HOUSE FINANCE COMMITTEE November 8, 2007 9:14 A.M. CALL TO ORDER Co-Chair Chenault called the House Finance Committee meeting to order at 9:14:50 AM. MEMBERS PRESENT Representative Mike Chenault, Co-Chair Representative Kevin Meyer, Co-Chair Representative Bill Stoltze, Vice-Chair Representative Harry Crawford Representative Richard Foster Representative Les Gara Representative Mike Hawker Representative Reggie Joule Representative Mike Kelly Representative Mary Nelson Representative Bill Thomas Jr. MEMBERS ABSENT None ALSO PRESENT Representative Craig Johnson; Representative Bob Buch; Representative Kurt Olson; Representative Paul Seaton; Kevin Mitchell, Vice President, Finance and Administration, ConocoPhillips; Jim Taylor, Vice President, Commercial Assets, ConocoPhillips; Claire Fitzpatrick, Commercial Vice President, BP; Bernard W. Hajny, Manager, Production Taxes and Royalties Alaska, BP; Craig Haymes, Production Manager, Exxon Mobil Alaska; Dan Seckers, Senior Tax Counsel, Exxon Mobil; Mark Hanley, Manager, Public Affairs, Anadarko- Alaska; Pat Foley, manager, Lands and External Affairs, Pioneer Natural Resources; John Zager, General Manager, Chevron-Alaska; Marilyn Crockett, Executive Director, Alaska Oil and Gas Association; Rich Ruggiero, Consultant, Gaffney, Cline and Associates Inc.; Dudley Platt, Department of Revenue; Barry Pulliam, Senior Economist, Econ One Research, Contractor, Legislative Budget and Audit Committee. PRESENT VIA TELECONFERENCE Edger Dunne, Manager AVCG/Brooks Range Petroleum, President Dunne Equities. SUMMARY HB 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. HB 2001 was HEARD & HELD in Committee for further consideration. 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. KEVIN MITCHELL, VICE PRESIDENT, FINANCE AND ADMINISTRATION, CONOCOPHILLIPS, provided a brief PowerPoint (Copy on File). He summarized that CSHB 2001 (RES) represents a less attractive climate for investors in Alaska, with a significant tax increase, not only in the context of tax rates and progressivity. He strongly emphasized that the CS would have an impact on investment decisions. Mr. Mitchell spoke to the proposed tax system. He noted the increased base rate from 22.5 to 25 percent and that progressivity is significantly increased over PPT amounts. In addition, the progressivity has a tie to the gross component to the absolute price. ConocoPhillips has been consistent in emphasizing the need for all aspects of the tax rates to be on a net basis, whenever those rates have a gross component that can have a distorting impact. Net rates adjust for changes in cost and margin; gross rates can be negatively impacted. Lastly, the reduction of transitional investment expenditure (TIE) credits penalizes investors who have been consistent in their investment plans. He asserted that TIE credits soften the impact of tax changes and provide stability for investors. 9:21:46 AM JIM TAYLOR, VICE PRESIDENT, COMMERCIAL ASSETS, CONOCOPHILLIPS, referred to Slide 3, "Tax System and Investments," depicting a graph with the Department of Revenue's eight year forecast of production. He noted that ConocoPhillips has been an aggressive investor in the North Slope, investing over $12 million and participated in all levels of the upstream business. He maintained the graph represents those elements of the upstream business it will need to arrest the production decline occurring on the North Slope. The green wedge on the graph represents new field development, the yellow represents other currently operating fields, and the red and blue represent the two large fields that have been referred to as the legacy assets. Mr. Taylor asserted that investment is the key to North Slope production sustainability. Without investment, the blue area could decline as much as 15 to 20 percent per year. The red wedge represents investment opportunities, such as infill drilling, heavy or viscous oil, and handling ever-increasing volumes of water and natural gas associated with oil production. Infill drilling opportunities represent less than 30 percent of the investments required to sustain production in the legacy fields. Mr. Taylor said originally estimates of North Slope oil were around 24 billion barrels. Approximately 11 to 13 billion barrels of that will come out of the existing Prudhoe Bay field. The investments of the future are not the same as the investments of the past. The single largest known reserve potential in the North Slope contains approximately 26 billion barrels and lies underneath the permafrost between the current producing zones, in the viscous and heavy oil layers. Drilling for and recovering this oil will involve many challenges, more risk and higher costs. Mr. Taylor summarized that about 40 percent of production in the red wedge will come from the existing fields, and consist of handling water, gas, and heavy and viscous oil, all of which cost more to develop. 9:26:07 AM Mr. Mitchell listed the provisions beyond the base rate increase that amount to a tax increase and add complexity to administration (Slide 4): · Out of state exclusion · Topping plant exclusion · DR&R [dismantlement, removal and restoration] exclusion · "Reasonable" transportation costs · Exploration confidentiality · 6 year statute of limitations · Retroactive implementation Mr. Mitchell argued that many out-of-state costs are legitimate expenses for a project. The topping plant exclusion targets one aspect of North Slope operations and adds complexity to the process for both industry and government, with significant effect on operations. He maintained that DR&R costs are legitimate expenditures and are typically an allowable expenditure world wide. He pointed out that the industry is already governed by two regulatory authorities and "reasonable" transportation costs add additional complexity of administration for both government and industry. Mr. Mitchell discussed exploration data and confidentiality provision changes. The provision restricting data confidentiality to two years is a disincentive to exploration credits. The six year statute of limitations has the effect of extending the time it takes to complete and close an audit. Increased interest costs resulting from the additional time allotted would result in a significant penalty. It will also take time to develop new regulations to cover additional provisions, especially the retroactive implementation. The industry is concerned about significant costs in penalties and interest. He pointed out that tax changes are generally phased in. Mr. Mitchell summarized the impacts on the investment climate. He acknowledged that the enhanced exploration incentive credits (EIC) would be beneficial. More is at issue than a 25 percent base rate and higher progressivity. Some of the issues are too complex to be modeled yet. He concluded that the added provisions create barriers to investment. 9:33:38 AM Co-Chair Chenault led a discussion about question and answer protocol. CLAIRE FITZPATRICK, COMMERCIAL VICE PRESIDENT, BP, provided a PowerPoint presentation on the impacts of CSHB 2001 (RES) (Copy on File). She observed that BP was not able to fully review the legislation and its impacts because they received the bill less than 48 hours previously. She acknowledged that there are good business opportunities [in Alaska], but expressed concerns. Ms. Fitzpatrick reviewed the guiding principles for the petroleum production tax (PPT): fair revenue to the state, creating an attractive investment climate for new exploration and reinvestment, and transparency. She maintained that the current bill and the HRES version are making a trade-off between short-term gain and long-term risk, but to different degrees. An attractive investment climate is one where the state recognizes the need to increase investments. Alaska still has the highest tax rate in North America. Future opportunities are not easy and the cost base for the total activity set remains high. Ms. Fitzpatrick asserted that the new administrative provisions for transparency will make it difficult to forecast, administer, and comply with the tax law. Fiscal systems globally recognize that it takes a couple of years to implement and evaluate new systems. She maintained that the bill turns what they thought was a manageable system and moves it into an inherently moving target. She acknowledged that some of the provisions will make it easier for the state to collect data, which they agree with as long they are implemented correctly, but she questioned if companies will be able to come up with consistent data, comply with unknown rules, and do forecasting to an accuracy of 0.1 or 0.2 percent. 9:40:35 AM Ms. Fitzpatrick compared some of the proposed measures to their perception of the guiding principles. Gross progressivity is a net trigger applied to the gross and adds complexity. She concluded that gross progressivity would impact investment decisions. She explained that under normal circumstances companies would expect to pursue new technology and investment opportunities if the price environment remained above $52 per barrel for a sustained period time. She maintained that gross progressivity would impact these activities. BERNARD W. HAJNY, MANAGER, PRODUCTION TAXES AND ROYALTIES ALASKA, BP, expressed concerns about using joint interest billings as a starting point for what is deductible under PPT. The current bill would repeal the Department of Revenue's (DOR) statutory authority under AS 165 (c) and (d) to authorize the operator's use of [joint interest] billings. He echoed concerns put forth by Conoco Phillips regarding deductions of out of state costs. The current legislation requires that costs most be physically located in the state, while removing language clarifying that the costs do not need to be in located on or near the unit, field or exploration prospect. Mr. Hajny discussed issues related to transportation costs. He maintained that there is not a problem that needs fixing. Any retroactive tariff adjustment applicable to any of BP's taxable oil would be adjusted in future tax returns, along with any associated interest. He stressed that the Regulatory Commission of Alaska (RCA) and Federal Energy Regulator Commission (FERC) are already charged with the task of determining "just and reasonable" tariffs. He thought the most straightforward approach is to continue utilizing the Trans Alaska Pipeline System (TAPS) tariff. Ms. Fitzpatrick added that BP executed the year's activity in good faith that the tax principles were in place. She suggested the committee answer the question whether the retroactivity application is "reasonable" or "fair". 9:44:47 AM Ms. Fitzpatrick noted that infill drilling noting is profitable to both the state and industry, but emphasized that infill drilling is only one element of future development. The future is going to also require satellite development, heavy oil, new technology, and infrastructure. Building new, more efficient facilities will make the North Slope viable for both existing and new developers. Ms. Fitzpatrick addressed the issue of heavy oil and said the current gross progressivity structure acts as a gross tax when companies are making investment decisions. If there is little or no upside potential, there is no incentive for companies to increase risk for challenging projects like heavy oil. Ms. Fitzpatrick discussed long-term planning and the variables that impact the process. Increased taxes reduce the cash available to fund business. She stressed that BP will continue to do business in the state. The amount of increased development and exploration will be determined by how much risk the company feels they can take under a given tax regime. She maintained that the pace and scale of what the company is able to do would change according to the legislature's actions. 9:48:13 AM CRAIG HAYMES, PRODUCTION MANAGER, EXXON MOBIL ALASKA, presented an executive summary on HB 2001 (RES). He reviewed written testimony and gave a PowerPoint presentation (Copies on File). He observed that Alaska has great resource potential and oil and gas with world class results. He pointed out that currently production levels are down to one third of its peak, which was 2.1 million barrels per day in 1988. According to the U.S. Geological Survey and the Minerals Management Service, Alaska still has undiscovered recoverable resources of over 53 billion barrels of oil and 259 trillion cubic feet of gas. Only one quarter of this potential has been produced. Alaska's world ranking of thth proven reserves has dropped from 14 in 1977 to 30 currently. Prudhoe Bay and Kuparuk represent over 70 percent of the current total North Slope production. These fields will continue to act as hubs for future satellite developments that would not be economic without their infrastructure. Mr. Haymes described Alaska as a high cost environment due to its severe climate, remote location, sensitivity of the environment, and exploration restrictions. Effective application of technology is critical to future development. He gave examples of leading-edge technology that has been successful. In ten years, 75 percent of oil production will come from new investments, which would require over $30 to $40 billion, or double the current investment levels per year. Mr. Haymes maintained that Alaska needs a long-term resource development policy, including (Slide 3): · Characterization of state-wide resource potential · Identification of key issues challenging exploration and development · Determination of key factors that impact resource value o Research and technology required o Exploration development costs o Regulatory and environmental considerations o Land access challenges · Establishment of goals and measurement of progress · A fiscal policy that will encourage development of remaining resources · Regular meetings with industry and agency representatives Mr. Haymes proposed a collaborative approach to develop a sustainable policy. The question is how Alaska's full resource potential can be commercialized. Mr. Haymes pointed out that industry needs a predictable fiscal environment. Investments are capital intensive and typically evaluated over decades. Changing the fiscal environment for capital projects reduces the attractiveness of investments. 9:55:16 AM Mr. Haymes explained that Exxon Mobil supports the concept of a net-based tax structure. He said that PPT has only been in existence for just over one year; DOR has not completed regulations nor commenced a PPT audit. Exxon Mobile met with DOR to improve the ability to forecast revenues and is willing to keep working to improve the department's understanding of joint interest billings. Exxon Mobile believes the policies established today will impact the attractiveness of potential future projects. 9:56:29 AM Mr. Haymes stated that the proposed tax increase is more complicated than a tax increase. First, it would cause uncertainty in the following ways: · Sections 34(b) and 34(c) propose a number of different reporting requirements for exploration tax credits. The credit qualifications are linked to the release of proprietary data. He argued that this is not the norm throughout North America and that the release of proprietary data would concern to any explorer, in addition to increasing their costs. This would create more uncertainty as to whether credit would be applied for. In addition, exploration confidentiality protection is diminished to a very short two years. · Section 44(f) proposes additional information requests, which they feel are ambiguous. "Other records and information the department considers necessary" is of concern. He maintained that any information required beyond what is submitted with their current tax filings needs to be carefully considered. · Sections 48 and 49, which propose that the department can, at any time, substitute the determination of reasonable costs for transportation instead of the taxpayer's actual costs. · Sections 53 and 54 propose a limit on qualified lease expenditures, restricted to those incurred on the lease producing oil and gas. Exxon Mobile believes this will decrease the attractiveness of opportunities and create uncertainty. · Page 42, subsection (19) proposes the disallowance and limitation of costs associated with refineries or heavy oil topping plants. He pointed out that there are significant costs associated with meeting the regulatory requirement of upgrading topping plants to comply with the state and federal mandates for ultra low sulfur diesel. He noted that they could deduct costs if they trucked out the diesel at an additional environmental cost. The potential environmental exposure and risks from increasing truck traffic on the roads needs to be seriously considered. 9:59:25 AM Mr. Haymes continued that second, the proposed tax increase would increase administrative burden. · Section 36 proposes to increase the statute of limitation from three to six years. He spoke against the change and pointed out that extensions have been historically granted when requested. The change would increase the company's administrative burden and costs. · Section 59 eliminates requirements for joint interest billings as the starting point for audits. He thought this would be a disadvantage as each year operators are subjected to extreme audits. Exxon Mobile spends over 100 staff weeks each year auditing joint interest billings. Mr. Haymes added that the CS has a number of unreasonable excessive components: · Section 29 reduces the transitional tax credits from six to three years. This provision was put in place in recognition of the long term investment requirement, and to encourage increasing investment. · Sections 25 and 45 have excessive late filing and document submission penalties. For example, there is a $1,000 per day penalty for "each report, statement or document" that is not produced "at the time required." He maintained that the provision could result in amounts that are disproportionate to the severity of the offense. · Section 57 proposes the publication of certain proprietary tax information when the information is aggregated among three or more producers or explorers. He supported the desire to obtain additional information under the PPT framework, but expressed concern that the aggregation of three companies would allow competitors to determine proprietary information. He stressed the importance of protecting tax payer confidentiality. Mr. Haymes closed by emphasizing the need to collaborate on a long-term investment development policy that increases investment, develops resources, mitigates production decline, recognizes the high cost environment, and provides fiscal predictability for industry. RECESSED: 10:03:16 AM RECONVENED: 10:18:52 AM Co-Chair Chenault invited questions for the panel of industry representatives. Co-Chair Meyer asked for clarification of definitions regarding infill drilling, joint interest accounting, TIE credits, and the discounted price for oil. Mr. Taylor defined infill drilling as the initiation of the drilling of a new well in an existing oil reservoir. The geological risk is greatly reduced when a new well is begun in a known deposit. Mr. Hajny explained that joint interest accounting is important to PPT as a basis for cost deduction. One of the principles behind developing PPT was the ability for producers to use the joint interest billing statements as a basis for deducting cost. The majority of North Slope fields use joint operating agreements. These agreements set out procedures by which BP, as operator for Prudhoe Bay, bills interest owners for their share of legitimate costs associated with BP's operation of the field. A bill is sent every month to Exxon Mobile, ConocoPhillips and Chevron for their percentage share of the costs. This is the only basis the companies have for determining what costs should be deducted when filing estimated payments. 10:24:00 AM Representative Hawker asked about the internal audit procedures within the companies. Mr. Hajny observed that the billings have a three year audit provision. There are different audit provisions within each company. Companies are billed as the costs are incurred by the operator. Interest owners can deduct these costs from their PPT. Representative Hawker asked if an audit process was in place. He spoke to the permissive language in the original PPT allowing the use of the joint interest billings. Ms. Fitzpatrick commented that each joint billing is subject to an audit each year by the parties who are not the operators. For example, Prudhoe Bay would be audited by Exxon Mobile, ConocoPhillips, and Chevron. The auditing is thorough, detailed, and rigorous, and done from people outside the organization. 10:27:58 AM Representative Nelson asked for more clarification regarding joint interest billings. Ms. Fitzpatrick explained that there are different teams working on each field. Audit teams bring in additional challenges. Auditing occurs externally as well; there are a number of checks and balances. Representative Nelson asked about the external auditing. Ms. Fitzpatrick reiterated that they are audited by independent companies and the results are publicly reported. She observed that DOR has not started PPT auditing. She pointed out that the department must wait until after the company has filed to begin. She did not believe the department was behind. 10:30:48 AM Mr. Mitchell explained that TIE credits were put in place in PPT legislation to provide some form of compensation for those who had invested in the past under a previous tax regime but were moving into a new tax environment. The credits apply to investments, for example, that took place in the 2003-2005 timeframe when there were no capital deductions or credits on the investments. By the time the assets were producing revenues, they were in the PPT environment and being taxed at a 22.5 percent rate. The TIE credits allowed for a five year look-back period and additional credit could be taken that provides some form of compensation. The credits require historic investment during the timeframe and future investment in order to be applicable. 10:32:56 AM Representative Joule asked about the increase to Exxon Mobile's profit. Mr. Haymes answered that Exxon Mobile does not release earnings statements for Alaska, only quarterly and annual reports. He stated that they had received Representative Gara's letter requesting profit amounts and were preparing a response. At today's prices, ACES would represent a production tax increase of 350 percent since 2005. With the HRC version of HB 2001, the production tax would increase by 470 percent since 2005. In the U.S., taxes paid have exceeded earnings for the company. Since 2001 to 2005, Exxon Mobile profits were $40 billion. In that same time frame, $60-70 billion of taxes were paid. Representative Joule referenced the issue of audits and questioned why the state should not be ruthless in the auditing process also. Ms. Fitzpatrick thought they should be but was not sure they would be. Representative Joule recalled that the permissive language was a compromise. DAN SECKERS, SENIOR TAX COUNSEL, EXXON MOBIL, agreed. The legislation would repeal Sections 165 (c) and (d). Those sections, which are not mandatory, provide that DOR can start its audits by looking at the joint interest billings. It does not have to, but can. He thought that was a good action because the joint interest billings are thoroughly audited. There is no economic incentive for anyone to pay anybody else any more money than necessary. There are internal rules, zero tolerance policies that do not allow paying one cost from one field to another. Mr. Seckers stated Exxon Mobile's concern regarding repealing the sections. If the legislature grants authority and then removes it, the concern is that DOR will no longer look at the joint interest billings. Representative Nelson understood that. Mr. Seckers stated that a cost has to be valid in order to be paid. Their accounting rules and internal ethics will not allow another action. Representative Kelly asked Exxon Mobile's opinion about what the administration said regarding the provision. Mr. Seckers replied that the administration has indicated that auditing is mandatory; however, 165 (c) and (d) are not mandatory, but permissive. He did not understand why. The industry expects to be audited. He thought it would be a waste of time. Representative Kelly noted that the administration has said that they are not trying to eliminate the provision and asked why they wanted it removed. Mr. Seckers did not know. He reiterated that it is permissive. Mr. Haymes added that if a DOR auditor requested a listing of payments, there is nothing to go by except the joint interest billings as a starting point. The industry spends many staff hours and almost $500,000 dollars a year auditing the other companies. He urged joint interest billings as the starting point. The current language makes it exclusive and creates ambiguity. He stressed that joint venture billing experts do the auditing. They know what to look for. 10:44:32 AM Representative Hawker wanted the external professional standards applicable to internal auditors. Mr. Seckers assured him that joint issue billings are looked at in accordance with GAP [Government Accountability Project] standards, which has specific guidelines as to what is allowable as an expense. Representative Crawford requested guarantees and described his experience with failed expectations of guarantees related to the oil industry. He stated concerns about keeping taxes low without guarantees that money will be reinvested in Alaska. He recommended a higher tax rate to help create incentives to explore and develop more oil. Mr. Taylor replied that there are no guarantees. He thought encouraging investment and raising taxes had already occurred since PPT mechanisms are in place to raise taxes and introduce progressivity. Industry is saying that the changes already took place last year and are being revisited, creating uncertainty. He thought the investments were there, but the elevated price is causing the industry to reevaluate Alaska commitments. Investments are occurring and the element of progressivity has already been introduced. He emphasized that changes slow the process down. Representative Crawford pointed out that his question was answered by ConocoPhillips, the company that has done the most investment. He wanted to see more investment in Alaska from the other companies. Ms. Fitzpatrick argued that BP has increased investment; depending on what is passed, they will continue consideration. She suggested extending rather than curtailing TIE credits. 10:54:37 AM Mr. Haymes added that Exxon Mobil has invested over $20 billion dollars in Alaska, with 900 new wells in the last seven years. He stated that they invest on a par with BP and ConocoPhillips. Exxon Mobile believes that the development of resources is global and competitive world wide. There is significant resource potential, but Alaska has unique challenges. He stressed that Exxon Mobile wants more competition on the North Slope; the more development, the lower the cost for infrastructure and operation, and the more oil that can be produced for everyone. He urged encouragement of independent companies. Mr. Taylor agreed that investment is happening. Mobilizing takes time and the market is expanding. He believed that letting the system work would bring new players, ranging from smaller consortiums like Brooks Range Petroleum through major international oil and gas companies like Anadarko. He spoke against raising taxes because they create instability. Representative Crawford understood that to mean that taxes should not be lowered. Ms. Fitzpatrick responded that accelerating the pace was not on the table. 11:00:06 AM Representative Gara asked about the 350 percent tax increase mentioned earlier by Exxon Mobile. He was concerned with companies misleading the public to undermine the efforts of the legislature. Public relations information put out by Exxon Mobile has suggested that ACES would triple industry's taxes. He requested accurate information. According to his calculations, the total tax burden has increased less than 30 percent under ELF [Economic Limit Factor], prior to PPT. He asked for an estimation of total tax burden in the current year compared to that under the ELF system. Mr. Haymes responded that the comment was in regard to production tax. Using the DOR model, at the current oil price, under the ELF system the tax burden for the industry would have been $1.1 billion. Under the ACES proposal, that number would be $4.9 billion, a 350 percent increase. Comparing the $1.1 billion under ELF at today's prices with the HRC version, it is currently at $6.4 billion, a 470 percent increase. Representative Gara reiterated that the total tax burden includes royalties, corporate income tax, and property tax. There have been ads supported by Exxon Mobile saying that their tax burden has already tripled. He asked if comparing the total tax burden under the ELF and last year under PPT would translate closer to 25 percent. Mr. Haymes commented that present testimony specifically referenced the production tax. The numbers are accurate with respect to the ELF system of 2005. When additional taxes such as federal and state corporate taxes, property taxes, and the royalties, the amount of tax increases significantly. Representative Gara requested totals for tax payments under the current system compared to payments under the ELF. He stressed that the taxes have not tripled as media ads are claiming. Mr. Haymes agreed to get he totals. He asked to discuss total government take as well. Mr. Hajny commented that the impact to BP was an increase from approximately $180 million under ELF to over $520 million under PPT for the last three quarters of 2006, nearly a tripling of taxes during that period. He did not know the impact of the state income tax; the property tax has also increased from roughly $3.3 billion to $4.5 billion. The $1.2 billion dollar increase was at a mill rate of two percent. Representative Gara pointed out that production tax increased under the ELF because at almost every field in the state they were zero. He referred to annual reports by BP and ConocoPhillips from the previous year. Profit margins were reported of 36 and 37 percent respectively, roughly over $2 billion in profit from Alaska on roughly $6 billion of income. He asked if Exxon profits margins were higher than those reported by BP. Mr. Haymes stated that they are not required under the Securities and Exchange Commission (SEC) to disclose profits. They are not attempting to hide the information; they do not report it that way. Current production is 150,000 barrels per day. He understood the desire to see the information to help with projections for tax and revenues; Exxon Mobile is willing to work with DOR to provide it. Representative Gara stressed that not having the numbers makes it difficult for the state to adopt a fair profit tax. The state's consultants say the internal rate of return is an important number as well as the profit margin number. He requested information from the three companies for the past fiscal year. Mr. Haymes responded that internal rate of return is only one measure used to look at profitability of investments. There are other factors considered. The internal rate of return is confidential, competitive, and proprietary information. However, the annual report does indicate those numbers on a world wide basis. Ms. Fitzpatrick explained that internal rate of return is an investment metric over a long period in the life of a project. On an annual basis it would be return on capital employed. She offered to calculate that based on public information. Mr. Mitchell added that the calculation would be difficult, although the financial results are disclosed in the SEC filings by region, including Alaska. There is a variety of information, including historic invested capital. Mr. Taylor stated that the planning horizon is an ongoing process in a company. ConocoPhillips is constantly looking for investment opportunities that will benefit shareholders and other recipients of benefits, including state and local governments. In the past three to five years there has not been an $80-90 price horizon. The market is heavily influenced by geo-political factors. There are profits associated with the actual profits. When looking at Alaska's potential, the question is how Alaska competes. The largest resource on the North Slope continues to be in more challenging projects. That situation is different than in the past, but price encourages taking more risk and higher costs from capital exposure and operating costs. The investments of the future are different than those of the past. Considering the changes, uncertainty causes investors to pause. He concluded that the internal rate of return ranges from the very high numbers suggested in previous simulations to very challenged numbers. 11:15:17 AM Representative Gara commented that keeping tax rates down does not lead to more investment, which is why investment credits and bigger deductions are being considered. Under the ELF system, a virtually zero percent tax rate did not increase investment. Keeping the tax rate down has not kept the money in Alaska. Giving money back seems to the only way to encourage industry to invest in Alaska. He asked why so much money left the state under ELF and PPT, and if the companies would be more likely to invest with incentives like the credit and deduction systems. Mr. Taylor reiterated that a change had already occurred in terms of raising taxes and progressivity with PPT last year. He emphasized that stability is the best thing to continue development. He did not think raising taxes would encourage investment. Incentives do help, but the legislation is getting more confusing, making it difficult for investors and slowing investment down. Ms. Fitzpatrick agreed. Mr. Haymes echoed Mr. Taylor's comments. He thought the net structure is a step in the right direction. The issue is complex; Alaska is a high cost environment with unique challenges. There is a lot of land access not available for exploration activities. Industry exists to find, develop, produce, and market energy and will continue to do that as long as it is attractive and makes sense. Mr. Mitchell added that investment does not happen overnight. A change in tax structure does not bring sudden investment. It has been only a year since PPT has been implemented. More changes create uncertainty. 11:21:11 AM Representative Kelly strongly encouraged industry profitability but wanted to guarantee that same profitability for Alaska. He was convinced that what is being offered is a robust and profitable system. He believed the changes being worked through would guarantee profitability for both the state and the industry. 11:24:04 AM Representative Hawker stated concerns about the credibility of the process, especially a statement regarding significantly inflated cost claims with the intent to deceive DOR. He asked if any of the industry present had intentionally inflated their numbers. He asked for assurances that they would not or could not inflate numbers because of internal accounting controls. He referred to the Sarbanes-Oxley Act, which establishes consequences for misleading financial reporting. 11:28:07 AM Mr. Seckers declared that Exxon Mobil has strict internal policies prohibiting falsifying records or returns; the consequence is immediate termination and severe penalties. The joint interest billings are audited independently and scrutinized in accordance with GAP. Tax returns are filed in accordance with the law. Mr. Hajny echoed Mr. Seckers. He stated definitively that within Exxon Mobile there has been no intent to inflate or file erroneous tax returns. When PPT was put in place, it was highly scrutinized because it was a new tax. Policy was created to make the tax work. He noted that not all regulations were currently out. Ms. Fitzpatrick explained that Sarbanes-Oxley requires that companies document internal controls to ensure there is appropriate financial reporting and that all the risks are identified and key controls in place. There must be both monitoring and verification of those processes and controls. There is an internal group in BP as well as an external group that confirm that activities and controls are in place and operating as they should. There are also third-party external auditors. Mr. Mitchell explained that ConocoPhillips has clearly defined Sarbanes-Oxley procedures and controls that are audited annually in addition to the standard external audit. In addition, every employee is required to adhere to an internal code of ethics and make an annual attestation that they have complied. This covers a broad range of aspects of the law. By the time the SEC filings are made, they are signed off on at a corporate level by a comptroller and a chief financial officer, with criminal penalties for fraudulent statements. Representative Hawker maintained that there is a legal as well as administrative control system to assure results. 11:35:05 AM Representative Gara wanted assurances that tax returns would be as creditable as possible. He questioned if there were penalties under Sarbanes-Oxley for state fillings or just SEC filings. Ms. Fitzpatrick responded that Sarbanes-Oxley governs a company's financial reporting under SEC guidelines. With respect to PPT filings, the same information goes into external reporting; a subset goes into the PPT filing. The actual costs are claimed with good faith. There are situations where interpretation of a guideline is subject to debate. If they have clarity about what they are filing against, BP's objective is to file a 100 percent compliant tax return for any of the taxes. Representative Gara asked if there were Sarbanes-Oxley penalties for overstating deductions or credits under the PPT return in SEC filings. Ms. Fitzpatrick explained that Sarbanes-Oxley does not apply to state tax filings. She thought there were other provisions that covered the filing of state tax returns. Mr. Seckers explained the process in more detail. When BP, for example, sends Exxon Mobile a joint interest bill, the comptroller along with the engineers go over it repeatedly. It is then reviewed by the law department to make sure it complies with the joint interest billings that are allowed under the unit operating agreements. Then the tax accountants look at it before sending it to the tax lawyers who make sure it complies with the PPT tax law. The return is prepared. The return is reviewed by the superiors of all the auditors, tax accountants, and lawyers to make certain it is correct. Then the return is signed and sent out. Every year Exxon Mobile employees have to sign an ethics agreement to make sure they are complying. In addition, the state of Alaska has other penalties, interests, and fines in place for fraudulent and late returns and so on. Federal laws also apply. 11:39:28 AM Representative Gara reiterated concerns that the PPT projections understated costs and overstated revenue. He felt that the industry should have advised the legislature if they felt costs were understated during the PPT debate. Ms. Fitzpatrick believed her counterparts had repeatedly attempted to discuss the costs. Current numbers for both capital expenses and costs are blended for the whole of the North Slope. She added that BP numbers are higher than the numbers listed for 2007, and will be higher still in 2008. Mr. Mitchell added that ConocoPhillips testified during PPT hearings regarding the trend toward an increase in costs. 11:42:38 AM Co-Chair Chenault invited closing statements from panel members. Mr. Taylor of ConocoPhillips agreed that profitability is not a bad thing and added that a healthy investment environment should benefit the state as well. Changes in the tax structure cause disruption. He stressed that whether taxation and progressivity are applied to the net or to the gross is an important distinction. Net taxation would create a healthy investment environment; taxation to the gross would be very challenging, especially to higher cost potential development. Ms. Fitzpatrick asserted that BP did not think the original bill at the start of the special session improved new investment or reinvestment. The HRES version is significantly worse and would require them to revisit their business plans. She emphasized that the quality of the oil as it gets thicker affects costs. At one point there was a $14 difference between ANS crude and heavy crude. That price difference may be larger still, and this is one of the many challenges that face the company as they try and come up with an economically viable project for a challenged product. 11:46:10 AM Mr. Haymes of Exxon Mobile stressed that in 10 years 75 percent of oil production will come from new oil that conservatively needs $30-40 billion in new investment. The resource potential for Alaska is significant. Policies established today will impact the attractiveness of future projects. The proposed CS of HB 2001 adds layers of complexity, increased taxes, and other measures that have been discussed. He pointed to detailed write-ups on those issues in submitted testimony. For the production tax, ACES proposes a 350 percent increase since 2005; the current bill would mean an increase of over 400 percent. 11:47:57 AM Representative Gara pointed out that the lower the tax rate, the more unstable it will be. He spoke in support of proposals by Representative Kelly. RECESS: 11:49:40 AM RECONVENED: 12:47:24 PM Co-Chair Chenault introduced the second panel of presenters. ANADARKO MARK HANLEY, MANAGER, PUBLIC AFFAIRS, ANADARKO PETROLEUM CORPORATION-ALASKA spoke in support of net taxation. Anadarko feels a flat gross system over-taxes some fields and under-taxes others. Costs are not included. The new investment needed, whether for exploration, infill, or heavy oil, tends to be more costly than for existing fields. The net system attempts to incorporate costs. Mr. Hanley pointed out that the net system, however, does not necessarily take risk into account. An infill well cannot be profitable in the current environment. To establish a tax rate on that would cause over taxation. Heavy oil does not have the same economics. He acknowledged that credits help. Anadarko supported PPT as an improvement in exploration economics, but preferred the progressivity be on the net. Mr. Hanley warned that the 0.2 escalator on the gross is more like a 0.25 on the net if the tax rate is 25 percent, and represents a significant increase. He described the change from an annual basis to monthly as an added difficulty. Mr. Hanley supported the net operating loss carried forward as an equity issue that was adequately addressed in the HRES version. Anadarko also supports an in-state gas use provision. Generally, they support the changes made to the exploration incentive credits, although they are retroactive to January 1, 2007, which is not the benefit it seems. The new program under the EIC requires permission from the commissioner before drilling a well to get those credits; wells drilled the previous year could not technically get permission. Mr. Hanley spoke to costs. He stated frustration with debate during PPT that companies were over-estimating costs in order to make returns look lower. He disputed the idea that increased taxes make it more attractive for companies to invest. Mr. Hanley maintained that legitimate costs should be allowed to be deducted. He questioned Section 53, which he says modifies Section 52 due to the potential of court proceedings. He felt the bill went too far. 1:02:34 PM PIONEER NATURAL RESOURCES PAT FOLEY, MANAGER, LANDS AND EXTERNAL AFFAIRS, PIONEER NATURAL RESOURCES ALASKA, presented a brief PowerPoint presentation ("Pioneer's View of CS HB 2001 (RES)," Copy on File). He noted the difficulty of the issues. He focused on the unique aspects of Oooguruk and its net profit share leases, consisting of a government take of 83 percent. He asked that the net profit share payment be creditable against the progressive element of PPT. Mr. Foley explained that Pioneer entered Alaska in 2002 to drill exploration wells at Oooguruk that led to a successful development. Pioneer also owns an asset in Cook Inlet called Cosmopolitan where they hope to have a development project. They have 1.5 million acres on the North Slope, mostly on the National Petroleum Reserve Alaska (NPRA). Their exploration partners are ConocoPhillips and Anadarko. Pioneer has drilled 11 exploration wells and has local staff of 35. Oooguruk, their cornerstone project, is an off-shore development that is about 70-90 million barrels in size. Production should start in 2008 and at peak should produce between 15,000 to 20,000 barrels per day for a period of 25 years. 1:05:59 PM Mr. Foley explained that Pioneer is the first independent North Slope operator. Production will go through a line and connect to the Kuparuk River unit, which will process their crude. He said many potential investors are assessing the success of this project. Mr. Foley spoke to the condition of local industry. Pioneer thinks there is limited activity for new players. The North Slope has been dominated by the major producers. He questioned if Alaska was attractive to independents for investment. He provided a list of the companies that drill the most wells in the lower 48. Pioneer and Anadarko are the only ones on that list that are in Alaska. He thought Alaska should decide if their policies are attractive to independent investors. Mr. Foley explained that in the Lower 48, there is a shorter cycle time and profits are greater. One of the reasons is no progressivity, so companies can capture the price upside. 1:11:13 PM Mr. Foley stressed that progressivity is an attempt to capture the windfall of upside prices. He maintained that for leases with a net profit share payment, the upside is already being captured. At Oooguruk, leases have a 30 percent net profit payment. They pay a royalty, a net profit, PPT, state, and federal taxes. The company take is 17 percent. The government take on Oooguruk is 83 percent based on total life cycle costs and a $70 deck, and it is all discounted. There is almost nothing that can reduce the government take at Oooguruk to less than 80 percent. Mr. Foley explained a pie chart on Slide 6 that details the numbers: · 18 percent to Alaska royalty; · 8 percent to property tax; · 18 percent to net profits; · 9 percent to progressivity; · 4 percent represents the base tax; and · 15 percent to PPT. Mr. Foley asked for a change in the bill that would allow a net profit payment directly creditable against progressivity. 1:15:34 PM Mr. Foley displayed a map with the leases and numbers from the Division of Oil and Gas website with 2006 net profit share payments totaling $87 million. The biggest payee is BP. Mr. Foley discussed concerns with changes to the EIC program. He maintained that the proposed program would be cumbersome and reduce incentives and concluded that a program without certainty discourages investment and exploration drilling. He pointed out that the bill requires geologic logs and "all derivative work products." He contended the impossibility of compliance. 1:19:53 PM Mr. Foley concluded that Pioneer has been an aggressive investor in Alaska and hopes to continue to pursue their goals. They worry about the balance tipping. Currently, the vast majority of Pioneer's investment opportunities are not burdened by progressivity. Their price upside is retained. He emphasized that at higher prices, Alaska opportunities are less competitive. Under progressivity, if the piece is taken off the upside in Alaska but not in Texas for a comparable project, the investment will be diverted to Texas. He reiterated their request to have the net profit share lease be credited against the progressive element of the production tax. Pioneer has earned all of the allotted TIE credits. The money was spent on wells, which resulted in Oooguruk. Pioneer would lose $33 million with a cutoff date. Mr. Foley asked members to consider if the bill motivates the desired behavior. 1:24:18 PM CHEVRON JOHN ZAGER, GENERAL MANAGER, CHEVRON-ALASKA, provided members with a PowerPoint presentation ("Testimony on SB2001/HB2001," Copy on File). Chevron is increasing investment in Cook Inlet and North Slope exploration under PPT. He stressed that they have over 500 employees and contractors, which will increase if their operations continue. 1:26:53 PM Mr. Zager pointed out that taxing the upside will deter investment. Slide 3 depicts possible outcomes for well success and failure. He demonstrated the concern that the tax is being added after companies have taken a carefully calculated risk and succeeded. Even the most positive outcome is significantly impacted. A change to the tax changes the risk and will influence decisions to drill. 1:30:51 PM Mr. Zager asserted that the legislation has moved in only one direction. He thought the base tax rate will likely increase. Alaska has a resource that it is trying to sell or lease. The customer is the oil and gas industry. The price is the government take, which must be compared on a worldwide basis. He gave examples of sales and asserted that industry is sending the message that the product and price in Alaska is not competing. He asked for consideration of that while determining the base tax and progressivity. Mr. Zager stated concerns about TIE credits. He clarified the usage of the terms income, earnings, and profit. Profit is related to PPT. Both earnings and income have depreciation included in the calculation. Early on it was decided that depreciation would not be allowed in the calculation under PPT. This means that credit could not be gotten for money invested in the previous year, and becomes a tax on cash flow. The decision was made to include the TIE credits as a proxy for that. The new bill would reduce or eliminate TIE credits. Mr. Zager spoke against the retroactive effective date. He did not think the impacts from the disallowance of costs are known. It would either disallow very important costs-in effect, a tax increase-or create incentive to be inefficient. The language in SB80 and ACES had problems. Disallowing unanticipated downtime is problematic. Things such as compressors fail in the normal course of a project. He cautioned that the language should be kept simple. 1:39:11 PM Mr. Zager cautioned that provisions weakening tax payer confidentiality are problematic. He discussed the multiple layers of penalties for mispayment or errant reporting. He questioned the reasonableness of the legislation. 1:41:25 PM Mr. Zager addressed committee member concerns about industry misrepresentation of costs. Slide 5 includes excerpts from 2006 testimony to the House Finance Committee regarding accelerating costs. He asserted that industry had been very clear about rising costs. Mr. Zager closed with questions for the members (Slide 6): · To what degree are you willing to risk future oil and gas investments in Alaska? He differentiated between PPT and ACES. He thought PPT put incentives in place to encourage investment. He did not think the new legislation would; the discussion was the degree to which it would hurt investment. · To what degree are you willing to risk the Alaskan economy? · Is Alaska "open for business"? · Will Alaska have more or less opportunity for our children after this bill passes? 1:45:54 PM ALASKA VENTURE CAPITAL GROUP/BROOKS RANGE PETROLEUM EDGER DUNNE, MANAGER, ALASKA VENTURE CAPITAL GROUP (AVCG)/BROOKS RANGE PETROLEUM, PRESIDENT DUNNE EQUITIES, (testified via teleconference), read testimony by Ken Thompson, AVCG Managing Director (taken from "Comments on ACES Petroleum Tax Proposal, October 2007," Copy on File): Alaska Venture Capital Group is a privately held member company with a technical and operational services' subsidiary company called Brooks Range Petroleum, with offices and staff in Anchorage. In Alaska and on the North Slope, we operate under the name Brooks Range Petroleum. AVCG has lease holdings and explores currently only in Alaska, nowhere else. AVCG/Brooks Range likes to think of our company as "Alaska's Independent Oil and Gas Company." We have been very active in the past seven North Slope area wide lease sales and active in acquiring acreage held by other companies where we see potential. We and our partners currently hold over 300,000 acres of exploration leases in five exploration prospect areas on the Slope. Our exploration strategy is to explore in the central part of the North Slope for fields in the 10-100 million barrels range. This past winter for the first time, our operations subsidiary, Brooks Range Petroleum operated the drilling of two exploration wells and ran a 130-square mile 3D survey over our acreage and surrounding area in the Gwydyr Bay area on the North Slope. This past drilling season, our group invested over $44 million on land, seismic and drilling activities. This winter our group will be among the most active of explorers as we plan to shoot over 200 square miles of new seismic data on the extreme western and eastern sides of the Central North Slope and to drill up to four exploration wells. Our group will spend over $40 million on seismic and exploratory drilling in winter 2008. At the end of next season, AVCG since 1999 and our partners since last year will have jointly invested over $100 million in Alaska even though none in our group have generated any revenues yet from Alaska oil, so we sincerely appreciate being listened to. We think in the long run we can bring substantial, incremental value to the State of Alaska. Our company prefers that the PPT be allowed to run its course in the next few years, and that ACES not be approved with its current provisions. Here are some suggestions of things not to change in the ACES proposal: 1) Keep the exploration and development investment tax credits. For a small explorer startup company like AVCG, the exploration economics with the exploration tax credits ranging from 20-40 percent as provided by PPT and with ACES are more favorable with an improvement in the investor's rate of return as compared with Alaska's old severance tax system. 2) Keep the "standard tax deduction/exemption" for smaller companies. The "Small Producer Tax Credit" that exempts up to the first $12 million in production taxes for smaller companies can allow us to return a larger share of our annual cash flow for exploration and investment while we build the company to a critical mass of reserves and production necessary to expand staffing and have a routine level of major capital spending each year. 3) Keep the new ACES tax credit allowance for qualified delineation wells. A new proposal in the ACES bill that was not in the PPT law is the possible tax credit allowance for the investment in up to two delineation wells following a discovery. This would be very helpful to small explorers as well as for large companies on the North Slope where often one well is not enough to determine if field size is large enough to warrant development. 4) Keep the revised progressivity tax rate at 0.2 percent per dollar increase in oil price. 5) Do establish the Oil and Gas Tax Credit Fund for the purposes of purchasing certain tax credits from explorers and producers. This is extremely important for AVCG to then be able to plow those credits back into seismic and exploration on the North Slope. Four things to change in ACES: 1) Change the recovery of tax credits from two years as proposed in ACES back to the recovery of credits in one year currently provided for in the PPT law. For a small company like ours, this will definitely affect our capital spending in a given winter as we plow all the credit refunds back into seismic or exploration drilling. We hope full credit can be applied for and refunded in a given year. 2) Change the base tax rate in ACES from 25 percent back to the PPT tax rate of 22.5 percent, and re-review again in 2011 as allowed for in current law. In other producing states that compete for investment by our AVCG investors, the state and federal combined government takes in 2006 averaged 45-57 percent. This was from the Gulf of Mexico, Colorado, Wyoming, Kansas, Texas, New Mexico, Oklahoma, California, and Louisiana. Those figures include a 12.5 percent royalty. These states do not have the added progressivity surcharge tax which further separates Alaska in government take from these competing states. Alaska should have a government take of 55 percent if we were to maintain long-term competitiveness with these other states for investment dollars. Some of these states do not have the prospectivity of Alaska, so Alaska could command some premium in take, but not as high as being proposed in ACES. 3) Change the trigger price to $40 per barrel net and not $30 per barrel. If the government take is to be the fair and equitable 60 percent and not the unfair 68 percent, the trigger price should stay the same as in the PPT law, i.e. $40 per barrel net. If Alaska is to share in high prices with the progressivity surcharge tax, then Alaska should share in the pain of low prices. 4) Consider some type of TIE credit. This provision allowed for in PPT was repealed in ACES. While this provision does not greatly benefit our company because we did not have large seismic or exploration drilling costs between March 31, 2001, and April 1, 2006, it is important to other major investors in Alaska. As an example, the largest explorer and developer in Alaska, ConocoPhillips, now with the ARCO heritage assets was hardest hit in tax exposure with the change from the old severance tax law to the PPT and now to ACES. Allowing a good steward who is the largest explorer in Alaska some transition allowance to ease the pain of greatly increased taxes is the right thing to do and can only build better, more trusting relationships. In conclusion, we've tried to share the perspective of an independent exploration company that only invests in Alaska. My ultimate wish would be to leave PPT alone and re-review it under the law as planned in 2011 or perhaps even in 2010. I urge you to at least consider the five things our company would not change in this bill and the four things we would change. 1:57:39 PM ALASKA OIL AND GAS ASSOCIATION MARILYN CROCKETT, EXECUTIVE DIRECTOR, ALASKA OIL AND GAS ASSOCIATION (AOGA), read from testimony ("Testimony of AOGA to the House Finance Committee Regarding CSHB 2001 (RES), November 8, 2007," Copy on File). She described AOGA as a trade association for the oil and gas industry in Alaska with 17 member companies, including the Agrium plant, Alyeska Pipeline Service Company, and three in-state refineries. These companies account for the majority of oil and gas exploration, development, production, transportation, refining, and marketing activities in the state. Ms. Crockett explained that when AOGA voices a position, regulators and legislators can be assured that it is the position of the overwhelming majority of Alaska's oil and gas industry because AOGA provides a forum for its members to reach agreement about industry positions. On tax issues, the AOGA tax committee requires complete consensus. Therefore, there is no dissent among AOGA membership regarding this testimony. 2:00:08 PM Ms. Crocket pointed out that AOGA has focused their comments on two key areas: first, declining production levels and the importance of investment to address that; and second, through the tax committee, which has many member companies and extensive experience, AOGA wants to respond to technical issues raised by the new legislation. She added that the tax committee has not had the time to generate qualitative analysis on the proposed options and will submit that later. Ms. Crockett commented on accusations that industry intends to take advantage of the state and cheat on their taxes, even to the point of deducting costs such as lobbying expenses. She pointed out that this would be against the law and is an insult to the employees of the companies. Ms. Crockett described the rigorous auditing provisions within the industry. Individuals would not cheat on their taxes if they knew there was a 100 percent chance of being audited, as oil companies are. Every return filed by the oil industry is audited by the state by high qualified auditors. 2:03:04 PM Ms. Crockett stated concerns about the Gaffney Kline economic model. It was designed to focus on a single investment decision in legacy fields and does not take into account investments in heavy oil and the investment challenges of exploration activity, and other things. She cautioned against using only that model and its results. Ms. Crockett addressed declining production levels. Nearly 90 percent of the state's discretionary money comes from the oil and gas industry, making production levels the cornerstone of Alaska's economic future. She referred to a chart on page four of her written testimony depicting declining North Slop gas production. North Slope production has declined at a rate of 6 percent between 1997 and 2007; Cook Inlet has declined by 8 percent during the same time. She maintained the 6 percent rate is the result of continued investment by the companies, and would have been 15 percent without these investments. Ms. Crockett spoke to the mechanical capacity of TAPS, which is 200,000 to 300,000 barrels per day. Different decline rates are outlined in the charts on page 5. The chart of the left shows the time to decline from 740,000 barrels per day in FY 2007 to a 200,000-barrel-per-day threshold, the one on the right shows the time to get to 300,000 barrels per day. At a 6 percent rate of decline the 200,000-barrel threshold is hit in 21 years, but at a 3 percent decline it would take 43. If the threshold is 300,000 barrels per day, it would be hit after 15 years at 6 percent and 30 years at 3 percent. Ms. Crockett stated that opportunities exist that should allow the rate of decline to be slowed to below 6 percent. These opportunities are in oil and gas exploration, in the development of the huge resources of heavy and viscous oil that are already known to exist, and in the renewal and continued development of existing fields. She referred to previous testimony explaining different kinds of investments and production levels needed if Alaska is to meet the challenge of production decline. Ms. Crockett emphasized that heavy and viscous oil lie within the areas of the so-called "legacy fields," as does the preponderance of the remaining opportunities for obtaining more "conventional" oil out of currently producing fields. The renewal of the existing fields will become increasingly important, as the existing production facilities need to be adapted, retrofitted, or even replaced in order to be fit for service for the coming decades. Ms. Crocket added that infill drilling to drain the spaces between the existing wells, or develop new oil, offers the best promise of slowing decline in the short term. The pattern and timing of the cash flows are very different between infill drilling and renewal of major production facilities on the surface. Even within a legacy field, without considering its resource of heavy and viscous oil, there is significant variation among the investments to be made, the economics for those investments, and the incentives. She felt it would be a serious mistake to treat the legacy fields as economic monoliths, impervious to how they are taxed and unaffected by the incentives that may be granted or withheld. Ms. Crockett spoke to stability. In 2005, the industry was faced with a $120 million tax increase. She pointed out that implementation of PPT increased the tax by $800 million during the first nine months of 2006. The HRES version proposes to increase the production tax again to $1.5 billion, over the PPT currently in place. Ms. Crockett maintained that there are serious misconceptions about the models that are being used to demonstrate potential impacts of a tax increase on investment decisions. She stressed that there has been a serious underestimating of the effects on future investment, especially regarding exploration, heavy and viscous oil development, and renewal of conventional fields. The laws of economics stipulate that there will be an adverse effect on investment decisions if the House CS becomes law. She asserted that the future of Alaska was at stake and urged the legislature to pull back. 2:11:56 PM Co-Chair Chenault referenced the Gaffney Kline economic model and noted that Mr. Rich would be provided an opportunity to testify at a later date. RECESSED: 2:13:19 PM RECONVENED: 2:16:29 PM Representative Hawker questioned the rules related to net profit share leases (NPSL). Mr. Foley explained that NPSL are 30 percent of net profits paid directly to the state in addition to 12.5 royalties. The cost of doing business is royalty plus net profit share, deductable against PPT and state income tax. There is a difference between a deduction and a credit. Representative Hawker observed that the standard royalty payment is 12.5 percent. He pointed out that Pioneer has filed for and secured royalty relief, so it is not 12.5 percent. Mr. Foley agreed and explained that 80 percent of the Oooguruk resource falls on four NPSL with a one-eighth royalty and a 30 percent net profit. He added that 20 percent of the resource falls on other leases with a one- sixth royalty. Royalty reduction was received and takes all of the royalties to a floor of 5 percent until payout, which is at the same time that the net share profit account pays out. The royalties begin to increase with the NPSL payments over a level three-year period back to current rates. At payout, the royalty jumps from 5 percent to 6.875 percent. There would be additional increases of 1.875 percent in each of the next two years, which takes them to their full royalty amount. Representative Hawker understood that the royalty relief provisions phase out over time. Mr. Foley stated it was totally dependant upon price. At $70 dollars, the effective royalty rate payments, discounted at the weighted average, is a little more than 8 percent plus 30 percent net profit. Without royalty relief the effective rate would be closer to 13.5 percent. 2:22:55 PM Representative Hawker summarized that NPSL are uncommon in Alaska at this time. Mr. Foley agreed that they are fairly uncommon. In the 1980s, the state started issuing leases with a fixed net profit component, such as the North Star leases. The North Star leases were subsequently amended and a sliding scale was applied. Pioneer is unique in that more than 80 percent of their resource falls on net profit share leases. He named other units that had NPSL. Representative Hawker wondered at the uniqueness of the circumstance and questioned if NPSL should be considered for Point Thomas in the future. Mr. Foley responded that the issue is appropriate for all NPSL. The progressivity is an attempt to capture the price upside. A large portion of the upside would already be captured by NPSL, greater than through progressivity. Representative Hawker acknowledged the merit of the debate, but encouraged members to look for parity. He summarized that the excess of the aggregate payment over 12.5 percent would be applied to relief, but would not be applied against base state taxes, just progressivity. Mr. Foley agreed and hoped it would be applied against progressivity. He emphasized the importance of having a relatively level playing field. He referred to Oooguruk with a government take of 83 percent, even with the benefit of royalty reduction. Without royalty reduction, the number would be even more favorable to the state. 2:28:12 PM Representative Hawker argued that the issue of equity was merited. Representative Gara claimed that DNR would have a different perspective. He observed that royalty relief was granted to Pioneer under the prior administration just before implementation of PPT. According to DNR, the economics of Oooguruk after royalty relief was better under PPT than under ELF. The net present value increased because they could write off their deductions and credits right away, which they could not do under the old ELF system. Department staff recommended a less generous royalty relief than the prior commissioner had granted. He concluded that the dollar value of Oooguruk doubled in terms of net present value from ELF and royalty relief to PPT. Mr. Foley stressed that their request for royalty relief was made through an open and transparent process, but emphasized that the pricing environment is different today. Actual costs were higher. Determinations are made on estimates, but oil has not been produced yet. When the royalty reduction was granted, the project showed a modest rate of return. He maintained that the project would not have happened without royalty reduction. The type of return their project delivers is dramatically less than some of the numbers suggested would apply for an infill well in the North Slope field. 2:32:45 PM Representative Gara assumed that Pioneer did everything properly. He observed that progressivity does not apply until there is $30 in profit above costs. Mr. Foley stated that originally under PPT, progressivity was designed to counteract the regressive nature of royalty. Take would stay relatively constant as price increased, but the take goes up as the progressivity amount is increased. He felt there was a shift between PPT and the current conversation. Representative Gara observed that Oooguruk would be more profitable now than under ELF at lower prices. Mr. Foley acknowledged the higher prices, but questioned if they would remain over time. 2:34:52 PM Representative Kelly asked about the uplift credit, which was intended to help launch the project. He proposed that progressivity is what a company should be paying. Co-Chair Chenault suggested that members interested in the subject get together with DNR and Mr. Foley to address the issue. 2:37:11 PM Representative Foster referred to an interaction he had with Chevron in rural Alaska in the late 1970s that illustrated that the price would never go down. Co-Chair Meyer pointed out that Chevron, while sitting with the small companies, is one of the largest. Mr. Zager explained that Chevron is the second largest U.S.-based company with a market cap of $200 billion and interests worldwide. Co-Chair Meyer questioned how Alaska looks in comparison to other places in terms of investments. Mr. Zager observed that U.S. production is about 320,000 barrels per day and noted that Chevron has major operations throughout the world. He detailed some of their operations. He reports to [Chevron's] North America organization. Most of the capital competition is with other areas in the Lower 48. However, the North Slope exploration program was evaluated against other projects around the world. Co-Chair Meyer asked about investments in Africa versus Alaska. He questioned Alaska's competitiveness. Mr. Zager answered that Alaska is having difficult competing for capital. He pointed to lease sales, and observed that people are not coming to Alaska. Most of those in the lease sale were already in Alaska. There are large resources in the other international countries such as Angola that have large government takes. He acknowledged security risks, but stressed that they are minimized by being offshore. Security risks are not huge in terms of financial risk. Government takes cannot be viewed independently of the resource. He suggested that there would be aggressive bidding on ANWR because of the perception that it is a world class field. Offshore terms in the gulf are also attractive. 2:46:06 PM Representative Gara observed that Gaffney Kline's model is for a five-year drilling program. This would explain the results Ms. Crockett obtained when she put zero in as a value. Representative Crawford asked if who controls the lease field would affect the lease sales. He observed that control of the deep Gulf is not yet established, which would explain the interest. Mr. Zager agreed that there is competition for infrastructure in the deep Gulf. New fields in the North Slope are assumed to be small enough to be dependent on the current infrastructure. Producers would not be concerned about going through Kuparuk or Prudhoe Bay if they thought there was a billion barrel field. Representative Crawford acknowledged that billion barrel fields are common, but felt 50 million barrel fields could pay if there were not barriers to access. Mr. Zager stressed the difficulty of facility sharing agreements, which require complicated negotiations. He maintained that being an owner does not guarantee access. 2:53:06 PM Representative Kelly asked if the access issue was in the realm of reasonable. Mr. Foley observed that there have been lengthy negotiations with Kuparuk related to access. He was pleased with their progress and anticipated positive results. He did not feel the current owners were a barrier to entry, although there were challenges to the process. The agreement is complex and important, and takes time. 2:55:00 PM Representative Kelly referred to the House version of progressivity with a net trigger and gross application that result in a higher effective rate. Something that appears to be 0.2 is actually 0.25. He questioned if Pioneer would prefer removal of the floor, or to pick up two tenths on progressivity, assuming the gross would be adjusted to reflect two tenths. Mr. Hanley responded that the lower progressivity would be better for Anadarko, although he had not modeled the proposition because the floor did not affect them. Mr. Foley noted that Pioneer was also not an owner and would not be affected by the floor. He would trade a floor for progressivity. Pioneer is affected by progressivity, but he did not think it was a fair exchange. Mr. Zager noted that they are small owners in Prudhoe Bay. He thought that Chevron would oppose the floor based on a structural issue. He suggested that there would be a relatively small financial impact. He was opposed to the floor on principle. He observed that PPT is a statewide tax that allows credits to be moved. Profits come out of Kuparuk and Prudhoe Bay. The inability to transfer credits can cause problems. He felt that the floor should be removed and progressivity reduced. 3:01:24 PM Representative Gara suggested that the immediate receipt of deductions and credits to new exploration was a positive aspect of ACES or PPT, which is not a common feature most places. Mr. Zager acknowledged that immediate receipt is a favorable feature. He observed that production sharing contracts (PSC) vary depending if it is current or existing. Revenue is generally divided into cost or profit oil. Mr. Hanley added that Alaska's winter drilling season is an additional challenge. The exploration program ties money up longer and the remedy would provide a slight benefit and help offset the challenges of doing business in Alaska. RECESSED: 3:05:09 PM RECONVENED: 3:13:37 PM RICH RUGGIERO, CONSULTANT, GAFFNEY, CLINE AND ASSOCIATES INC., reviewed the modeling they provided. He explained that modifiers do not change history, except on capital expenses. All the money spent on the drilling program through 2006 demonstrates that extra oil and sales result in a 156 percent rate of return on investment. The control page shows fixed prices. Field revenue is shown in line 16. The price of oil only affects the future. Oil companies have acknowledged that the model is an accurate reflection of their infill drilling program. The model pertains to the infill portion of the North Slope. ConocoPhillips and BP testified that infill drilling represents 30 percent of the oil or the business that is possible on the North Slope. Mr. Ruggiero agreed that 300 percent is the actual capital expenditures (CAPEX) since BP testified that they spent an additional two dollars on injections and facilities for every dollar spent producing a well. He maintained that there would be a 22 percent return if all the oil is shut off at the end of 2006. There would be a 55 percent return for oil in the $40 range going forward. All the multipliers aside from the CAPEX only impact the future from 2007. Any result from putting in zero is the money the oil company has already made from infill drilling. 3:19:08 PM Co-Chair Chenault clarified that CAPEX is on a five year investment. Each year is an investment. He questioned why companies are not investing in Alaska if the rate of return is 53 to 55 percent. He concluded that it must more profitable to invest elsewhere. He wondered what he was missing. Mr. Ruggiero suggested that it is a reflection of prospectivity. There are significant logistical issues to operations in Alaska. People are the scarcest resource. Opportunities must be significantly better to warrant the movement of people. 3:23:26 PM Mr. Ruggiero observed that the model would vary base rate and a single progressivity factor, and stated that they would attempt to allow for multiple progressivity factors. DUDLEY PLATT, PETROLEUM ENGINEER, DEPARTMENT OF REVENUE (DOR), claimed that the Alaska fields are healthy with a reduction over the next eight years of 67,000 barrels per day, including both state and federal oil. Filtering out the federal oil, the state reduction is 39,000 barrels per day for the next five years, when payback begins. Mr. Platt constantly evaluates the producing characteristics of the fields. The state of the fields is healthy; Prudhoe Bay and Kuparuk are capable of producing. He verifies the timing of new development projects, such as Oooguruk and heavy oil. Adjustments result in a slight delay of six months to a year, which is normal in new projects. The pace of heavy oil development was slowed to reflect challenges and commercial issues. The largest change falls into these components. A larger expectation was included for downtime attributed to both planned and unplanned events. Additional downtime was been added for the impact of infrastructure renewal. He concluded that there will be significant changes in the five to eight year time frame. 3:27:21 PM Co-Chair Meyer observed that the true challenge is the decline of production, which has been masked by high oil prices. He asked if raising taxes on the oil industry would solve the problem of declining production. Mr. Platt was unable to respond. In response to a question by Representative Kelly, he said 25,000 to 30,000 barrels per day is related to the two biggest factors of decline. 3:29:22 PM Representative Gara asked for an estimate of daily production for the next two years. Mr. Platt estimated FY 2008 production at 732,000 barrels per day, barring unanticipated additional downtime and depending on winter conditions. He did not know the estimate for the following year. 3:29:57 PM Co-Chair Chenault noted that it was not the intent of the Resource Committee to delete the 25 percent cap from progressivity. BARRY PULLIAM, SENIOR ECONOMIST, ECON ONE RESEARCH, CONTRACTOR, LEGISLATIVE BUDGET AND AUDIT COMMITTEE, explained that he would detail the effects of different components of the legislation working through the House, using PowerPoint presentation "Estimating Financial Impacts of Various Approaches to Current (PPT) Provisions," (Copy on File). He reviewed the chart on Slide 2 depicting the base tax rate change in different versions of the legislation from 2008 to 2014, including HB 2001, the House Oil and Gas (HO&G) version, and the House Resources (HRES) version. He observed that the column of numbers beneath HB 2001 shows the annual average difference attributable to moving from the 22.5 percent rate in the current PPT to the 25 percent in HB 2001. The next column, HB 2001 (O&G), did not change the base rate from 22.5 percent, making those figures zero. The HRES version was changed to 25 percent, so those numbers match the HB 2001 column. He noted that the volumes included come from the state estimates and will change. 3:34:02 PM Mr. Pulliam spoke to the impact of the progressivity in the various versions of HB 2001 (Slide 3). The Governor's version starts at $30 dollar net and has a flatter (0.2 percent) slope. More money would be raised at the lower price levels because the slope is smaller than the current PPT; the progressive portion does not bring in as much as the current PPT does, translating to positive numbers at the $60 and $80 dollar per barrel level and negative numbers at the $100 and $120 dollar level. The HO&G version has a steeper slope that is tied to the gross, resulting in greater revenue generated on the progressive piece. In the HRES version (without a cap), progressivity is triggered at different stages ($30, $40, $50, and $60 net) at different factors (0.2 - 0.5 percent) applied to the gross. The HRES version is the most progressive, even with the cap. Representative Kelly asked if the cap would affect only the bottom line. Mr. Pulliam thought it might affect the $100 level as well. 3:37:08 PM Mr. Pulliam spoke to the TAPS tariff (Slide 4), which applies in the HRES version. The current PPT and HO&G versions have the tariff deducted based on whatever is filed and approved by FERC. The HRES version also contains a provision that allows the state to determine the just and reasonable rate of the TAPS tariff based on actual costs, regardless of the FERC outcome. If the state were to determine the rate, and the numbers coincide with the DNR estimate of $2.50 per barrel, there would be a reduction of several dollars relative to what is currently on file with FERC. These filings have been challenged by producers and the state; the result of the regulatory FERC process could be tariffs in line with intrastate tariffs. If the tariffs remain as filed, the average tariff over the period through 2014 would be 90 cents per barrel lower than the current projects over a number of years. That would generate around $53 million dollars a year; most of the difference would be in the next couple of years. Representative Kelly wondered if only producers or TAPS owners that would be affected, excepting Anadarko, who has no pipe. Mr. Pulliam affirmed that would be true if they actually ship and pay the higher rates. Representative Gara thought the change may be worth $100 million a year. Mr. Pulliam did not think that the change would rise to that level, but noted there could be greater value in the next couple of years. The tariffs currently on file are $5 per barrel. If FERC follows through with staff recommendations, those tariffs would fall $2-3 per barrel and generate, in the near term, around the $100/year. The settlement is about to expire; the assumption is that rates will fall with the expiration. He observed that $53 million reflects an average. 3:41:54 PM Mr. Pulliam spoke to how the different versions of the bill approach TIE credits (Slide 5). The original HB 2001 version does not provide for TIE credits, which would result in a difference of $176 million per year over the 2008 to 2014 period. The credits phase out in 2013 for those that have had production. Both the HO&G and HRES versions would limit the TIE credits to a three-year period beginning in 2003. This limitation would result in $47 million annual difference relative to the current law. 3:43:15 PM Mr. Pulliam spoke to the effective tax rate on the gross value of the oil at different ANS price levels (Slide 6). He compared different tax rates on gross taxable value. He observed that PPT provides the lowest rate on average; HB 2001 raises the effective tax rate at lower prices. As a result of lower progressivity, the difference narrows at higher prices. The HO&G version is closer to PPT at lower prices, but crosses over at $80 per barrel at higher progressivity. The HRES version has the highest effective tax rate overall because it combines a higher initial tax rate and high progressivity. A cap of 50 percent would come at just before $120. 3:45:22 PM Representative Gara observed that the Governor has expressed support for a 0.4 progressivity. Mr. Pulliam stated he would provide information regarding the Senate JUD version of a $30 dollar net trigger with a 0.4 progressivity. Representative Kelly asked if the $30 net trigger with a 0.4 progressivity would be imposed on the graph and distributed to the group. Mr. Pulliam agreed. Representative Gara questioned if the 0.4 progressivity proposal would start higher at the lower prices ($60 - $70 per barrel), but be lower at higher prices than the HRES version. Mr. Pulliam observed that it would flatten out with the cap. The HRES version would show more acceleration, while the SJUD would be more linear in its increase if both were capped. Representative Gara asked for clarification. Mr. Pulliam thought the SJUD version would cross the Governor's proposal at $55 per barrel. The HRES version would be in the $50 to $55 per barrel range. 3:48:35 PM Mr. Pulliam reviewed tables on Slides 6 and 7 regarding the estimated average effective tax rate on gross taxable value, and government share, marginal government share, and estimated annual revenue impacts relative to current law. He differentiated between the $80 and $100 levels; previous charts topped out at $80 per barrel. Mr. Pulliam highlighted that government share differs, but relationships mirror the previous chart. Marginal government take was introduced by DOR and represents the share of revenues that would go to state and federal governments when prices rise by $1 per barrel without any other changes. The HRES version at $80 to $100 dollar per barrel results in extremely high marginal takes. The collective take could exceed the increase without a cap. He added that there would be a volume adjustment of approximately 38,000 barrels per day over the next six years, which would impact the revenue forecast. 3:52:41 PM Representative Hawker clarified that the same data points were used throughout the report. Mr. Pulliam noted that variance result from the impact of the floor. Representative Kelly asked a question about real dollars. Mr. Pulliam explained that the per barrel prices were in real terms with inflation of 2.75 percent a year. Revenue statistics are in nominal dollars. 3:55:18 PM Representative Hawker asked if the fiscal note numbers were consistent with DOR fiscal notes. Mr. Pulliam observed that Econ One's analysis is within two percentage points of the DOR's. He acknowledged that the department has more specific information. 3:57:16 PM Mr. Pulliam referred to a chart provided for the Senate, which showed SJUD crossing the Governor's proposal around the $50 to $55 per barrel range. He observed that the highest rate tops out at 85 percent and then declines and flattens as a result of the cap. 3:58:18 PM ADJOURNMENT The meeting was adjourned at 3:58 PM.