He asked Mr. Haymes would not be disturbed by a higher tax rate if Alaska incorporated that type of structure. 11:19:25 AM MR. HAYMES reiterated that ExxonMobil Corporation is looking for fiscal predictability, and he said there are many different ways to find that. Every country has a different model. He stressed the need for a collaborative effort with government and industry to establish an equitable, workable best-case scenario. 11:20:53 AM REPRESENTATIVE NEUMAN noted that page 4 of Mr. Haymes' statement shows that Alaska has 53 billion barrels of oil still recoverable, but the ranking of its reserves have declined from fourteenth in 1977 to near thirtieth today. He asked Mr. Haymes what criteria are used in those rankings. 11:21:59 AM MR. HAYMES said the definitions used by the Oil and Gas Journal and Energy Information Administration are based almost solely on economics, without "significant technical challenge" and without considering total resource potential. He noted that Canada was ranked seventeenth and now ranks second. Norway has increased in ranking, as well. 11:23:36 AM REPRESENTATIVE NEUMAN asked, "Is that directly proportional to the amount of known reserves?" 11:23:56 AM MR. HAYMES said some aspects must be looked at: the resource potential of the basin, the technical challenges, the cost challenges, and the fiscal policy that encourages investors to invest. He stated, "We can learn from others ... but we need to step back and say what's right for Alaska." 11:24:33 AM REPRESENTATIVE COGHILL said the tax rate that was chosen last year was the beginning of the discussion to figure out how the state can improve its partnership with the industry. He opined that the investment ExxonMobil Corporation and others have made under the ELF system was terrible. He noted that there has been a change to both price and cost environment, and Alaska is trying to make investment decisions and capture the value of its resource along the way. He said, "I think you did a much better job of capturing the value than we did." He said he thinks the governor is questioning what is a fair share. Representative Coghill said he is listening intently to find out how Alaska can get the oil industry to invest through incentives, while still ensuring the state shares in the value "as it goes out the door." He stated concern about "the progressivity and the floor." He said he would rather "see a share on the upside and go ahead and take the risk on the lower side." He asked Mr. Haymes to explain "the complexity of the recording." 11:27:05 AM MR. HAYMES reviewed two aspects which he covered in his previous statement. One is the 10 percent gross floor and the other is the ring fencing, which is applied to Prudhoe Bay and Kuparuk River Unit. The 10 percent floor, he said, adds uncertainty around the assumed tax rate if the crude price is low, and that 10 percent floor needs to be considered when looking at long- term investments. Investment decision risk assumes the worst- case scenarios. He continued: On the legacy field component of ring fencing costs, I cannot see how that encourages investments for anybody. First of all, it is focused on Prudhoe Bay and Kuparuk, which in itself adds complexity. Adding complexity and administrative burden makes it tougher for everybody to try and work out what the joint venture billings are, what is in that ring fence, what's not - it's going to create a lot of uncertainty and a lot more auditing requirements from everybody. MR. HAYMES said ExxonMobil Corporation recognizes that the administration is proposing not to use the joint-interest billings as a starting point for audits, which he said the corporation finds difficult to understand. He continued: We, as a "nonoperator" of Kuparuk and Prudhoe Bay, spend a lot of money and time auditing our joint- venture billings, as I'm sure any of you would do if you were a partner in any business. We spend almost half a million dollars a year and a hundred weeks of work effort every year auditing our joint-venture billings, and we believe ... an excellent starting point for any auditor to look at is: What have the other auditors done? Audit the audit. And then if you find gaps, start to look at other information. MR. HAYMES said the current proposal has a lot of other complexities that need to be seriously considered and thought through. He said the acid step is to question whether a proposal will encourage more investment, simplicity, and transparency in Alaska. 11:30:30 AM REPRESENTATIVE COGHILL said the legislature needs to figure out if "that floor" does that. He offered his understanding that ExxonMobil Corporation was given the ability to transfer credits within the ring fence, and he said it will be interesting to hear from ExxonMobil Corporation and the administration regarding "what value that really is." He offered his understanding that progressivity is outside that system. He concluded, "I'm looking for where ... the levers move to make that valuable to us and less valuable to you. And I haven't ... been convinced by either argument yet - ... to me it's an open question." 11:31:46 AM MR. HAYMES said DOR's "economic 101 on the fields A, B, C, D, and E" is narrow in its focus, because it looks at one price and assumes it's constant. Furthermore, it focuses purely on net present value. Any investor does not look at just net present value as a criteria for an investment decision; there are many factors and ranges of outcomes that need to be considered. There are variables in resources, costs, and commodity price. 11:32:58 AM REPRESENTATIVE COGHILL said the claim is that "we will hardly ever again in history see that lower part truly needed." He added, "But I also was here when we bounced off of $8 oil, so I ... guess anything can happen." 11:33:34 AM MR. HAYMES responded, "The DOR's price forecast even assumes that it's nowhere near what it is today." 11:33:41 AM CHAIR OLSON asked how much oil and gas is coming from Alaska compared to ExxonMobil Corporation's total U.S. production. MR. HAYMES answered the ExxonMobil Corporation produces approximately 2.2 million barrels of oil a day in the U.S. Worldwide, he said, Alaska's production represents 3 percent of the corporation's total production on an oil equivalent basis, including gas. 11:34:14 AM REPRESENTATIVE SAMUELS asked if 3 percent of the spending also takes place in Alaska. MR. HAYMES said over the last five years, ExxonMobil Corporation has invested over $25 billion on projects throughout the U.S. In response to a follow-up question from Representative Samuels, he said the corporation has spent $280 billion. Last year, he noted, ExxonMobil Corporation invested $20 billion worldwide and the industry invested approximately $2 to $2.5 million in Alaska in that year. REPRESENTATIVE SAMUELS calculated: "For simplicity I'm going to say it's 2.4 divided by 3, so you invested $800 million, maybe a little less. Okay, thank you." 11:35:37 AM CHAIR OLSON recessed the House Special Committee on Oil and Gas meeting until 1:30 p.m. CHAIR OLSON reconvened the House Special Committee on Oil and Gas meeting back to order at 1:41:12 PM. 1:41:23 PM JOHN P. ZAGER, General Manager, Alaska, Chevron, offered a 12- slide PowerPoint presentation. He highlighted slide 2, which read as follows [original punctuation provided]: Chevron's Alaska Presence  th ‡ 4 largest producer in state rd ‡ 3 largest operator ‡ ~500 employees or full time contractors „>300 on the Kenai Peninsula ‡ Chevron is the only producer in the state with a relative balance of assets in the Cook Inlet and on the North Slope „Cook Inlet production - 23M BOPD zOld oil production, very high lifting cost „North Slope production - 15M BOPD „In early stages of increased capital program zExtend life of Cook Inlet O&G production zNorth Slope exploration on state lands zInvestment decisions made under PPT MR. ZAGER noted that where slide 2 shows 23 million barrels of Oil per day (BOPD), it should actually read BOEPD, for barrels of oil equivalent per day, because about two-thirds of that volume is actually gas. In its heyday, he said, Cook Inlet produced 200,000 - 220,000 barrels a day gross, and now it is down to 15,000 - 16,000 barrels a day gross. Now what is being lifted is more than 90 percent water. Regarding the early stages of the increased capital program, he said extension of Cook Inlet oil and gas production would be very economically challenging without the current high price of oil. He said some of Chevron's platforms have direct lifting costs - platform- related costs that do not include overhead or indirect expenses - in excess of $40 a barrel. MR. ZAGER said Chevron will have a rig ready to operate to begin a drilling program in Cook Inlet. On the North Slope, he noted, Chevron has accumulated a large exploration position in the White Hills area in which it will begin drilling in December for two years. Chevron has operated a well on the North Slope since the early 90s. 1:45:59 PM MR. ZAGER directed attention to slide 3 of the PowerPoint, which shows Chevron's Capital Investment - its spending profile - from 2006 projected through 2009. The graph shows an anticipated increase from $80 to $400 million in spending. He said a second rig would be added in 2009. 1:46:59 PM MR. ZAGER moved on to slide 4, which read as follows [original punctuation provided]: Chevron is increasing investment under PPT  Introductory Comments  ‡ We do have a common enemy - decline ‡ Disappointing to be back so soon after passage of PPT „Lack of actual PPT results to revise tax policy „Review scheduled for 2011 „Too soon for a change ‡ Need to strike a balance between tax rate and investment climate MR. ZAGER said he doesn't see the evidence to support the theme that PPT is "broken." He said it is too early to make that determination. Regarding the review scheduled for 2011, he said: Quite frankly, that doesn't give me a lot of comfort. Sitting here today, you can see the kind of expenditures we've got going. If White Hills ... is successful, that would mean probably, on a normal time line, some time around 2010, we would be ... commissioning the actual development, which means you go from spending $200 million to potentially billions or more dollars. So, knowing that there's a reopener in 2011 is concerning, because, ... when we run our risk and our distributions, and all the things that could happen, one of the things is that state taxes could go up in 2011. And it's been said, "Well, you guys have been put on fair notice if that's going to happen." And that's true, but it ... doesn't help me right now to make the decision or make a commitment to that point. It won't help me in 2009; it won't help me in 2010. 1:49:47 PM REPRESENTATIVE NEUMAN indicated that the state's oil economists had discussed the subject of stability and had said they did not feel the review scheduled for 2011 would cause insecurity in the industry, because that date allowed warning and time for preparation, and upon hearing that, he had thought it was a good policy. He said he would like Mr. Zager to respond to that, and also to tell the committee what Chevron's "actual" was when looking at capital investments. He thanked Mr. Zager for Chevron's investments in the Cook Inlet area. 1:51:11 PM MR. ZAGER responded that knowing what is coming in 2011 allows Chevron to plan for that contingency, model it into its valuations as best as is possible, and plan its development accordingly. 1:52:36 PM REPRESENTATIVE NEUMAN asked Mr. Zager if he foresees Chevron changing its investment plan should ACES be adopted. MR. ZAGER offered a two-part answer: First, he said, it would be unlikely that Chevron would halt its North Slope program midstream. He said a big part of the cost in Cook Inlet is getting the infrastructure ready to drill and getting a drill rig that's capable of drilling. He said the rigs that have been out in Cook Inlet have been many years out of use and in disrepair, and bringing them back "is a big front-end loading." He continued: To the extent we haven't made commitments going forward, then certainly we would change our economic model [to] reflect ACES. And the effect it will have is it will lower the returns on those projects, and they will get lower in the queue of projects that we fund. ... We're part of the mid-continent and Alaska business unit, which is part of the Chevron North America, so, that's mostly the world we're competing in for developing capital .... Exploration capital is competing more on a heads-up basis across the world. 1:54:21 PM CHAIR OLSON said virtually all the arguments that he has heard revolve around not getting a fair share and make comparisons to other countries, but he said he has heard no comparisons to other places in the U.S. He asked if Chevron is doing business in other states and what tax plan do the other states employ. 1:55:07 PM MR. ZAGER said he has spent most of his time worrying about Alaska's tax rather than analyzing other states. Notwithstanding that, he offered his understanding that the tax in places like Texas is "extremely stable." He added, "There are things going on in some states, but I don't think anything in the magnitude that we're talking about here." CHAIR OLSON asked, "Not the frequency?" MR. ZAGER answered, "Not that I'm aware of." He emphasized the importance of finding the balance between the state's needs and that of the industry. 1:56:19 PM REPRESENTATIVE DOOGAN said the legislature has heard that sentiment from everybody who has testified, including the administration. He asked Mr. Zager how he recommends measuring the investment climate. 1:57:32 PM MR. ZAGER replied that Alaska needs to figure out what product it is leasing and what value it has in the market. He said he would be providing further details later on in the PowerPoint. 1:58:22 PM MR. ZAGER directed attention to slide 5 of the PowerPoint, which read as follows [original punctuation provided]: Factors that affect investment decisions  „Corporations have a responsibility to operate safely, seek returns, and increase shareholder value „Corporate Cash Flow Management zCorporate uses of cash: fOperating Costs fInvestment: upstream, downstream, technology, acquisitions fPay down debt, build cash fPay dividends to shareholders fBuy back stock MR. ZAGER said operating costs include salaries to employees and utilities. Regarding acquisitions, Mr. Zager explained that it is always an option to buy a company and get the reserves than to drill for that company. Chevron, he relayed, is one of the bigger investors amongst its peer group. For the last five years, Chevron has consistently reinvested 100 percent of its earnings and has the largest exploration budget worldwide of any of the producers in Alaska. Its total capital expenditures are - relative to the company's size - second only to Shell. 2:01:45 PM MR. ZAGER, in response to a question from Representative Neuman, said Chevron does not provide segmented earnings and cash flow in its reporting for Alaska. However, he estimated that Chevron has been investing between 50-100 percent of its earnings or cash flow from Alaska. He said the trajectory is up, and at some point, Chevron would be a net investor in Alaska. 2:02:35 PM MR. ZAGER returned to the PowerPoint. Because of the present value of oil, he said, most companies have strong balance sheets at present - possibly even a net cash position. He said companies don't want to be too cash positive, because their shareholders are not paying them to be a bank but to invest money. He said paying dividends to shareholders is a well- received use for large companies' cash. Buying back stock, he said, is another way of "returning a little bit of value to the shareholders." He explained that buying back stock differs from increasing dividends in that it is not necessarily a recurring event. 2:04:00 PM MR. ZAGER moved on to slide 6 of the PowerPoint, which read as follows [original punctuation provided]: Upstream Investment Decisions  ‡ Always more opportunities than can be funded or staffed ‡ Key Factors - How do Alaska state lands stack up? „Rocks - What is the reserve and production potential? „Cost - How much will it cost to find, develop, and produce? „Time - How long will it take to realize revenue? „Risk - What is the probability of success? „Fiscal regime - How much revenue does the investor get to keep? ‡ Economic models are developed, opportunities ranked, and investment decisions are made on an After-Tax Net Present Value (NPV) basis „Does the investor get enough to justify the investment? zGreat rocks can trump poor fiscal terms MR. ZAGER said Alaska ranks high in its distribution of rocks, especially at Prudhoe Bay; however, most of the exploration and new money is not going for Prudhoe Bay light oil, but is going to viscous oil and new exploration. The new exploration prospects in Alaska, he indicated, are middle of the road, in terms of potential. 2:07:23 PM MR. ZAGER said the cost to find, develop, and produce is high - probably in the top quartile. Regarding time to realize oil revenue, he said, "The longer it takes, the less valuable it is." He estimated time periods of 2-10 years to get production on line in Alaska. He named the following risks: geological, price - which would be common around the world, and permitting or other unanticipated delays that can affect decisions. Regarding fiscal regime, he offered an analogy to put across the point that "it's all about what you put in and what you get out at the end of the day." He said he doesn't know how Alaska could compare its product to any other country's product, because it is not the same. 2:10:31 PM MR. ZAGER said some of the key factors listed on slide 6 are more controllable than others. Rocks, for example, are not controllable. He stated, "But the biggest driver that the state really has just about 100 percent control on is the fiscal regime, which is the final thing that would be included." Changing the taxes, he said, will change the relative valuation and where opportunities will fall in line relative to other opportunities in North America or worldwide. Mr. Zager talked about justifying investment to risk. He said getting access to oil in Alaska is one of the best factors of doing business in the state. "Everything after that is when you've ... got the issues," he remarked. 2:13:28 PM MR. ZAGER directed attention to slide 7 of the PowerPoint, which shows with a chart how attractive Alaska is as an investment. The line above the chart read: "Let's look at results of recent lease sales as a scorecard: This is industry voting with their dollars." Referring to the chart, he explained: So, what I've done is ... taken bonus bids on Alaska state lands and compared them to Gulf of Mexico areawide lease sales since 2002. These are the same investors that Alaska should be attracting; they're mostly ... either the super majors or large independents that have the wherewithal to play in the off-shore gulf or the deep water - the same type of players that would be playing on the North Slope of Alaska. MR. ZAGER said the chart shows that the ratio showing lease sales for the Gulf of Mexico versus Alaska is 72:1. 2:15:10 PM REPRESENTATIVE DOOGAN asked Mr. Zager to compare both the Gulf of Mexico and Alaska against the list of factors from slide 6, beginning with rocks. 2:15:26 PM MR. ZAGER offered his understanding that the rocks are better in the Gulf of Mexico, cost in both places is high, time in both places is similar, and the fiscal regime is better in the Gulf of Mexico. He said he does not have an answer pertaining to risk. 2:18:13 PM MR. ZAGER stated that the point is that there are competitors around the world that are marketing their resources. He mentioned Libya as an example of a place that has onerous fiscal terms but is still attracting bidders. He said, "So, it must tell you something's different than it is here." 2:19:06 PM MR. ZAGER highlighted figures on slides 8 and 9, entitled, "Exploration - How taxing the upside can deter investment decision." The slides show four-point economic models, including after-tax (ATAX) net present value (NPV), probability of success (POS), and probability of failure (POV). He stated, "This is a simplistic way of actually approximating the actual distribution which would be ... a law of normal distribution of possible outcomes." He explained the math behind POS and said, "To decide whether to drill, you simply add the probabilities and values together." Mr. Zager showed numbers on the slides that prove the point: "Taxing and taking away the upside does affect decisions today." 2:24:52 PM MR. ZAGER, in response to a question from Representative Doogan, said he chose the 15 percent POS and 85 percent POF amounts for the example on slides 8 and 9 because he thought they would be fair. In response to a follow-up question, he confirmed that those numbers would be based on more information in a real life situation, because that's what geologists and geophysicists are paid to figure out. He added, "If we can convince ourselves that that POS is actually 20 percent instead of 15, then it's a better investment decision." 2:25:56 PM REPRESENTATIVE NEUMAN asked Mr. Zager what the limits are on exploration days in Alaska and how those limits may affect Chevron's decisions. 2:27:07 PM MR. ZAGER said the crew in the North Slope is restricted by a drilling window from December to April or May. In contrast to that, drilling in the Gulf of Mexico can occur 365 days a year. In response to a question from Representative Neuman, he surmised that Norway, with its off-shore drilling, can also operate year round. 2:28:33 PM MR. ZAGER moved on to slide 10 of the PowerPoint, which shows: "Investment is Needed to Maintain Production at Reasonable Levels." Slide 10, he said, is a simplistic spread sheet illustrating an "Alaska Production Forecast Estimate." The blue line on the spread sheet shows the current production at a 6 percent decline. The red and green lines show the results of an assumption of $15 a barrel finding & development costs (F&D) and a $1 billion or $2 billion annual additional investment. The other assumption made, he said, is that there are enough projects going on to continue at least until the year 2027. The committee took an at-ease from 2:30:20 PM to 2:33:55 PM to address technical difficulty. 2:34:06 PM MR. ZAGER returned to slide 10 and said it shows that "we need to attract significantly more investment." 2:34:24 PM REPRESENTATIVE NEUMAN said if investment stays the same, when a pipeline is built in 10-12 years there will be half the amount of oil coming down the pipeline. That's assuming that $15 is "the same $15 10 years from now as it is today," he said. He said that really grabs his attention. 2:35:21 PM MR. ZAGER responded that is correct. He said, "So, whatever the [$15] is now, it certainly could ... mean we need to attract more capital in nominal dollars in future years to get the same amount of work done." 2:35:54 PM REPRESENTATIVE DOOGAN asked, "You've just taken that $15 a barrel and divided it into a billion and tracked the result in production on that line there?" 2:36:07 PM MR. ZAGER responded: In a nutshell, yes. It's a little more sophisticated than that in that I made some assumptions about the timing of that incremental investment. In other words, you don't spend a dollar a day and get all those barrels. And that's why you see this inflection a little bit here. But once it gets out here where these are happening constantly, then it's a straight line again. 2:36:33 PM REPRESENTATIVE RAMRAS mentioned an editorial in the October 2 Anchorage Daily News. He said, "It seemed that the premise was if we're ... at ... 22.5 and 20 [percent], what are we even getting of the 20? Why don't we just keep the 20? ... $600 million was the number they referenced, and they said over 5 years, the $600 million invested, plus the interest income would be about $4.5 billion. That was the premise of the editorial is what are we getting for the money; we should just keep it all and keep the $4.5 billion dollars in our account over the next five years." That said, Representative Ramras asked, "What do we get for the green line versus the blue line? He requested a hypothetical response. 2:40:09 PM MR. ZAGER said the spread sheet shows that in ten years, in the year 2017, Alaska would get royalties and taxes on approximately 100,000 barrels a day. He said he has not done the math to compare a "take it now and bank it" philosophy versus the financial benefit of the spread sheet from the state's perspective. REPRESENTATIVE RAMRAS recommended members read the aforementioned editorial, because it is a fascinating reframing of the argument. 2:41:03 PM MR. ZAGER returned to his PowerPoint, to slide 11, which is labeled: "Chart 14 - Fiscal Attractiveness Rating versus Fiscal Stability Rating." He noted that this chart is from the Wood Mackenzie Government Take Study of 2007 and is somewhat controversial. He explained that the chart shows fiscal security on its vertical axis and fiscal attractiveness on the horizontal access. He said his focus would be on the latter. Alaska, he pointed out, falls at the middle of the fiscal attractiveness axis. Those countries listed to the left are less attractive fiscally. What they have in common is: they are mostly in the Middle East, they are sitting on "world class rocks," many are members of OPEC, and many have their own national oil companies. Developing their reserves is not necessarily something they need or want, but the rocks are so good they can either set a price and let people take it, or open it up and let people bid. He added, "And people will bid it up to the point where they're in that regime, because the pie is so big, there's still enough left to justify their investments." MR. ZAGER drew attention to the countries listed on the right of the chart. Most of those countries, he noted, are "oil patch wannabes" - they have less than 1 billion barrels. In order to attract people to invest, those countries are willing to offer the best fiscal terms in the world. He reiterated that Alaska falls in the middle of the chart. He mentioned the data point from the U.S. He said, "You can argue that industry voluntarily moved themselves to the left. ... The terms and the rocks created enough value that we as industry wanted in that play enough to put $2.9 billion on the table right up front." Using an analogy, he questioned trying to sell a Chevrolet as if it were a Cadillac and simultaneously attracting more investment. He concluded: You just kind of got to wonder when you ... look at this from a high level. People who want to attract more investment are on the right. People who have ... a lot of companies coming to their door are either on the right or they're over here and they can, quite frankly, afford to turn companies away or only have people that will deal specifically on whatever terms they offer. 2:45:53 PM REPRESENTATIVE RAMRAS asked if that is not exactly the discussion that the legislature is having, that some people think that a change shifts the "U.S.A. Alaska diamond" significantly while the administration thinks the change "just shifts the diamond a sliver." 2:46:27 PM MR. ZAGER replied that he thinks that is correct. He said this morning he was asked where Alaska was before PPT came into place or before ELF. He indicated that it would have shown in an upper quadrant of the chart that showed it to be much more stable and more favorable on taxes." He continued: Interestingly enough, you know, this is a confidential piece of work, and I want to just be clear that we got permission from Wood Mackenzie to share this with you today. But we also asked them, "Could you take a look at ACES and plot a new diamond would be if ACES passes?" They declined to do that. ... It would be an interesting piece of data, and ... I don't expect it's going to move it over here, for sure. But the question is, even directionally, is that the way to be moving if we want to attract more investment? A little bit, you know. Where's the straw that breaks the camel's back? 2:47:30 PM REPRESENTATIVE RAMRAS speculated on what would happen should the premier of Alberta sign the Alberta fair share agreement. 2:47:54 PM MR. ZAGER said certainly if Alberta lowers its fiscal stability while raising its taxes, the diamond showing its place on the chart would appear somewhere in the lower-left quadrant of the chart. 2:48:15 PM REPRESENTATIVE DOOGAN asked, "Don't I look at this chart and think that my government is selling Cadillacs in the Gulf of Mexico at sort of Yugo prices here? Isn't that what I take away from this display? I mean, they're cheaper than Chevies, because they're over to the right, but they're better cars, too, 'cause..." 2:48:41 PM MR. ZAGER said a person could reach that conclusion, and he said he is not here to argue about any aspect of this. He said he hopes his data is somewhat objective. He stated his view of the industry as extremely competitive in terms of gaining access to opportunities. He continued: You've probably heard people say that internationally it's becoming more difficult to gain access to many areas of the world. And so, when an opportunity comes up, you've got to capture it if you think it's high quality .... So, industry ... voluntarily moved themselves to the left, by putting $2.9 billion up front. And you all know up front costs are going to hit your [market percentage value (MPV)] more than anything. [Industry] moved it to the left, because of the opportunities and because of the fiscal terms. 2:50:01 PM MR. ZAGER turned to slide 12 of the PowerPoint, which read as follows [original punctuation provided]: Summary Comments  ‡ You have the power to increase short term state revenue through raising taxes ‡ Energy companies have the responsibility to invest where they see the best risk/reward ratio ‡ The common enemy is decline, ‡ Investment is the only way to stem decline ‡ How do you price Alaska's product ? „Lowest possible taxes and stability will encourage investment ‡ Chevron intends to invest and grow in Alaska, but ACES makes investing in Alaska more difficult MR. ZAGER, regarding taxes, said it is debatable what will happen ten years out. He stated, "Assuming there aren't more tax changes, it's not controllable by the state completely, in terms of what the production level will be." Mr. Zager said he has heard people say that oil companies are threatening to withhold investment from Alaska. He emphasized that from the perspective of Chevron, nothing could be further from the truth. He explained, "We're simply trying to convey the economic reality that increasing taxes will make Alaska investments less attractive." He stated: My job is still to try to gain as much funding for Alaska as possible to keep my 500 employees fruitfully working. It's just that the job would be that much ... more difficult when we're trying to stack Alaska up against other opportunities either in the U.S. or worldwide. The committee took an at-ease from 2:52:21 PM to 3:02:58 PM. 3:03:06 PM PAT FOLEY, Manager, Lands and External Affairs, Pioneer Natural Resources Alaska, Inc. ("Pioneer"), introduced Mr. Sheffield and said his presentation would: serve to reintroduce Pioneer as a corporate entity; familiarize the committee with Pioneer's process in making capital investment decisions, what other projects within the company compete for its capital, and where Alaska might fall within that list; share a project update on Oooguruk; and conclude with specific comments on PPT and ACES. He stated that the bottom line is to ask the legislature to "resist the temptation to make any negative changes that would make the fiscal environment less attractive to a new investor." He deferred to Mr. Sheffield to offer the PowerPoint presentation. KEN SHEFFIELD, President, Pioneer Natural Resources Alaska, Inc. ("Pioneer"), showed slide 2 of the PowerPoint and offered some background on Pioneer, noting that although the company has no production in Alaska as of yet, it is new and growing. The bulk of Pioneer's business is in Texas, Colorado, and Kansas. It also maintains a natural gas business in South Africa, and an oil business in Tunisia. In 2006, Pioneer employed 1,600 people worldwide, produced approximately 100,000 barrels of oil equivalent a day. Other than size, he said, one difference between the major companies and Pioneer is that over 90 percent of Pioneer's assets are in North America. 3:06:07 PM MR. SHEFFIELD related the points from slide 3, regarding Pioneer capital investment decisions. He stated that investment opportunities "compete for budget dollars." He said Pioneer and most independent companies prefer projects in the Lower 48, because those projects are closer to the company's infrastructure, are closer to services, and are not geographically challenged, which results in lower risk, lower cost, and shorter cycle times. That gives the company a significant amount of flexibility, he explained. Mr. Sheffield said Pioneer looks for projects that will give the company 10 percent annual production growth, will guarantee at least 100 percent - if not more - reserve replacement, offer as low a finding and development cost as possible, and meet certain economic and financial metrics, such as internal rate of return and discounted return on investment. Pioneer also considers project economics over a broad range of potential outcomes, as well as based upon a variety of "price calls." He said out of all the projects Pioneer is considering for 2008, about 75 percent of them will be funded; those that don't get funded will be deferred if possible. 3:09:38 PM MR. SHEFFIELD referred to slide 4, regarding competition for Pioneer Capital. He stated that rising commodity prices have improved the outlook for oil and gas investments worldwide. Rising costs have taken a bite out of those margins, but those margins have increased nonetheless. He said one trend is to see budget dollars flow to low risk resource plays, including tight sand investments, coal bed methane projects, and shale gas. He explained the reason for this trend is that with the higher commodity prices, corporations can meet their objectives without having to take "the higher risk." Mr. Sheffield listed the low risk, short cycle projects: oil drilling in West Texas, gas drilling in South Texas, and gas drilling in Colorado. He noted that Pioneer is also "competing against" a growing gas business in South Africa and a growing oil business in Tunisia. Furthermore, he said, Pioneer has a business development group looking for new opportunities, primarily in the Lower 48. 3:12:52 PM MR. SHEFFIELD mentioned that he has heard Alaska's "take" is in "the mid-60s range." In response to Chair Olson, he said the average take in the Lower 48 is in "the mid-40s." 3:13:07 PM CHAIR OLSON asked, "So, ... the ... bill that's in front of us would be significantly higher: 20 points?" 3:13:12 PM MR. SHEFFIELD answered that's correct. 3:13:26 PM MR. SHEFFIELD directed attention to slide 5, regarding Pioneer's Alaska entry. He said that five years ago, the company put together a SWOT analysis, which stands for "strengths, weaknesses, opportunities, and threats." The strengths listed for Alaska are its prolific petroleum system, high impact opportunities, its location in North America, and the ELF policy and available exploration incentive credits (EICs). The opportunities that Pioneer noted are that business opportunities are opening for independent investors, while the weaknesses are that operations and transport costs would be high, the project cycle times would be longer, and the regulatory processes would be complex, although workable. The threats perceived by Pioneer regarding entry into Alaska include the possibility of the tax policy changing, and the project delays or cost overruns resulting from working in a remote Arctic environment. MR. SHEFFIELD said Pioneer still thinks Alaska has a great petroleum system, but it has been disappointed in the reservoirs it has encountered through its drilling. He explained that those reservoirs have been found to be of lower quality than expected. Furthermore, he said, the company has found that conducting business in the state is a little more time consuming and challenging than expected. The regulatory processes are complex. Actual costs have been much higher than anticipated, he noted. He said Pioneer is about half way through its Oooguruk project - ending the construction phase and about to embark on the drilling phase - and, to date, is approximately 25 percent over on its capital expenditures, which translates into about $70 million over budget. He said Pioneer participated in approximately 11 exploration wells in the last five years, and almost all of them have run at least a third over predicted budget. He stated that the tax policy was uncertain five years ago and still is uncertain today. 3:18:08 PM MR. SHEFFIELD, in response to Representative Neuman, offered his understanding that the structure of the EICs five years ago is similar to what is in the existing PPT law. He deferred to Mr. Foley for further comment. 3:18:43 PM MR. FOLEY confirmed that Mr. Sheffield's statement is correct. He expounded: Under ACEs, under PPT, all it really does is preserve the existing EIC program, and that system ... allows an explorer to take a credit of 20 percent for drilling an exploration well if it's three miles away from any other well. And they can take an additional 20 percent, for a total of 40, if the well is much more remote. And there are also credits available for a seismic program, which I believe also are 40 percent. 3:19:27 PM MR. FOLEY, in response to a question from Representative Neuman, said Pioneer has a single project that it is currently pursuing in Cook Inlet, which is called the Cosmopolitan Project, and it is offshore from Anchor Point. In response to a comment from Chair Olson, he confirmed that it is "a potentially significant project." 3:19:51 PM REPRESENTATIVE NEUMAN offered his understanding that the investment credits there are different from the rest of the state. 3:20:00 PM REPRESENTATIVE DOOGAN, regarding investment credits, asked if Pioneer's work on the slope qualified for the 40 percent [credit]. 3:20:22 PM MR. FOLEY responded that Pioneer has participated in several exploration wells on the North Slope, and the credits have varied from 20 to 40 percent. 3:20:49 PM REPRESENTATIVE DOOGAN asked if the Alaskan EICs are the only tax credits that are available, or if the federal government gives credits, as well. 3:21:02 PM MR. FOLEY responded that he is not aware of any other credits that "we" receive from the federal government. 3:21:20 PM MR. SHEFFIELD returned to the PowerPoint, to slide 6, which highlights the Pioneer Alaska profile. He said Pioneer entered Alaska in 2002 and began its Oooguruk project. The company became the Cosmopolitan unit operator, he noted, and that unit is drilling just over one mile and deep and three miles under Cook Inlet. He said Pioneer made its first investment in this known oil discovery back in 2005 and, in the last two years, has taken over as operator and increased its interest to 100 percent. He stated, "We upped the ante on this project, based upon PPT law, and we believe that maintenance of the PPT structure is critical to the viability of this technically and economically challenged project." MR. SHEFFIELD said in addition to Cosmopolitan, Pioneer also owns interest in about 1.5 million acres - some of it in and around Prudhoe Bay and Kuparuk River Unit, and some of it out in NPR-A. He said Pioneer has participated in 11 exploration wells, and other than identifying the resource at Oooguruk, the company really doesn't have much to show for those investments. 3:23:48 PM MR. SHEFFIELD, in response to a question from Representative Neuman, explained that low quality rock was discovered at Cosmopolitan in the late 1960s, and Pioneer is investing in determining the extent and productivity of the resource there, so that it can make an educated decision on whether or not to move forward. 3:24:24 PM MR. SHEFFIELD moved on to slides 7 and 8, which offer a summary of the Oooguruk project. He continued: As you can see in the aerial photo, our Oooguruk project is nearing the end of the construction phase, and we anticipate spudding the first of approximately 40 development wells next month. Oooguruk is the largest single capital project in our company's history; we are the operator with a 70 percent working interest in a project that will cost over half a billion dollars. First production is anticipated in 2008, and peak flow rates are expected in the 2010 timeframe at approximately 15-20,000 barrels per day. We've come a long way and faced many challenges to get to the point where we can start drilling. From our first well in early 2003, we evaluated and sanctioned a major off-shore project in the Arctic in less than three years. We permitted a complex project with a diverse group of government agencies and stakeholders. In 2006, we constructed an armor to Gravel Island, installed a complex, sub-C flow line bundle, and fabricated and installed facilities in a remote, logistically challenged setting. At peak of construction, we had over 600 workers up on the slope, and if you look over the last couple years, we probably averaged over 400 workers on the [North] Slope. We are now poised to begin a three-year develop drilling program, and we are looking forward to first oil in 2008. 3:26:08 PM MR. SHEFFIELD talked about the benefits that the Oooguruk project will generate, as shown on slide 9. He said Pioneer is poised to be the first independent oil producer on the North Slope, as well as the first independent to gain facility access into one of the major units. Other investors, he said, are watching to see if Pioneer is successful. The tangible benefits of the Oooguruk project to the state of Alaska would be from the royalty plus 30 percent of the net profits tax, PPT revenues on Pioneer profits, state income tax, property taxes to the borough, jobs in construction and operating, and the profits that will be generated through those expenditures. 3:27:25 PM MR. SHEFFIELD moved on to slide 10, which lists the Oooguruk capital expenditure beneficiaries - the major contractors on the project. 3:27:50 PM REPRESENTATIVE SAMUELS asked if the lease under which Pioneer is operating is still owned by ConocoPhillips Alaska, Inc. 3:28:24 PM MR. FOLEY offered a brief history, noting in conclusion that the leases have been assigned from ConocoPhillips Alaska, Inc., to Pioneer. 3:29:02 PM REPRESENTATIVE SAMUELS asked Mr. Foley if it would be fair to say, "It was worth your risk; it was not worth their risk." 3:29:24 PM MR. FOLEY said he can only speak from Pioneer's perspective, which is that it was worth the risk. 3:29:35 PM REPRESENTATIVE SAMUELS said if he makes the assumption that ConocoPhillips Alaska, Inc., chose not to develop that area because it was not worth a big company's risk, then if Pioneer had not picked it up, that oil would still be sitting under ground. 3:30:16 PM MR. SHEFFIELD responded that Pioneer drilled the three exploration wells and made "a completion in the Jurassic formation," and the results of the test gave the company encouragement that the long-known resource could potentially be economic. Therefore, the work that Pioneer did actually improved the knowledge base on that resource. At that point in time, he said, Pioneer was looking for a sizeable development project to help in meeting its corporate return, so it made sense to "kind of take that next step." 3:31:23 PM MR. SHEFFIELD, in response to a question from Representative Samuels, estimated that the difference in market cap is in the range of 20 fold. REPRESENTATIVE SAMUELS said, "So, they're 20 times as large as you are." 3:31:36 PM REPRESENTATIVE DAHLSTROM asked if it would be accurate to say that it was insinuated that all the companies saw the same seismic activity. 3:31:52 PM MR. SHEFFIELD said all companies had similar databases. He stated: I don't think that specifically that the seismic data was the driver. It was a known resource; wells had penetrated this horizon before. I think that through the completion that Pioneer did on one of our wells - and we actually tested the well - it kind of gave us a little bit of encouragement that this whole ... resource that had been known for some time - that we might be able to take it to the next level with new technology. 3:32:33 PM MR. SHEFFIELD returned to the PowerPoint, to slide 11, which addresses Pioneer's view on PPT. He stated that PPT was "rolled out" without Pioneer's consultation. When the bill was released in early 2006, he said, Pioneer was already committed to the Oooguruk project and already had significant exploration commitments, both in the Central Slope and in NPR-A. After seeing the tax rates go up from zero to over 20 percent, he noted, Pioneer took time to work through PPT mechanics and found it to be a balanced system where investment tax credits help offset the tax rate. He stated that Pioneer finds PPT to be a modest incentive for additional investment; it encourages the development of the abundant lower tier resources in Alaska. Mr. Sheffield said, "We feel that some of the lower ... quality reservoirs are a big part of Alaska's resource future, whether they be challenged by size, or reservoir quality, viscosity, or just the fact that they're not close to infrastructure." He said Pioneer also believes that PPT is fair and sustainable over a broad range of investments. He added, "We think PPT, over time, should grow the pie and give the state a bigger slice." 3:34:51 PM MR. SHEFFIELD highlighted slide 12, which addresses Pioneer's belief that ACES erodes modest PPT incentives. He explained, "It's really not any one thing, but the cumulative effect of the changes." Two changes that are negative for the investor, he said, are the base tax rate increase from 22.5 percent to 25 percent and the tax rate increase through a more aggressive progressivity formula. Regarding the next negative factor listed - transitional investment expenditures (TIE credits) eliminated - Mr. Sheffield said Pioneer's position on that has possibly changed in the last 24 hours. He explained: Our interpretation of ACES would be that we wouldn't be able to recover that $100 million - the credits related to the $100 million that we spent on the Oooguruk project. But our ... tax person has been visiting with some tax folks from the administration, and we now believe that because Pioneer has been ... spending so much money, we ... do believe that since PPT effective date to the end of 2007, that Pioneer will have spent 2:1 on that sunk $100 million investment. And we believe - although we still would like some clarification - that we will be able to ultimately recover those TIE credits that we've earned. 3:36:06 PM REPRESENTATIVE DOOGAN asked Mr. Sheffield to confirm whether or not Pioneer would return to saying that ACES has a negative impact if it had a retroactive effective date. 3:36:24 PM MR. SHEFFIELD replied: What I'm saying is our interpretation of the way the ACES bill is written today, with some verification, we believe that maybe we've already earned those, and they'll be available to us in the future. Twenty-four hours ago, our interpretation was that we would lose all those credits, even though we've been aggressively spending 2:1 on the capital that we spent prior to the effective date. 3:37:04 PM REPRESENTATIVE NEUMAN said some people would argue that TIE credits give away Alaska's money, and that sentiment concerns him. He questioned what would have happened regarding Oooguruk if that $100 million had not been there for Pioneer. He asked Mr. Sheffield to comment. 3:38:26 PM MR. SHEFFIELD said the issue for Pioneer is that it sanctioned the Oooguruk project under ELF and spent quite a bit of money prior to the implementation of PPT - about $100 million. Now, instead of being taxed at the ELF rate, any profits made will be taxed at the PPT rate. The PPT legislation, he said, set up a framework for Pioneer to earn "that sunk capital," and Pioneer "stepped up to the plate and earned that back by spending 2:1 on our sunk capital." 3:39:21 PM REPRESENTATIVE NEUMAN proffered: And that's why, in ... Pioneer's view of PPT that you felt it's sustainable and fair across a broad range of investments. MR. SHEFFIELD answered yes. REPRESENTATIVE NEUMAN added, "And without that, you probably wouldn't have had that sentence in there?" 3:39:46 PM MR. SHEFFIELD admitted that the issue is confusing. He said Pioneer has been following the capital rules created for the transition from ELF to PPT and wants to make certain that "we're kept whole when we've lived up to our end of the bargain." 3:40:18 PM REPRESENTATIVE NEUMAN said every oil company, large or small, has said it does not like the spread of earned tax credits over a two-year period. He asked Mr. Sheffield to explain. MR. SHEFFIELD explained that a credit that can be cashed in today is worth more than one that can be cashed in next year. He characterized the issue as significant, but not huge. In response to a question from Representative Neuman, he said he can understand why a smaller company than Pioneer may more strongly object to [the two-year spread of tax credits]. 3:42:04 PM REPRESENTATIVE HOLMES directed attention to slide 9 and the mention of royalty plus 30 percent net profits to the state of Alaska, and she asked Mr. Sheffield to explain the 30 percent. 3:42:33 PM MR. SHEFFIELD stated that the 30 percent net profits are "embedded in one of the base leases that overlies Oooguruk," so it is part of Pioneer's lease obligation to the state. He added, "And then, we would pay PPT on top of that." 3:42:54 PM MR. FOLEY noted that there are a handful of leases on the North Slope that have both a royalty and net profit component but are not a large contributor to the state economy. However, a third of the money that would flow to the state of Alaska from Pioneer's Oooguruk project comes from the net profit component, he said. The committee took an at-ease from 3:43:41 PM to 3:45 p.m. 3:45:30 PM MR. SHEFFIELD returned to slide 12, and said Pioneer believes that increased taxes potentially jeopardize lower tier project funding. If the lower tier resources go unfunded, it is not good for the state or the economy. He said the Oooguruk project has probably the highest take of any project in the state of Alaska, and Pioneer is concerned that its Oooguruk returns would be reduced, in which case the company would be less likely to fund similar projects in the future. Mr. Sheffield listed some positive elements to come from ACES: it retains the net tax framework for the non-legacy fields, and it allows credits to be monetized at face value, with some time delay. He said Pioneer believes that the only way higher taxes make sense is in a net regime. 3:47:06 PM MR. SHEFFIELD directed attention to slide 13, which is from the Department of Revenue and shows the projected impact of ACES on four new projects on the North Slope. He continued: Our observation looking at this analysis is the [market potential value (MPV)] of those four projects was eroded by an aggregate of about 50 percent. And if these projects were in our portfolio, they would be much less likely to be funded. We believe that ACES reduces the competitiveness of Alaska investments, and it will make it more difficult for us to build a business here in Alaska. 3:47:47 PM MR. SHEFFIELD moved on to slide 14. He concluded the presentation by saying that Pioneer's primary competition for capital is the Lower 48. The company has been an aggressive investor, but it requires fiscal stability. He said PPT provides both the balance and the stability for Pioneer to grow in Alaska, while ACES erodes modest PPT incentives. Finally, he related, raising taxes on the abundant lower tier projects in Alaska risks the funding of those projects, which would put at risk royalty, state income tax, property tax, and jobs. 3:49:03 PM MR. SHEFFIELD, in response to a question by Representative Doogan, said that Oooguruk is an isolated field that is not geologically connected to the Kuparuk field, but it will be tied in to the infrastructure of Kuparuk by an eight mile flow line. The committee took an at-ease from 3:50:35 PM to 3:58:21 PM. 3:58:24 PM MARK HANLEY, Public Affairs Manager, Anadarko Petroleum Corporation in Alaska (APC), emphasized the importance of clarity and said he would discuss resource potential and risk. 3:59:57 PM MR. HANLEY turned to slide 2 of his PowerPoint presentation. The slide shows a map of all the areas worldwide where APC explores for and produces oil and gas. He said APC is a large, independent company that is not integrated and, thus, does not typically have pipelines, refineries, or gas stations. He referred to slide 3, which shows on a map the areas where APC has a position as operator, where it has positions where it is not the operator. He talked about investing and relinquishing land; spending money to make discoveries. He indicated that when people consider rate of return, they don't think about the fact that the company has to cover risk, lease payments, and seismic work, for example, even when it does not find anything. 4:04:47 PM MR. HARVEY projected a slide from an Econ 1 presentation given during discussion of PPT. He mentioned "prospectivity." He indicated that the slide shows United States geological survey (USGS) estimates of the central North Slope's undiscovered, technically recoverable oil reserves. The mean estimate of reserves to be discovered is 4 billion barrels, but the amount of fields smaller than 64 million barrels is 51 percent. Mr. Harvey reminded the committee that a 50-60 million barrel field, if not within about 10 miles of existing infrastructure, is not economic. The best place to find oil is where it's already been found. Mr. Harvey said APC is one of the companies that think there "are a few more alpines out there, which are these 500 million barrel fields." 4:07:34 PM MR. HARVEY said risk and prospectivity needs to be considered when considering government take. He stated, "If we had 800 [Tcf] sitting on the North Slope, I can guarantee you we'd be having a little different discussion right now, and government could probably justify taking a higher take than you can with 35 [Tcf] sitting up there and challenged economics." 4:08:15 PM MR. HARVEY indicated a slide of the Arctic National Wildlife Refuge (ANWR). He continued: Remember before, on the North Slope, we had about 4 billion of technically recovered [oil] in those smaller field sizes. Here you see a price factor put on it. So, at $50 a barrel, you can see $2.66 billion or at 63.2. So, ... for every $10 dollars here you've got another 600 million barrels of recoverable oil. Between 40 and 50, it's 700 million. ... And so, what I want to put in perspective, just so you know, is: what is the impact of this tax thing? One of the slides that the administration showed, and I'll show it to you later, showed that the current PPT raised, under their estimates, at $60 a barrel, about $1.3 billion, and their ACES is about two, so call it $700 million. ... 700,000 barrels a day is about, I think, 240 million or 250 million barrels per year. Okay, so what's that on a per barrel basis? Give or take, it's about $3 a barrel, right? ... So, $3 a barrel is the cost on a per barrel basis, ... just [to] give you a rough idea. So, at least with this chart you can see, at least through USGS, well I can't tell you exactly, but if you take this from 60 down to 57, you know there's some linear thing, it's 150-200 million barrels that is ... not economic overall. Can I tell which field that is? I cannot. But ... when you're looking at this overall, there is an impact - $3 a barrel is an impact. How big an impact, which field is it going to do, how much risk is there in a specific field? You know, all those get affected. But again, just remember this is not heavy oil, this is not existing fields. So, if you were to do this ... - I think some other companies have shown you what they think the economic impacts are on infield drilling, maybe, at Prudhoe, and offshore stuff. And again, the other thing to remember, is this is oil, not gas, that [is] out there. But again, I just want people to understand: the oil that's out there tends to be in smaller fields, and there is - even if you're just using generic terms - an impact of $3 a barrel that's going to have some impact. And you could actually [ask]: "... If over 20 years I lost 200 million barrels, how much would that cost the state, ... [including] take and everything else?" So, you can get some idea and roughly do it, but then you'd have to apply that to, you know, NPR-A, offshore, anything that's open, infield stuff, and you'd start getting an idea: "Okay, we're raising 700 million a year. How much is it?" And I don't know, I don't know what it comes out [to be]. But there's an impact, and I guess that's my main point is that it has to have -- and I will show you later on. And so, that's all I had from these slides, but I thought it was a real good representation. It's their presentation, but it really shows you this prospectivity issue, as well as how the price can affect -- and on this slide, like I said, ... these are probably a number of years old, and the cost factors are changed, but the concept's still going to be the same; there's going to be some impact. 4:12:17 PM MR. HANLEY returned to his APC PowerPoint presentation, to slide 4, which is titled, "Alaska Opportunities." He talked about the world class petroleum basin and said there is a significant amount of petroleum to be found in "legacy-type prospectivity - anchor fields. He defined an anchor field as one that can sustain its own infrastructure, is not tied back through another facility, and is "kind of an alpine thing" with probably 400-500 million barrels of oil. He mentioned a 2 percent chance, and he said APC's people think there is a chance to find some of those fields, which would open up satellite opportunities around the field. These fields tend to be higher risk, but they also tend to yield higher reward. Mr. Hanley said APC thinks there are currently a lot of opportunities to partner with new entrants up to Alaska. He stated that having more companies drilling wells is a positive thing. He explained that not all companies can sustain 10 dry holes, but if there are several companies each drilling three holes, for example, then there will be a couple discoveries, and that will "focus people in a direction." This method allows APC to partner and take more risks. 4:15:30 PM REPRESENTATIVE NEUMAN noted that the committee had heard from one of the oil economists who said that Alaska only needs enough companies to produce the oil that Alaska has, and he said that contrasts with Mr. Hanley's statement that the more players there are, the better. 4:16:31 PM MR. HANLEY acknowledged the state's perspective could be that it only needs the minimum number of drillers to get the job done. The problem with that, he said, is there are a lot of unexplored acres and it would be ideal to have 15 holes a year drilled for 10 years to maximize the potential for discovery, which means more companies drilling and trying out different concepts. He offered examples of new exploration rigs in the state. He said the PPT and net profits approach encourages that. 4:19:33 PM MR. HANLEY moved on to slide 5, which addresses challenges in Alaska. The basin is maturing and there is still a lot of oil left to be found, but it tends to be in smaller prospects/fields. Those smaller prospects attract different kinds of companies. Other challenges, he noted, include a lack of infrastructure and competition, long lead-time exploration, and seasonal drilling. He offered examples. 4:23:40 PM MR. HANLEY projected slide 6, which shows APC's view of PPT and a recap of the 2006 testimony. He said, "You raised a bunch of money on existing fields, but you created this new system for new fields that was beneficial, ... effectively reduced our cost of capital, and helped us with our net present value analysis." If we're out drilling a lot of wells, doing a lot of exploration, which is what the state's trying to encourage, then we are able to offset that ... higher tax rate at Alpine. And so, you're getting what you want. As long as you keep investing in the state, you can keep that tax rate down. And that's a positive thing from our perspective, particularly from a company that ... has explorations acres [and] wants to go out there. So, the whole system set up, in our view was a positive, even though we had a tax increase, for instance, at Alpine. 4:25:14 PM MR. HANLEY, referring to slide 6, said the company has seen an overall improvement in exploration economics compared to the old ELF system. He said the old 25/20 was worse in regard to exploration economics than the old ELF system. He added, "And that was before you had progressivity, so it would even be a little ... worse." He stated, "On balance, we were supportive of the PPT system." 4:26:22 PM MR. HANLEY moved on to slide 7, entitled, "Support Net Profits Approach." APC appreciates the administration's work in evaluating gross versus net and its conclusion to stick with the net system. He said he thinks a gross system could be designed, but it would be complicated, and credits would have to be offered. Once credits are offered, there must be a differentiation between operating costs and capital costs. He named the four areas related to the gross system: existing fields, satellite fields, frontier exploration, and heavy oil. The economics for each is significantly different. 4:29:10 PM MR. HANLEY directed attention to slide 8, which shows APC's view of ACES is that the negatives outweigh the positives. Some part of ACES is support by APC, for example, the expansion of time to qualify for the exploration incentive credits; however, that positive is offset by a lot of new exclusions and restrictions. Regarding equity, he said, while ACES does not directly affect APC, it does directly affect the company's partners. He offered an example. He stated, "In our view, the tax rate and the carry forward should be the same number." He said APC would prefer that the administration's proposed tax rate of 25 percent be lower, but it is matched for the net operating loss, which he said he thinks is fair. He said, "To the extent this helps attract people who have worked in industry or understand the industry, I think that's a positive thing, so we'll do that." 4:32:46 PM MR. HANLEY, regarding stability, stated concern that PPT and ACES be revisited again in the next few years to deal with gas. He said, "I can tell you from our perspective, these rates are too high for gas." He opined that the state needs to do something to make gas economic. In the next two years, he said, the industry will be back before the state government talking about gas tax rates. He said that discussion is inextricably linked with oil. Mr. Hanley listed the top three concerns: the tax rate increase from 22.5 percent, the tax escalator, and the transition investment expenditure credits elimination. Regarding the tax escalator, he offered an example in which, at $40 net, there would be a 2 percent higher tax rate under the ACES plan. He said, "Where the numbers are exactly the same is at $80 net." He emphasized the importance of being on the same page with the administration. 4:37:28 PM MR. HANLEY, regarding the elimination of the transition investment expenditure credits, said, "Geez, if we'd have known that you were going to change this thing, we would have changed our decision - we would have absolutely waited." He explained that APC spent money in '05-'06 to get a satellite on line, and if the company had known it would be hit with a higher tax rate without transition credits, it would have waited. He offered further details. The policy call is how far back to go in letting people collect money and how much a company will get into the future. Originally, he said, "it was 1 for 1, and they changed it to a 2 for 1," which meant having to invest at least twice as much money to bring forward one dollar to get the credits. He said this is an issue of fairness. He emphasized the impact that tax decisions have in a company's decisions. 4:40:48 PM MR. HANLEY directed attention to slide 9, which shows the administration's field economics estimates. The table is from a presentation from the administration given on September 4, 2007, and it shows a project net present value of cash flows, with a 10 percent discount rate, and with field/projects A, B, C, and D. The table shows that for each project, the economics decrease anywhere from 33 percent to 54 percent. Mr. Hanley said he does not know what geological and commercial risks were assigned in this table, nor where the dry holes are and whether failed projects were accounted for. 4:44:33 PM MR. HANLEY turned to the summary on slide 10, which is: "Significant tax increases outweigh any potential benefits." He mentioned the time when APC pitched the idea of PPT or a net profit system. He said the old ELF was a regressive system; at high prices it was good for companies, but on the low side, it was not. He said the state actually still has a gross and net system, because the royalty is really a gross tax, in APC's point of view. The old system took less at high prices. The PPT took more of the high side but it actually "gave up some" on the low side. On balance, he said, that was one of the things about PPT that helped, because it gave some downside risk protection for the companies. With a 10 percent floor, Mr. Haley said, it is like the state is taking the low side and the high side, and he posited that this is imbalanced and shifts the risk even more significantly to the industry. That is why the state will find opposition from companies, he concluded. 4:48:09 PM REPRESENTATIVE DAHLSTROM expressed her appreciation for Mr. Haley's ability to comprehend the responsibility the state has as well as the corporate responsibility to find a balance. The committee took an at-ease from 4:49:17 PM to 4:55:05 PM. 4:56:16 PM DAN E. DICKINSON, Certified Public Accountant (CPA), stated that he works in local practice but is giving this presentation on behalf of the Legislative Budget & Audit Committee (LB&A). He noted that all the information is on the LB&A web site and his presentation would follow the order found on that site. 4:57:28 PM MR. DICKINSON directed attention to slide 3 of his presentation, which shows Alaska oil production from 1965 projected to the year 2020. The majority of the oil produced has come from Prudhoe Bay, production beginning in 1977 and peaking in 1989 at 1.6 million barrels a day. The peak, including production from all other fields, totaled 2.1 million barrels a day. Since that time there has been a decline, and today, Prudhoe Bay is producing less than 400,000 barrels a day, and all fields combined are currently producing approximately 700,000 barrels a day - one third of the production of twelve years ago. He continued: During this time, the royalties were a much larger piece of the state's fiscal system. ... As production fell, the economic limit factor fell even more dramatically, and the production taxes ... [went] from being twice what royalty was, essentially, marching down towards zero. People were very concerned about the decline; they were very concerned about investment. That was the major focus; it was certainly Governor Murkowski's major focus. And in that context, tax was really treated as one of the fiscal tools that the state had, and it really was viewed as a tax. By that I mean in the sense it was an act of the sovereign authority to go out and look at certain activities within the society and say those should be bearing some portion of the society's total burden - it really is part of the tradeoff between those in our society who were the most fortunate, and those that are less fortunate. 4:59:47 PM MR. DICKINSON discussed figures pertaining to slide 4, which is a graph showing the Alaska North Slope West Coast price from July 1977 to September 2007. Since the low point of less than $10 a barrel, there has been a dramatic increase in oil prices. Even counting inflation, prices are higher than they were back in 1980 when they hit a nominal peak of $35, he said. He continued: And in this time the conversations have changed. We're not really talking about a tax in the traditional sense anymore. We're basically talking as if there was a new ... deal out there; there's a new bid around. We want to talk commercial deals; we don't want to leave money on the table. There are lots of other resources that the state obliges you to manage for the people's benefit, but we don't talk about making sure that there's no pennies left in anyone's pocket on that that we haven't over hit. So, the whole conversation now is really driven, I think, by the profits that are being made, and that's changed the conversation. Nonetheless, we still are a tax system. 5:01:06 PM MR. DICKINSON projected slide 5, entitled, "Increasing Costs." He stated, "I think we've all heard the story: Things were down around $2 billion. We came in and the PPT was passed, and since then they've gone up to about $4 billion." The first graph shows the state's general fund budget, he noted. He said if people had predicted 5 years ago what would happen to the state budget, nobody would have said it would double. He relayed that when people consider their tax system, they talk about revenue sufficiency. Mr. Dickinson said governments put taxes in place so that they can raise money for their operations. People don't typically ask, "Well, how much did the other guy get?" The concern is whether government gets enough to fund what it is doing. And when the discussion turns to bid rounds or talking about whether "the other guy" gets more profit, then the talk has changed into something very different. 5:03:13 PM MR. DICKINSON turned to slide 8, entitled, "Historical and Forecasted Budget Surpluses and Deficits FY 2000 to FY 2020." The chart on slide 8 shows a projected deficit in the year 2010, which will increase to $1 billion by 2011 and $3 billion by 2015. He said the question is whether each time that deficit increases will be reason for the state to reevaluate and see whether or not it "left some money on the table with the industry." 5:03:50 PM MR. DICKINSON addressed the subject of information, which is outlined on slide 9. He said information forms judgment, and the big mistake "the team" made in presenting PPT was in "not requiring a lot more information up front." He stated, "I believe that what the governor's proposed to do makes a lot of sense; people need to be comfortable with what's going on." However, he said he would like to challenge some of the things he has heard and to review what happened in the last fiscal year, [as shown on slide 10, entitled, "FY 2007 first snapshot."] He continued: When most of you left the regular session in the end of 2006, ... you had passed a budget. ... And that budget you had based ... on what the Department of Revenue had said revenues were going to be. And we had said, "There's going to be $3 billion coming in oil and gas revenues, there's going to be $400 million coming in non-oil and gas, for a total budget of $3.4 billion. ... You had authorized ... general fund spending of $3.2 billion for a surplus of $200 million dollars. What happened? ... You passed the PPT. And on the fiscal note for that it said because of retroactivity there's going to be FY 06 PPT revenues generated in April, May, and June. They're going to come in, in ... fiscal year ... and in calendar year 2007, plus you're going to have FY 07 payments made in calendar year '06, but in FY 07 - so one's for the actual year - of $923 million. So, the total increment for FY 07 will be $1.3 billion. And so, at the end of the special session, you can take the $959 million that we said was going to be generated in the production tax under the ELF - under the old system. Add to that an additional $1.3 billion in PPT to come out with a total of $2.3 billion, so you're total oil and gas is 4.3. Obviously non-oil and gas and everything else stayed the same. So, you're now looking at ... a total coming in at $4.8 billion dollars. As I said, there's a slight source difference here, so there's a slight difference I don't understand there, but the general point is: the surplus was going to be $1.3 billion. 5:06:59 PM MR. DICKINSON continued: Okay, let's fast-forward: What actually happened; was there a shortfall? And the answer is no. ... This is spring forecast 2007, so it comes out, I believe, in April, so it's not quite to the end of the fiscal year, ... but I think this is pretty accurate. What happened is the total oil and gas was $4.3 billion - about ... $23 million less than had been projected. Non-oil and gas went up by about $150 million. So, the total amount that actually came in was slightly higher than the amount ... [of] the forecast that your budget had been based on. ... If you look at the additional supplemental authorizations that were made, some which were forward funding, ... that exactly equaled the general fund appropriations, and so, there was no surplus for the [Constitutional Budget Reserve Fund (CBRF)] that year. So, the point is, the total revenue projection was $3.5 billion; the total amount that came in was $4.3 [billion]. 5:08:09 PM MR. DICKINSON said it is interesting to note that the Department of Revenue's estimate for oil and gas production tax was the closest estimate of any that was created. He said that fact could be called lucky, because prices and costs were underestimated, production was overestimated, and those factors cancelled each other out. 5:09:53 PM REPRESENTATIVE DOOGAN asked if Mr. Dickinson is addressing the administration's assertion that PPT brought in $800 million less than predicted. 5:10:31 PM MR. DICKINSON indicated that he may be. He said he has heard people talk about an $800 million shortfall many times and he is not certain what that means. He described factors that may lead to a discrepancy in the numbers. 5:11:31 PM REPRESENTATIVE DOOGAN stated: I'm not sure how useful what you just told me is. People have been shifting numbers here more than once since we sat down at this table. I've objected every time, and now I'm objecting to you. If the discussion over the ... revenue sufficiency of PPT - if I can use that phrase - is based on a set of numbers that show that there's $800 million less than were predicted at the time the bill was passed - which I want to say is not particularly important to me, because I didn't cast any votes, so I wasn't relying on those projections - then it's not particularly useful for me for you to come in here and tell me if we look at these numbers in a completely different way we get a different result. If what you're saying is that that statement is wrong, then I'd like you to prove that to me using the same method that they used to make it, if you can. ... And if you can't, then I want you to explain what value this number has to me in this debate. 5:12:57 PM MR. DICKINSON said he will try to address Representative Doogan's request. 5:13:18 PM REPRESENTATIVE DOOGAN said he does not care if the number doesn't turn out to be $800 million, as long as "we're talking about the same thing." 5:13:25 PM MR. DICKINSON said the question he would ask is: How would a better forecast have made a difference during this last year? He said he is attempting to separate regulatory control issues from fiscal policy issues. He said he believes in offering more information as opposed to less; however, getting that information will not necessarily make the situation better. 5:15:21 PM MR. DICKINSON directed attention to [slide 15], which shows a simple model of FY 08 production tax revenue. He talked about the model in conjunction with the governor's proposal. Regarding the $800 million, he proffered: ... If these rules were in effect for all of ... FY 08, and we use the current modeling assumptions, the difference between PPT and the governor's proposal would be roughly $800 million. ... I believe that's what's being said. 5:25:36 PM REPRESENTATIVE DOOGAN responded, "That's not what's being said." He continued: What's being said is that there was a fiscal note that indicated or said how much money the bill that passed was going to raise, and ... in fact, the bill that passed raised $800 million less than what was listed on the fiscal note. Now, I'm not saying it's true, but I'm saying that is what is being said. 5:26:03 PM MR. DICKINSON stated his belief that if the dollar assumptions were put in the fiscal note, a person would not have arrived at that number. REPRESENTATIVE DOOGAN responded, "So, you just think they're wrong if that's what they're claiming." MR. DICKINSON answered yes. 5:26:53 PM REPRESENTATIVE NEUMAN offered his understanding that the $600- $800 million was a result of what could be deducted, not the different prices in the tax rate. 5:27:28 PM REPRESENTATIVE DOOGAN said, "That statement was actually made in this committee, as well, in the administration's presentation, that most of the difference was [due to] substantially higher costs that had been claimed - I think." 5:27:44 PM CHAIR OLSON added, "In addition to Prudhoe Bay being shut down for almost two months." 5:27:51 PM REPRESENTATIVE SAMUELS said he does not know what number was used to generate the $800 million figure. He said the last couple months there was a lower figure of $700 million. 5:28:37 PM MR. DICKINSON said that clearly, in the fiscal note, the cost numbers used were far below the cost numbers that have shown since and are being used for estimations. He said he is not questioning that line of reasoning. He emphasized his point is that in looking at the other assumptions, such as price and volume, it is easy to adjust "some of those and not others" and then say there is some deficit or lack of revenue that flows from that. He clarified that he was trying to look at "what was being said in the fiscal note at the time." 5:29:47 PM REPRESENTATIVE DOOGAN clarified that he was trying to ensure that Mr. Dickinson was addressing the same case that the administration was addressing. 5:30:04 PM MR. DICKINSON reviewed the work to date, which is shown on slide 16. He then turned to slide 17 - which outlines part II of the presentation. He said he would comment in the case of tax rules that are replaced by the discretion of an agency. 5:30:56 PM CHAIR OLSON acknowledged the presence of Commissioner Patrick Galvin of the Department of Revenue. 5:31:09 PM MR. DICKINSON continued. He said he would also talk about when broad and robust rules are replaced with narrow, specific approaches, and situations in which production tax, or features of it, can be made to look more like a windfall profits tax, versus "the notions of the floor." Finally, he said data, although good, does not make the decisions and may not even give all the necessary information needed. In reference to slide 18, regarding rate, Mr. Dickinson issued a caveat on government take statistics. He explained that apples to oranges comparisons are very useful, but he asked everyone to be wary about comparing numbers from various studies with different assumptions. He recommended looking at the rest of the fiscal system. He said some governments encourage high paying jobs with low industry taxes and pick up the difference by other means, such as personal income and consumption taxes. 5:33:26 PM MR. DICKINSON talked about progressivity, which is on slide 19. Regarding switching factors, he said there is a switch from monthly to annually, which typically means lower dollars. He continued: If you have a spike, under the progressivity, it will ... average out. ... I believe that when people were here last year, in the summer of '06, and prices were at $75, people were thinking about that as a spike. And those of us who talked about it as a spike probably have a little egg on our face, because it didn't go back down - or it did, but for a couple weeks - and then it went charging on up. It is less progressive, because it's basically making ... more of a base rate and picking up less at the upside. Clearly, it is administratively more simple; that's one of the things the administration has talked about, and I agree with that absolutely. 5:34:39 PM REPRESENTATIVE SAMUELS said: It had been my assumption that it's a true-up at the end, but you're still going to get -- I mean, the point of the progressivity was to get the spikes .... Is it that the language of the bill says that you're going to average it for the year and then collect it at the end of the calendar or fiscal year, or whatever? 5:35:05 PM MR. DICKINSON answered yes. He offered his understanding that the piece for applying the progressivity will no longer be calculated monthly. 5:35:24 PM MR. DICKINSON moved on to slide 20, which, in terms of progressivity, compares an annual and monthly analysis of FY 08 with a hypothetical spike. He pointed out that with the $40 starting point that is in current law, for nine months out of the year, absolutely no progressivity would be generated; however, in the three months of a spike, the price index goes up, and quite a bit of progressivity is picked up. He highlighted the progressivity over the year as shown in the analysis. He said, "My point here is, a single month at a high rate, when it gets averaged in, you lose the effect." He stated: So, the observation on progressivity is: I believe the most dramatic change probably is the one that stems from the monthly versus annual. It's very, very hard to model, because no one's going to make predictions, and certainly I'm not going to try to make predictions about the upcoming monthly crisis, and whether those spikes are going to occur or not. 5:38:14 PM MR. DICKINSON addressed slides 22-24. The first two are graphs showing the effect of a gross floor - low end, while the latter shows the effect of a gross floor - windfall profits. He offered details. He said to his way of thinking, a gross windfall profits tax makes a lot more sense than a floor. 5:44:41 PM MR. DICKINSON explained that the state's system was regressive for many years, which made sense when Alaska was a young state. Every year, the state knew that cash would come in to cover costs. Today, the state has a savings account with billions of dollars in it - the earnings reserve - and those dollars are available for appropriation. 5:46:01 PM MR. DICKINSON directed attention to slide 25, addressing the issue of ring fencing. If a legacy field is generating profits, that money can be reinvested, and that would still be allowed under the governor's proposal. Mr. Dickinson pointed out a typographical error at the bottom of the slide. The language there should read: "Investment credits and losses generated in Legacy Fields could not be offset by profits generated elsewhere." He explained that a credit within a legacy field has to stay there; if it cannot be used, it will never be used anywhere else. 5:47:32 PM MR. DICKINSON reviewed the information on slide 26 - ".023 Investment Credits." He talked about a 20 percent loss carried forward, why it is not the same as the tax rate, and whether it discriminates against people. He said, "My observation [is that] it is, and I applaud the notion of making the two the same." He addressed the issue of spreading out credits over two year's time and the proposed elimination of TIE credits. Regarding the latter, he said .025(i) in the bill would essentially introduce a "mini TIE"; however, the commissioner of the Department of Natural Resources could authorize credits to people who had done seismic work prior to 2003. He said people talk about the conceptual notion of what people expect when making an investment, and "eliminating the TIE credits would not eliminate that particular concept." Regarding ".024 Non Transferable Credits" - as shown on slide 27 - Mr. Dickenson said the only proposed change in the bill is that those credits could not be applied against the floor. 5:49:22 PM REPRESENTATIVE SAMUELS surmised that in an arena where there were either massively increasing costs or, more likely, a decreasing price where "you hit the floor," the $12 million credit is actually "against their income." 5:49:58 PM MR. DICKINSON confirmed that's correct. He moved on to slides 28 and 29, regarding exploration credits. The new addition to the bill, in .025(b)(3) would state, "costs arising from gross negligence or violations of health safety, or environmental statutes or regulations". The new language in .165(e)(6) would state, "costs arising from fraud, wilful misconduct, gross negligence, violation of law, or failure to comply with an obligation under a lease, permit of license issued by the state or federal government". He said, "In general, I think it makes sense to not have the kinds of things that would not be allowed under, for example, a federal tax." 5:53:28 PM REPRESENTATIVE NEUMAN referred back to slide 26 and stated his concern is that a company spends a lot of money to procure seismic information - to find out about the existing rocks - and it seems unfair that in two years that information becomes public and available to others who did put out the cash. 5:53:42 PM MR. DICKINSON prefaced his response by noting that there is a difference between well data and seismic data. He said companies could chose to keep that information to themselves; they would simply not qualify for the credits. 5:54:12 PM MR. DICKINSON returned to the presentation, to slide 29, which addresses exploration credits and "moving from a rule to agency approval." Currently, he noted, AS 43.55.025(c) requires that a bottom hole be three miles from previously drilled bottom holes, except in Cook Inlet if the Department of Revenue determines the site is a "distinct exploration target." The proposed legislation changes that by putting in place three requirements: before applying for credit, the company must get DNR approval; the company must still meet the three-mile requirement if the site is not in Cook Inlet; and the company must get DNR approval "afterwards" to apply for the credit - to confirm that everything was done as promised. 5:55:37 PM REPRESENTATIVE SAMUELS asked if, by "rules," Mr. Dickinson is referring to statutes, as opposed to regulations. MR. DICKINSON answered yes. 5:55:47 PM MR. DICKINSON continued with the subject of exploration credits, shown further on slides 30-32. He said the proposed legislation would make data on nonstate land - private and federal - more available to DNR and the public. He mentioned the tax code. He reviewed that under current law, only additional wells spudded in a drilling season of 150 days qualify for exploration credits; however, the proposed legislation would expand that figure to two drilling seasons, which equal 540 days. The bill would shift credits to explorers. It would also create "mini- TIE," allowing DNR to authorize tax credits for seismic work done prior to 2003. 5:57:29 PM MR. DICKINSON moved on to the issue of allowable lease expenditures, which is covered on slides 33-40. He said [AS 43.55.160] would be greatly simplified, because there would no longer be the need for doing monthly calculations for progressivity and a monthly gross based on windfall profits tax would not require division of costs between months. Under the proposal, allowable lease expenditures must be defined in regulation, which is a switch from "what is not forbidden is permitted" to "what is not permitted is forbidden." Mr. Dickinson said his concern is that the regulatory agency will have to play "catch up" with innovations in the field. He stated that although specific language authorizing joint interest billings would be repealed under HB 2001, the Department of Revenue would still be able to "go down that road" through its authority granted under its regulations. REPRESENTATIVE SAMUELS said everyone agrees upon using the billings as a base point; however, there has been disagreement regarding whether to keep or eliminate "the two paragraphs." 6:00:37 PM MR. DICKINSON said, "I agree that one of the paragraphs was confusing, but the other one wasn't." He offered examples. 6:02:11 PM MR. DICKINSON returned to the presentation, to slide 35. Regarding AS 43.55.165(e)(6), he said the current prohibition is costs arising from fraud, wilful misconduct, or gross negligence. The proposed legislation would add: a violation of law; a failure to comply with an obligation under a lease, permit, or license issued by the state or federal government. He said this is different from that which is being proposed for AS 43.55.025(b)(3). Mr. Dickinson said in general he is fine with this proposition; however, he questioned what it would mean to fail to comply with an obligation under a lease, and what kinds of costs would result. 6:03:13 PM MR. DICKINSON, regarding slide 36, said [subsection (e)] would prohibit deductions of the certain costs. He continued: Under current law, [dismantlement, removal, and restoration (DR&R)] cash payments, ... for upstream only, not for pipelines, would be allowed. ... Any DR&R proportionally that was produced or that the effect of which came from after the PPT law bill was passed, would in fact be deductible. The governor's proposal totally disallows DR&R. One of the interesting things about DR&R ...: At the end of the field life, as costs rise, there's going to be a point at which costs are too high and the field will shut down; people won't be able to use it anymore. At some point ... TAPS is going to come to a place where you say there isn't enough volume, the costs to run TAPS are too great. At that point, probably, that's when the legacy fields will ... shut down. The point is: Even though there's a fair amount of DR&R that ... was nominally deductible, a lot of it - and it always has to be on a cash basis - will be incurred after there's no longer anything come to offset. There will be no net ... barrel values that can be brought down. So, the general discussion under DR&R and deductibility really has to do with some of the smaller fields in which DR&R will occur prior to shutting down TAPS, as long as the legacy fields are still producing. ... 6:05:50 PM MR. DICKINSON, regarding slide 37, said he would compare three different approaches: that of the bill, that of SB 80, and that of the governor's proposal. The proposal, he said, would disallow costs arising in response to a problem which required an unscheduled reduction in production or resulted in a release of gas. He suggested that the legislature needs to redefine what reschedules means, because "unscheduled reduction" is a term that could be difficult to define. Acts of God, he said, would still be allowed. 6:08:03 PM MR. DICKINSON, referred to slide 38, which shows: "Current law disallows 30 cents a barrel from what would otherwise be allowable capital costs. This was described as dealing with the known corrosion issue." 6:09:11 PM REPRESENTATIVE DOOGAN asked if the 30 cents is subtracted from the deduction or from what the deduction is based upon. 6:09:28 PM MR. DICKINSON confirmed the former. He continued: It is subtracted from your deduction, so you pay tax on 30 cents more. In other words, if you think about the net value, it's going to be 30 cents higher as a consequence of subtracting this from the deduction. MR. DICKINSON, as shown on slide 39, said the approach of SB 80 was to disallow any costs associated with improper maintenance. Under current property tax law, he said, is the concept known as, "replacement cost new less depreciation." He continued: What is taxed on the North Slope are not the facilities that are there, but the ... hypothetical facilities that are there had there been a replacement of them. And so, what happens is, tax payers come in and they spend literally millions of dollars, and they basically build an "as if," and they say, "If we were producing 400,000 barrels at Prudhoe Bay, we wouldn't have six production facilities, we'd have three, and we would have 42-inch pipe, we'd have... You go through the whole rigmarole and you say, "Here's the 'as if' facility." And that's what the 2 percent property tax is levied against. ... I believe that's exactly what would have to happen, because you ... could have improper maintenance here, a little bit here, something in that facility that had the implication that this facility was done differently. And so, essentially, you'd have to build this "as if" proper maintenance, and every year it gets sort of further and further disconnected. 6:11:54 PM CHAIR OLSON interjected: Without debating the merits of the bill, I think in this particular case, the fact that the feeder lines hadn't been pigged for eight years, the corrosive additive had been cut back to basically water, I believe, that it was kind of like the definition of pornography a few years ago: You don't really know what it is, but you know it when you see it. In this particular case, we ... had a difficult time finding industry standards, but we knew it when we saw it. 6:12:23 PM MR. DICKINSON said that is a fair point. He suggested that one of the three approaches is appropriate, but he does not think "having two or three of them in there" would be. He added, "If one of these other approaches is taken, then I believe the 30 cents should be repealed, because I think that was an express attempt to meet that concern." 6:13:17 PM MR. DICKINSON, regarding slide 40, said the question is whether there will be some new topping plants "up there," and whether that is an appropriate part of production that should be allowed. He continued: Two concerns I have: One is that you're going to have a fair market value standard in its place where there isn't a broad market - not a lot of liquidity, and trying to figure out what that is, again, may ... be difficult. And I hate to get into situations where people say, "Gosh, the companies owe us money, ... they're messing with us." And then it turns out it's a fight about the fair market value and somebody who's buying and trading in that market is arguing with someone who isn't in that market about what fair market value is. Those standards are very hard to define if you don't have liquid markets. One observation I'll make: We all accept the ANS market value now - the way that's traded and the way that's reported - but for the first 10 years, when that was going on, there ... was a lot of skepticism, a lot of difficulty accepting that, and I would just be very concerned about having a fair market value standard for transactions on the North Slope. And my last concern: ... It's always difficult when you're trying to take a broad, general principle like this and you've got plants staring you in the face, and depending on whether it's in or out, a different company will be able to make money. And that's ... just always unfortunate when that's what it comes down to. 6:15:57 PM MR. DICKINSON, in response to a question from Representative Neuman, said he does not believe there would be any question that fluids purchased for production would be deductible if they were part of an arm's-length transaction. He continued: My belief is at the moment, most of this is simply fuel used for vehicles and compressors and standby things that aren't running on the natural gas, or what happens if the methane stream that's used is interrupted - that that's the main use. And I think those are clearly production uses. So, I haven't done the math on that particular issue about how those two would balance out. 6:16:45 PM MR. DICKINSON moved on to the issue of the state's purchase of credits, shown on slide 41 and regarding AS 43.55.028. Currently, he indicated, that credit purchase is allowed only in relation to small producers, and when they apply, they have to reinvest the money in the state, including lease bids, they cannot have any other delinquent taxes, and there is a limit of $25 million a year. The proposal, he said, would establish a fund from tax revenues and the earnings on them, which would be used to purchase the credits. Furthermore, he said, the proposal would remove the $25 million limit. He observed that those are two separate issues. He explained that there could still be a fund that could be funded through a percentage of tax revenues and capped at a certain amount, or "you could take off the cap and not have the funding." 6:17:53 PM MR. DICKINSON directed attention to slide 42, regarding information issues and pertaining to AS 43.55.040(5) and (6). This section of statute, he said, would require taxpayers to file reports and copies of records that are considered by the department as necessary to forecast state revenues under AS 43.55, and a $1,000 penalty would be levied for failure to comply. He explained how this can be ambiguous language. He suggested a better definition for the word "necessary," a specification of how far in advance, in terms of the forecast, how often the reports need to be updated, how far due diligence would have to go, and whether the state can audit for information not provided. 6:20:00 PM MR. DICKINSON turned to slide 43, which covers information related to the general rule in AS 43.05.230 and the proposed rule in AS 43.55.890. Currently, he stated, DOR can publish statistics with individual data combined to prevent the identification of particular returns or reports. The proposal requires only the combination of three taxpayers, "regardless of whether the information prevents the identification of particular returns or reports." Referring to notes on slides 44-46, he said, "This was described by some folks as being exactly what happens under the Salmon Pricing Report, which is something else the Department of Revenue does." Regarding that report, he noted that lots of values are not reported because of confidentiality reasons. The report is given in summary. He continued: The confidentiality statute does not remove the Salmon Pricing Report from the general tax law that it has to prevent the identification of a specific tax payer. What it does say is: ... If price averages are calculated by the department, it's public information, except the information that identifies or could be used to identify a particular fish processor is confidential. I guess that's restating the prohibition that is already in the ... general tax statute. It may be the reason that, in fact, this information is not tax information, and therefore the general tax rule doesn't apply. I don't know why they have this separate thing. But my point is: You've got a situation where you're still required under the Salmon Pricing Report to make sure that a particular fish processor cannot be identified. ... Here's the language out of the Salmon Pricing Report ...: "We use the following guidelines when evaluating confidentiality. If there are three or more processors for a given area ..., the information is reported unless one processor accounts for over 80 percent of total value, or two processors account for over 95 percent of total value." If that is the case, he said, information is not reported. MR. DICKINSON asked the committee to review the laws to ensure that they adequately protect confidentiality. 6:23:14 PM MR. DICKINSON looked at slide 47, showing information regarding AS 43.05.230(h). He said the proposal would require DOR to share information with DNR obtained under AS 43.55. Mr. Dickinson said he thinks that is a great idea for there to be more cooperation between the agencies. In response to a question from Representative Samuels, he indicated that the department has not had a competitive sale since 1986, but that does mean it won't have them again. The other issue is that all the tax information is "backward looking." Up to today, he said, that is true. He continued: But the point is, if you read the wording, what this is going to say is all the forward-looking information that you have to produce under a $1,000 a day penalty will also be available to the Department of Natural Resources. And that's simply where my concern is, whether that will have (indisc.) implications or not. 6:25:05 PM MR. DICKINSON noted that slide 48 shows what has to be filed by the tax payers. He said he agrees with this portion. As shown on slide 49, the proposal would extend the statute of limitations from three years to six years. He said he doesn't think that is that big a deal, because currently there are mutually agreed upon extensions. He recommended that the committee look at "this notion that you can assess $1,000 a day for not reporting information," and consider whether that would be extended, or whether advance notice or more timely notification should be required in association with those penalties. 6:26:19 PM MR. DICKINSON turned to slide 50, which addresses the issue of auditors as exempt employees. He said it is a great idea if one is trying to get people in a competitive market. He noted, however, that there are income tax auditors within the Department of Revenue, and income tax is complex. There are over half a billion dollars a year being generated in income tax issues. He added, "It's not a trivial issue." 6:27:23 PM REPRESENTATIVE NEUMAN asked, "What's your opinion if that job was farmed out?" 6:27:35 PM MR. DICKINSON stated his belief that in the beginning, the job should be farmed out. He said there are firms in the Lower 48 that do this all the time. He recommended using those folks as "part of the seed process to get the Department of Revenue going." He said people will believe that the department should have people dedicated within the state. He said he thinks it will always be useful to have outsiders coming into the system. 6:28:48 PM MR. DICKINSON moved on to slides 51-52, which address all the other information systems. He said "this" requires the information to be filed in a form or manner approved or prescribed by the department. He said this is something he used to think was great. He explained, "Tax payers already have this information, so there's no burden being placed on them, but if they have to restate it, 'refile' it, and do it all monthly in a way that meets the state's requirements, there may be a burden on the tax payer." He said the problem with a form generated by the Department of Revenue is that it represents their view that everyone else has to fit the data into those categories. Sometimes when that happens, he said, "you miss what's going on, because there's some new division being made we don't know about, but they have to take those numbers and add them back together, for example, and stick them into one of our categories." He expressed a desire to see a balance between getting information in its raw form and getting information in a form that can be used immediately. 6:30:47 PM MR. DICKINSON, referring to slide 53, noted that Pedro van Meurs, Ph.D., had told the legislature to look at the penalty provisions, because this bill would weaken them. He indicated that he had subsequently spoken to Dr. Van Meurs and shown him a different view point. He continued: Let me just explained the way the interest provisions work. Within a year, if ... the taxpayer makes estimated payments, and they're underestimated, they owe the time value of money; they have to pay interest from that through March 31 at a rate set by the IRS, which is generally viewed pretty close to a market rate. If they ... overestimate in a month and it turns out that they owed less, then the state owes them money. ...And there's actually four rates, because the IRS has what's called an "over payment" and a "large over payment" [rate]. And it's not symmetrical, but the taxpayer owes a higher interest rate to the state, and vice versa, ... and then the break-off there is, I believe, $100,000. Then ... if there's a refund, the interest ... is at a lower rate, and I believe the level there is $15,000, but I could be wrong on those. But as soon as you hit March 31, everything that's happened before gets rolled together, and from that day forward you are back under Alaska statute, which at the moment is 11 percent compounded. ... Folks can make their own judgments about the relation of that to market rates, but I believe that most people looking at that believe that ... if your state underpaid for four or five years and then [had] to pay 11 percent on that, ... that is a penalty. And what Dr. Van Meurs didn't understand is that ... the ... lower IRS rates stopped as soon as you hit March 31. 6:32:56 PM MR. DICKINSON directed attention to the information on slides 54-56, regarding Cook Inlet "Simplicity." He suggested that the Cook Inlet ceilings could be implemented more simply. Currently, calculations have to be done individually for each lease or property - once for the oil and once for the gas. Under current statute, all the North Slope is "one segment - one set of calculations." Everything outside of Cook Inlet and the North Slope was another calculation. He said, "And then within Cook Inlet, a taxpayer might have five or six or seven segments, because this calculation had to be done so often." He continued: So, I think there were two rules the legislature wanted to impose. The first one: there were ceilings - that Cook Inlet taxes will remain zero for oil, and for gas it would preserve a level of the ELF and the prices that were found in 2005-6. And then that would be preserved until 2020. The second important principle is that these ceilings were meant to benefit consumers. Therefore, if a taxpayer was paying a whole lot less because of the ceiling -- Maybe I'll just skip ahead to the next [slide] to give you an example: If I owe $10 in taxes, and then I have some credits and I apply them and they drop my tax to $5, and then it turned out that the ceiling dropped it further down to $3, a taxpayer couldn't come in, pay their $3 in taxes, take that $5 credit, and sell it to somebody or use it elsewhere. The notion was if you were paying lower taxes because of the ceiling, you had to apply your credits and your costs and your lost carry forward to bring you as close to that ceiling as you could. And that makes sense. And I believe that there's ways that that can be implemented. It will be a lot less difficult then the three or four pages that it now takes to implement those. 6:35:34 PM MR. DICKINSON concluded his presentation with slide 55, which addresses the effective date. Generally, he said, the effective date is January 1, 2008. He said: I think there are two very good tax policies built into there. The first one is: the change corresponds to the calendar year, which is the basis on which all the taxes are paid, so you don't have to have this one system through three months and another system through another several months. So, that's a good idea. And then the other thing is: generally, as a tax person, I tend to think that retroactivity - the more limited use of that is made the better, and so, I applaud the fact that it's a foreword-looking tax. There is one provision which is retroactive - the so-called corrosion provisions - but otherwise it is foreword looking. [HB 2001 was held over.] ADJOURNMENT  There being no further business before the committee, the House Special Committee on Oil and Gas meeting was adjourned at 6:37:04 PM.