HB 2001-OIL & GAS TAX AMENDMENTS 9:17:20 AM CO-CHAIR GATTO announced that the only 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." [Before the committee was CSHB 2001(O&G).] CO-CHAIR GATTO then reviewed committee procedure and introduced the first speaker. 9:18:38 AM CRAIG HAYMES, Production Manager - Alaska, ExxonMobil Corporation, Anchorage, Alaska, paraphrased from a prepared statement, which read as follows [original punctuation provided]: ... I want to thank the committee also today for the opportunity to testify on this important issue in front of us. I'd like to mention the packages we've given you. We have an executive summary on the front of our written testimony and the executive summary is about six pages long and that's to help facilitate the discussion today and hopefully will help you follow as we go along. I would like to start and talk about ExxonMobil and ExxonMobil in Alaska. ExxonMobil has had a presence in Alaska for over 50 years and has been a key player in the development of Alaska's oil industry. We have spent and invested over $20 billion dollars in Alaska. We are currently very active with our co-owners at Prudhoe Bay, Kuparuk, Duck Island, Granite Point and Point Thomson. Our current working interest share of production in the State is approximately 150,000 barrels of oil per day and we are also the largest owner of discovered Alaska gas resources. We certainly look forward to working with Alaska for many more years to come. 9:20:26 AM I would like to state upfront that ExxonMobil believes the current PPT tax rate and the proposed increase will not result in the additional investments required to maximize development of Alaska's resources. When you consider Alaska's resource potential and the current production decline, ExxonMobil does not support the Administration's proposed tax increase. Alaska has significant undiscovered resources - both oil and gas; but oil production is declining. Increasing investment in Alaska is required to mitigate production decline. Government and industry have a common goal: to maximize economic resource development of oil and gas. The full development of Alaska's resource potential will require extensive collaboration and focus from all parties. We need to work together - government, the industry, and the people of Alaska to enhance the development of Alaska's resources. ExxonMobil believes that Alaska needs a long term resource development policy, a policy that will encourage increasing investment - increasing investment needed to mitigate production decline, a policy that will encourage the full development of Alaska's oil and gas resources. With that I would like to talk about Alaska and the significant oil and gas resources it is blessed with. 9:22:11 AM To date Alaska has produced close to 17 billion barrels of oil - a world class result. According to the US Geological Survey and the US Minerals Management Service, Alaska still has undiscovered technically recoverable resources of over 53 billion barrels of oil as shown on the chart, the barrel - that's represented by the orange colors. This is in addition to the Department of Natural Resources' estimate of known or proven reserves of 6 billion barrels - that's shown in the dark green in the chart. When you consider this resource potential, Alaska has only produced one quarter of its resource. In other words, Alaska still has the potential to produce 59 billion barrels of oil. 9:23:22 AM CHAIR GATTO asked Mr. Haymes if his numbers include heavy oils. MR. HAYMES said the numbers include conventional oil only. CHAIR GATTO asked how much of the remaining three-quarters of Alaska's oil resource is recoverable. MR. HAYMES said if one assumes a crude price of about $60 per barrel, recovery of about half of the 53 billion barrels would be economically feasible, according to the federal agencies. He clarified the numbers he quoted were based on the mean. 9:24:10 AM MR. HAYMES continued: If you expand the resource assessment to include gas, on an oil equivalent basis, it doubles those 53 billion barrels. As you can see in the chart, there's about 259 trillion cubic feet of gas according to the U.S. Geological Survey and the U.S. Minerals Management Service. Alaska has significant oil and gas resources. While Alaska's resource potential is high, the Oil and Gas Journal and Energy Information Administration report that its world ranking of proved reserves has dropped from 14th in 1977 to around 30th today. 9:25:04 AM CHAIR GATTO asked how many rankings exist. MR. HAYMES noted every country in the world is ranked so the number is probably around 100. 9:25:16 AM MR. HAYMES continued: How can we commercialize Alaska's resource potential? I'd like to talk a little bit about Alaska's high cost challenges. Alaska is a high cost environment that challenges the pace of exploration and development of both existing and new fields. Alaska also has mature producing fields with significant challenges and growing unit costs. Many factors contribute to Alaska's higher costs. Some examples include severe Arctic conditions placing seasonal limitations on drilling and operations; a sensitive environment requiring significant and due diligence measures to protect it; remote location of its resource and distance to market and current restrictions for exploration activities. For any investor, higher costs reduce the attractiveness of any opportunity. We need to work together to reduce these high costs. 9:26:33 AM The effective application of technology is critical. We have been quite successful in the past at using technology to unlock Alaska's resources. Some examples include the installation of the ice resistant platform at Granite Point, which is still producing oil today. Another example is the completion designs at Prudhoe Bay for permafrost conditions. Another example is the installation of concrete oil and drilling systems that we used to drill the first exploration wells in the ice-covered waters of the Beaufort Sea. And, also, still in use today a 3D full-field simulation model for Prudhoe Bay, which continues to underpin enhanced oil recovery opportunities and development drilling opportunities. The application of technology will continue to be critical to the future pace of resource exploration and development activity. It will require significant long term research and investment. 9:27:59 AM CHAIR GATTO asked about the different conditions that are apparent in oil field developments and whether the Arctic environment is tougher because of distance to market. He noted the Arctic condition also offers some advantages; a 48-inch pipeline has plenty of room in it and ice roads can be built. He questioned whether the Arctic condition is harder for an oil company to develop by 2, 4, or 10 times. MR. HAYMES replied when the Arctic environment is compared to other areas where most of the oil and gas is being produced today, it presents unique challenges that increase costs. The remote location requires significant infrastructure to get the product to market. The North Slope is inside the Arctic Circle so drilling and operation and maintenance activities can only be done during certain times of the year. The increased costs are due to what is known as "waste," meaning a drill might sit at a location for weeks or months while awaiting a window of opportunity. In addition the rigs typically cost $20 million to mobilize and winterize because of severe conditions. Last, the offshore water sites must deal with freezing and thawing ice. 9:30:34 AM MR. HAYMES continued: I'd like to talk about Alaska's oil production. Alaska is currently producing approximately 750,000 barrels of oil per day from the North Slope - about one third of its peak. The Department of Revenue issued recently a forecast in the spring revenue sources book. You can see that in the chart. It is made of two components. Apparently current base production is shown in the green and then future "Under Development and Under Evaluation" is shown in the blue. 9:32:27 AM The department's forecast shows that the current base production in the green is estimated to decline at 9 percent per year and within 10 years will be down to around 360,000 barrels per day. The department's forecast also shows that this production decline will be partially mitigated or offset by the blue edge - "Under Development and Under Evaluation" component. That includes future investment opportunities, such as satellite development drilling, enhanced oil recovery from existing fields. Based on this forecast, 50 percent of the future production is not developed or producing today. If you consider that most North Slope projects take 5 to 7 years to bring to production, new term investment decisions for these activities will be critical to underpin future production as forecast here. If you turn to the next slide, as I mentioned earlier, the Department of Revenue's forecast is based on a 9 percent decline, as shown in the green, but this decline includes current production enhancement investment activities. The department forecast does not highlight that this activity requires investment decisions that are no different than the "Under Development and Under Evaluation" category. So, as such, a more accurate representation of the future investment levels required to achieve this forecast is shown in the chart below. 9:32:55 AM As this chart shows, Alaska's oil production could be as low as 150,000 barrels per day in 10 years without an ongoing increasing investment. Based on this forecast, within 10 years 75 percent of production will come from new investments. When you look at that component - the green hatched section and the blue section - conservatively we estimate at least $30 to $40 billion of investment is required to achieve this production forecast. We think 10 years. That does not include the billions of dollars of operating expenditures that would be required to support those developments once they are producing. This is a significant future investment spending level and substantially more than is currently invested today. 9:34:03 AM MR. HAYMES continued: I'd like to focus in a little more on the production and talk about Alaska's two largest oil fields - Prudhoe Bay and Kuparuk. They have been producing since 1977 and 1981, respectively. Today these two fields account for over 70 percent of our production on the North Slope. With continuing exploration and investment activity, these fields could remain at this level for the next decade. These 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 production of oil there are many changes - changes in reservoir pressures, oil, water, gas production levels, operating conditions, facilities utilization. In order to keep the oil flowing, ongoing additional investment is required. Such is the historical investment that's been at Prudhoe Bay for gas and water injection and gas compression facilities. Apparently the owners spent over $2 billion per year to optimize and enhance production from Prudhoe Bay and Kuparuk. That spending is in addition to the investments associated with development drilling, project activities and other enhanced oil recovery opportunities. These operating expenditures are critical to mitigate oil production decline. Prudhoe Bay and Kuparuk have the potential to continue to be critical contributors to Alaska's oil production. They also have the potential to remain hubs for other activities on the North Slope, whether it's in the pursuit of heavy oil, light oil, or gas. 9:36:07 AM Now I'd like to talk about a couple of examples of where this has worked. Many of today's exploration and development activities are occurring around Prudhoe Bay and Kuparuk. Since the year 2000 there have been multiple Prudhoe Bay satellite developments. Most of those today are contributing over 40,000 barrels of oil today. These satellite developments would not have been possible without the infrastructure of Prudhoe Bay and Kuparuk. They simply would not have been economic. As infrastructure on the North Slope continues to expand, it improves and creates economic viability for future satellite developments as the infrastructure continues to grow. Another example is development drilling in Prudhoe Bay and Kuparuk. Over the past 7 years, over 900 new wells have been drilled in those fields. The drilling of those wells has slowed the production decline from 9 to 12 percent, so 12 to 15 percent to 6 to 9 percent -and almost 40 percent of today's production at Prudhoe Bay is from these new wells. 9:37:17 AM CHAIR GATTO asked for clarification of the percentages. MR. HAYMES apologized for the confusion and explained that if no drilling activity occurred, Prudhoe Bay and Kuparuk would typically decline at 12 to 15 percent. Drilling activity would mitigate the decline to 6 to 9 percent. 9:37:42 AM MR. HAYMES continued: For the past two years, development drilling in Prudhoe Bay alone has developed the equivalent amount of resources as the important Oooguruk development. Prudhoe Bay and Kuparuk have the potential to continue to be critical contributors to the North Slope oil production. They also have the potential to remain key hubs - hubs that enable us in the pursuit of new heavy oil, light oil and gas as I mentioned. Encouraging increasing investment in these fields is critical and important to the future. Without these two hubs, Alaska would be severely challenged to realize the full potential of its resources. 9:38:28 AM Now I'd like to shift gears and talk about ExxonMobil's position on the enacted 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 structure, the proposed 20 percent tax rate as per the original PPT bill, and we said that it would not encourage a 20 percent full development of Alaska's resource potential. We agreed with the 20 percent tax rate in order to support the progression of a gas pipeline project. The PPT that was ultimately enacted increased the 20 percent base tax rate to 22.5 percent with progressivity, more than doubling industry's taxation. When combined with the gross royalties and the high cost environment, it produces the attractiveness of Alaska's resource developments. There has been a lot of discussion recently on PPT revenues and forecasts, which has been used in part to support the Administration's proposed tax increase. PPT has only been in existence for slightly more than one year. The Department of Revenue has not yet completed its regulations around PPT, nor completed an order. ExxonMobil, as well as a number of producers, met with the Department of Revenue several months ago to talk with them and help understand how we can help them improve their ability to forecast revenues. We're willing to continue to work with the Department of Revenue in that pursuit. We're also willing to work with auditors and our partners to improve the understanding of joint interest billings. 9:40:39 AM I would now like to talk about the Administration's proposed tax increase. In analyzing the Administration's tax proposal, we found that virtually all of the provisions of tax increases or further increases in complexity. In the summary you have in front of you there's four examples I'd like to talk about but, Mr. Chairman, and this is your call, the first two I realize are not in the current bill in front of you from the committee substitute, [Indisc.] with 10 percent gross minimum tax, ring fencing of the Legacy fields, and the additional reporting requirements for exploration tax credits so, in the interest of time I can move past those or, if you'd like us to talk about our perspectives, I can certainly do that. 9:41:24 AM CHAIR GATTO asked Mr. Haymes to describe ExxonMobil's perspectives. 9:41:54 AM MR. HAYMES said the 10 percent gross minimum tax would be in addition to the base royalty payments. With the minimum gross tax, the state would be insulated from price and cost risks while it would retain the upside potential from the progressivity element. He explained the proposal would shift the development risks to the producers. At low prices, the producers would be penalized. He continued: Progressing a tax policy that singles out and penalizes these fields will discourage investment, not only of these fields but would also impact investment attractiveness to explore and develop other Alaska oil and gas resources because of their dependency on that infrastructure. Companies are certainly willing to accept the risks of long-term capital investment but, when there's a corresponding opportunity for upside and potential, the economic risk increases significantly at a low price environment with the 10 percent tax proposal. 9:43:00 AM CHAIR GATTO commented that at the prices where the 10% floor would have existed, all parties would have been in severe financial stress. However, most people recognize that with oil prices at $96 per barrel today, they will probably never drop that far again. He said he recognizes ExxonMobil's concern that it doesn't want to be penalized with a gross tax when no one is making any money. He said the legislature recognizes that problem and did not include it in the bill. 9:44:30 AM MR. HAYMES continued: The Administration also proposed that all revenues and expenses for the Legacy Fields, which I think they've defined as Prudhoe Bay and Kuparuk, would have to be accounted for separately, with separate taxes paid for each unit and their satellites. This would include Alaska's heavy oil resource, which already has significant economic and technical hurdles. It's interesting that no other fields, units, or regions within the state would be subjected to these higher tax and administrative burdens. 9:46:26 AM I will talk a little bit about the additional reporting requirements for exploration tax credits. The Administration is proposing that in order to qualify for the exploration tax credits, the explorer has to agree in writing to release proprietary information, such as seismic survey and core samples. Providing this type of proprietary information is not the norm throughout North America. Releasing key competitive and highly valued information would be of concern to any explorer. As you know, it often takes decades to progress from exploration to development, and the release of proprietary and competitive information before an asset is producing may not always be appropriate so early in the phase and, so, this could decrease the value of the exploration credit and may discourage an explorer from applying for the credit. In addition, providing this type of information would increase the costs for an explorer. Core samples are costly and in the bill it mentioned providing one-third of the core to the state. Cores can always be made available upon request. A core [sample] can be easily damaged. It's physically damaging to gather it and important to retain it's integrity. So, when you look at it, we feel these requirements go against the basic principle that if a party is willing to take risks to collect information, they should be entitled to maintain confidential and competitive information. 9:47:07 AM CHAIR GATTO asked if it would be fair to say that because the state participates in the investment by giving credits, it should be entitled to the data. MR. HAYMES replied no one would disagree that the state should see the data. He clarified that minimizing the burden on the explorer by keeping costs down and providing certainty that a credit can be applied for and granted is what needs to be considered. The bill, as written, contained specific requirements that a company must meet to be eligible for the credit, which created uncertainty about the availability of the credit. 9:48:18 AM MR. HAYMES continued: I'd like to talk about - in the bill, and I believe it's in the committee substitute, the elimination of the requirement for joint interest billings and, as a starting point in particular, for audits. As a non- operator for Prudhoe Bay, Kuparuk, Duck Island, and Granite Point, we are on the receiving end of a lot of those joint interest billings. We fail to see how not using those is to the State's advantage. I believe "it is to their advantage to use them" is probably a better way to say that. All of the producers' deductible lease expenditures are in accordance with the monthly cost data charged by the field operator to its co-owners. In addition, in a field's operating agreement, the working interest owners have specified what cost an operator can bill to the co-owners. Each year the operator is subjected to very detailed audits by the co-owners and we do that to ensure compliance in accordance with those joint operating agreements. The use of these joint interest billings is the foundation to determine what are allowable business expenses, which provides greater predictability and eliminates the need for the state to reorder new information for the same materials. Using joint interest billings will reduce disputes over appropriate deductions, as well as the state's and the producers' administrative and audit costs. We believe they should be used as a starting point. It doesn't mean that's the ending point. ExxonMobil spends a lot of time auditing those joint interest billings. 9:49:56 AM I'd like to talk a little bit about joint information requests. The Administration is proposing that they require additional information to improve their ability to forecast future revenues under PPT. As I mentioned earlier, we met with the Department of Revenue months ago and are willing to continue those efforts to help them with that focus. We believe that additional information beyond that currently submitted with our tax filings needs to be carefully considered. There must be some limitation and reasonableness on what data is requested. As an example, in addition to monthly cost and production information, the Department would now require a producer or explorer to file each month "other records and information the department considers necessary." We recognize the Department's need for additional data but we believe the current legislation is too open-ended. It should be amended to specify the required information and existing data that is already submitted needs to be strongly considered. There is a lot of information that is shared currently with the Department of Revenue. 9:51:33 AM I would like to shift gears and step back. I'd like to address another important element of the business environment for any investor - 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 typically evaluated over timeframes of decades. A change in the fiscal regime has a direct impact on how we view predictability of the Alaska fiscal environment. This directly impacts how we evaluate on a risk basis future investment decisions. The Administration's 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 could take many years to generate a return and can only reduce the attractiveness of those investments. 9:52:51 AM CHAIR GATTO asked Mr. Haymes if he felt the first change made a couple of years ago to boundaries was significant and on par with PPT. MR. HAYMES said he recognizes the aggregated ELF was a regulatory change, not a statutory change. As a taxpayer, any change, be it statutory, regulatory, or municipal, is a change to the fiscal regime. The aggregated ELF was a tax increase, but not as substantial as the PPT or ACES. CHAIR GATTO said he asked because Mr. Haymes grouped it with three significant changes, rather than calling it one minor, one significant and one proposed change. MR. HAYMES said on an industry level, the change from ELF to the aggregated ELF to PPT to ACES would represent an over 350 percent increase in taxes. He noted each time taxes increase, the attractiveness of any prospective well or project diminishes. For every well or project that does not progress, additional production of state revenues are foregone. 9:54:26 AM MR. HAYMES continued: ExxonMobil expects to be involved in Alaska for many years to come. Policies established today and in the future will impact the attractiveness of potential projects and the future of Alaska. Mr. Chairman, I'd like to wrap up on the next couple of summaries. Alaska needs a long-term resource development policy. 9:54:41 AM As I mentioned earlier, Alaska has significant resource potential but it is a high-cost environment. Oil production is at one-third of its peak, but we've only produced one-quarter of the total oil resource potential. The gas resource potential is equivalent to the oil. It will take significant resources, technology, investment, and teamwork to realize the full potential. In ten years, 75 percent of the future oil production needs over $30 to $40 billion, conservatively, of new investment. Prudhoe Bay and Kuparuk represent currently 70 percent of the North Slope production and they can continue to provide significant levels of production if the right level of investment continues. They can be the backbone for future exploration-development activities, whether it's heavy oil, light oil, or gas. Alaska and the industry collaboratively need to create a resource development policy. We propose a collaborative approach to develop a sustainable long-term resource policy that will encourage the increasing investments that are needed to build the future of Alaska for many generations to come. I've listed here some of the key components we believe are important. · Characterization of statewide resource potential. · Identification of key issues challenging exploration and development. · Key factors that impact resource value, such as research, technology, and exploration development costs, regulatory and environmental considerations, land access. · Establishment of a fiscal policy that will encourage development of remaining resources. · Regular meetings with industry and agency representatives. ExxonMobil looks forward to working with the Administration, legislators, the industry and people of Alaska in the future pursuit and development of its oil and gas resources. Thank you again, Mr. Chairman and committee members, for the opportunity to testify today. 9:57:33 AM CHAIR GATTO opened the meeting to questions from committee members. REPRESENTATIVE ROSES asked Mr. Haymes to address the differences in the bill before the committee and ACES, on the progressivity on the gross as opposed to the net. He noted Mr. Haymes mentioned the $30 to $40 billion that will be necessary to invest for future development production. He asked if ExxonMobil produces in any other country or state that offer as many credits and incentives as Alaska. 9:58:38 AM MR. HAYMES said the gross progressivity is no different from a gross tax. Gross does not take into account the different challenges that face future investment opportunities in Alaska. A low gross tax has worked in other countries; the 10 percent or progressivity factor would dampen attractiveness. ExxonMobil would have to assume the gross would apply when it looked at future investments. He said ExxonMobil considers various factors when making investment decisions, such as the reserves risk, the costs to explore, develop, and produce, including the technology required, the fiscal regime, the operating costs over the life, and the costs of returning the site to an agreed condition. He explained the $30 to $40 billion required averages $3 to $4 billion per year for the next 10 years - that is in addition to operating costs on the Slope. The industry currently spends about $2 to $2.5 billion. That substantial increase will be necessary to achieve the Department of Revenue forecast. 10:01:21 AM REPRESENTATIVE ROSES said he was not asking how or why the investment would be made but whether ExxonMobil is offered the same incentives that Alaska offers anywhere else in the world. MR. HAYMES said many different fiscal policies exist around the world: net, gross, credits. "They can all work," he said. He said it is important that Alaska look at what others are doing but each place is unique. ExxonMobil must look at Alaska in the context of its goal here, whether that be to develop the entire resource and at what pace. If the 53 billion barrels was produced at 1 million barrels per day, it would take 124 years to produce. Producing the gas at 4.5 billion cubic feet per day would take 150 years. He noted the resource potential is massive but ExxonMobil's production is down to 750,000 barrels per day. He stated there is no right or wrong or magic answer. 10:03:27 AM REPRESENTATIVE WILSON commented that, considering the price of oil today, Alaska is not alone in considering restructuring its oil tax to get higher returns. She asked how many countries and states are considering raising their taxes. MR. HAYMES said when the crude price inflates; the 'pie share' is scrutinized. A lot of countries are doing that. He said one must step back and consider whether the price will remain that high. Historically it has not. He said ExxonMobil believes the net-based structure can work and that the tax rate to encourage the full investment of the resource potential is too high today. The goal must be the focus, whether that is to develop the resource potential or the revenue stream. He said those two goals need to be balanced. The biggest challenge facing the industry is that it looks at timelines of decades. Typically governments are in power for less than decades, as are legislators, so it is important to look at a policy that can bridge the investment timeline under consideration. Long term perspectives must be kept in mind by the oil companies. 10:07:39 AM REPRESENTATIVE WILSON noted Mr. Haymes did not answer her question. 10:08:09 AM MR. HAYMES said he is not aware of a total number; he knows Alberta is considering a change to its oil tax structure. He offered to follow up on her question. 10:08:36 AM CHAIR GATTO thanked Mr. Haymes for his presentation. 10:09:19 AM The committee took an at-ease from 10:09 a.m. to 10:21 a.m. 10:22:21 AM MARK HANLEY, Public Affairs Manager, Anadarko Petroleum Corporation, told members his goal is to educate the committee on what drives companies' decision making processes so that it can better develop its policy. He said he believes it is important to review parts of the original bill because people are considering whether to include them. [MR. HANLEY used a slide presentation to accompany his discussion.] MR. HANLEY explained that Anadarko is an independent company that explores for and produces gas around the world. It does not own pipelines, refineries, or gas stations. Its focus is the upstream. He said Anadarko has been in Alaska a number of years. It owns 22 percent of the Alpine field, which Conoco Phillips operates. He noted it owns no interest in the gray areas on the map. The brown and pink areas are areas in which Anadarko has an interest but is not the operator. In general, Conoco Phillips operated acreage runs from Alpine to National Petroleum Reserve-Alaska (NPR-A). Anadarko is a partner in a majority of the wells in NPR-A. The lighter brown areas are acreage that Anadarko has an interest in. Its partners in the Foothills are PetroCanada and BG. Its partners on the North Slope are BG and ASRC (Arctic Slope Regional Corporation). 10:26:26 AM REPRESENTATIVE GUTTENBERG asked that the 68th parallel be identified on the map. MR. HANLEY said it is not indicated on this map; however the Foothills area is shown. He said the point of the maps is to show Anadarko's significant acreage position and prospects in multiple places. 10:27:34 AM MR. HANLEY stated that, as a partnership corporation, Anadarko is associated with ConocoPhillips, PetroCanada, BG, ASRC, and Pioneer and has partnered with BP and Exxon in the past. Partnerships are typical because areas far from infrastructure are high risk with potentially high reward plays, and thus there's the desire to reduce the risk. He pointed out that Anadarko and Conoco Phillips relinquished about 300,000 acres in NPR-A recently so its acreage equals about 4.9 million gross acres and 1.4 million net acres. 10:28:18 AM MR. HANLEY pointed out that Anadarko spent over $100 million on lease bonuses and drilling costs on the acreage that was relinquished. He said it is important to keep in mind the rate of return must cover a company's losses and be commensurate with the rate of risk. Models that only show profit margins on discoveries do not take into consideration that risk. He noted if one always takes it from a success case forward, one will assume the company is making too much money. He said it is important to ask consultants where the risk is included in their models. 10:31:47 AM REPRESENTATIVE FAIRCLOUGH asked if the industry average for producing wells is one in ten. MR. HANLEY said he has seen numbers all over the board and those numbers can depend on whether it is true exploration outside or in-field drilling. He said with new technology, gas and oil will be found more often but whether or not a well is commercial is the question. 10:32:32 AM REPRESENTATIVE FAIRCLOUGH said Mr. Hanley is asking Alaskans to consider what their fair share is as they look at billion dollar profits for some companies. She said she would like to include tangible statistics to provide a rationale in her newsletter if she is to support Mr. Hanley's statement. 10:33:16 AM MR. HANLEY said he believed the Department might have industry numbers; at this point he could only provide a number for Anadarko. He said Anadarko has participated in over 40 exploration wells and has had some discoveries but, to date, none have been commercial. Each individual field has its own economics but averages provide general ball park numbers. 10:34:51 AM REPRESENTATIVE FAIRCLOUGH said she would be satisfied with a number for Anadarko's experience in the North Slope that she can include in a special session newsletter. MR. HANLEY said he would provide those numbers and talk to the Department about an average number. 10:35:27 AM MR. HANLEY continued with his slide presentation. Alaska provides a world class petroleum basin with significant resources. The best place to find oil is where it's already been discovered. Anadarko believes Alaska's resource potential is significant such that there is "legacy-type" prospectivity and a number of fields that can support their own infrastructure, which is Anadarko's focus. Anadarko is looking for the Alpine-size field. 10:37:07 AM REPRESENTATIVE GATTO referred to the previous question on success in drilling and said if one is drilling in Prudhoe Bay, every hole in the ground will produce. He said previous speakers have said that one in eight wells produces but, if that is true, the oil companies would be spending a lot more money in Prudhoe Bay and Kuparuk. He asked if the one in eight estimates pertains to new exploration only. 10:38:08 AM MR. HANLEY thought the in-fill drilling at Prudhoe Bay is not included in those rates; they pertain to exploration drilling. 10:38:25 AM REPRESENTATIVE FAIRCLOUGH stated, for the purpose of clarity, that the speaker was offering a one-sided, corporate-biased argument of numbers in the tax debate that is valid but again asked for more accurate numbers. MR. HANLEY agreed to provide accurate numbers to the committee. 10:39:41 AM MR. HANLEY said Anadarko is bullish on Alaska's resource potential. New players have entered the field in the last four or five years and six new exploration rigs have been brought to the North Slope this winter. The arrival of new companies in the picture is a healthy situation as they provide new ideas. He elaborated on how discoveries by various entities prove helpful to all, and spread the risk and support the successes. 10:42:21 AM MR. HANLEY moved to page 4 and explained the challenges of operating in Alaska. Alaska's basin is maturing, which means it is a smaller prospect. He said it is valuable to evaluate Alaska's system to other places but: ...if you have a gutter that has 800 trillion cubic feet [TCF] of discovered gas sitting close to tidewater with costs that you don't need at 800 or a 2500 hundred mile pipeline to get it to market and their costs are somewhat less, they can get a higher rate. If they had 800 TCF sitting on the North Slope right now I think you could be getting a higher government take so it's important not just to look at the average government take everywhere but look at the prospectivity. 10:43:41 AM MR. HANLEY continued: ...as you can see here, this is an Econ One presentation during PPT from one of the legislative consultants that was out there. ...One of the things I wanted to point out because I think it's valuable when we talk about this - what is the prospectivity of Alaska - here is - these numbers come from USGS but if you look at the top it says undiscovered technically recoverable oil reserves. It is not gas, it's technically recoverable. In other words, you may have a field, oil in place of a billion barrels but you can't get 100 percent of it out so this is the - technically - they may have a 50 percent - I don't know what their numbers use but it's what they think is technically recoverable. It doesn't mean it's economically recoverable. That's why it says the footnote at the bottom. This is their slide but what's interesting is we're just looking at the central North Slope - that's not [Arctic National Wildlife Refuge] ANWR, that's not offshore and you can see that they think there's 4 billion barrels of technically recoverable remaining reserves so I think that's a significant amount that's sitting out there. That's not in-field, that's not the heavy oil. It's already kind of sitting there. This is kind of the exploration oil that's out there. But look at the amount in fields that's over one billion barrels - zero. Look at the amount of fields over 500 million barrels - 2 percent. That's the anchor fields that I guess you'd say we were looking at - the 4 to 500 million barrel fields. Look at the amount in fields smaller than 64 million barrels - 51 percent. So, I think this helps put a little bit into perspective why we think there's significant remaining resource. They tend to be in smaller fields. They tend to be in what we would consider the 64 million barrel satellite opportunities. The 64 million barrel field will not justify its own stand alone facilities typically. So, if you're not within about - give or take - 8 or 10 miles of an existing infrastructure, you could have a 60 million barrel field that's just not economic. That's why I say it's important to put numbers into perspective. While we do like the prospectivity, we do think there's some of these amounts over 200 million barrels - it isn't the billion barrel fields that are sitting out there. This is just a size distribution of the fields. But here's one of the other things that I like to use this slide to point out, is the economic impact of either price or, if you want to look at it in a different way you can say taxes. We think taxes - I think you've heard a lot of time that prospectivity, risk, but price factors, volume factors and tax factors all have an impact on economic decisions for companies and how they make their investment decisions. If you look here you can see that in rough numbers this is the same North Slope - central North Slope reserves that were 4 billion total potential, you can see a different oil price is what they say is economically recoverable. This is a model. This is why it's hard for a lot of us to come up here and tell you exactly what's going to impact specific issues. We have to look at our own fields. But this gives you an idea that there is some relationship between price and the number of economically recoverable reserves. I just want to leave people with the fact that if you get another billion dollars of taxes, it's not a lot different from our perspective as if we got a billion dollars less on those barrels of revenue. And you can see that if you took $3 a barrel, which is roughly $800 million dollars of new taxes on the existing production level we have, that you might have a couple million barrels in the central North Slope that is not economic now. Do they point out exactly where it is? No, this is more theoretical or estimated models but I do think it's important to point out that there is, to the extent that you have a dollar impact from your taxes, it does impact the amount of economically recoverable reserves. I can provide a copy of the whole report. I have in the past. This is a legislative consultant report so you can see the whole thing. So again, when we got to the point of - we do see a lot of resource potential but it tends to be in smaller fields. We're looking for those smaller numbers of anchor-type facilities but the challenges that Alaska faces are the high costs, the extremely long lead time exploration, which is partly driven by the seasonal drilling. Part of it is the cards you're dealt. We're out there not drilling in the summer time and when there's sensitive activities out there. For us, being able to drill for four months of the year compared to other places, it does take longer to explore for and develop oil and gas in Alaska than almost anywhere else in the world where we operate. 10:48:40 AM MR. HANLEY continued with page 4 of the committee hand out entitled: "Seasonal drilling and regulatory timing requirements". He told committee members: You can imagine, if we have the same prospectivity, the net present value, which you've heard, if we have our money tied up for an extra four years here versus somewhere else and they're the same kinds of investment decisions, it's a challenge. That's why, to be honest with you, the PPT system - and I'll go into this a little more, but the net profits approach system is so valuable in our opinion. One of the big challenges of Alaska is the timeframe to get things into market. The amount of time your capital is tied up is longer here. What it's amounted to is through those incentives, through those credits, effectively it's reduced our costs. Now we pay more in the back end. The tax rate is higher than it would be under a gross system, for example, but effectively we have less money up front, which means that really does help our net present value analysis so that's why the system - and I think you've heard the Administration talk about if you had a gross that raises the same amount of money - how does it affect investment decisions. Those charts were very valuable and we agree with those because you can raise the same amount of money but you actually improve through a system like PPT your chances of companies actually investing up here because it improves our net present value while you get the same amount of money. That, to us, is one of the real benefits of the system that has been developed and we would encourage that it stay with the net profits approach, and I'll go a little bit more into that. 10:50:52 AM MR. HANLEY called attention to page 5, entitled, "Our View of PPT Recap of 2006 Testimony," and said it was a significant tax increase on existing fields. Anadarko was paying on net but it wasn't able to utilize the credits and deductions that were generated from building that facility. Anadarko felt its exploration economics improved slightly under the new program but that applied to a new field it has not started drilling in yet because it will get the credits and deductions. 10:52:12 AM MR. HANLEY stated that Anadarko supports a net profits approach. Anadarko staff met with the Administration in May and June and provided its ideas on net versus gross. It had no specific proposals but had valuable discussions about why keeping the net profits approach is beneficial for the industry and state. Anadarko appreciates the fact that the state retained the net profits approach. He explained that Page 6 contains four bullet points, 3 on why this is a good approach. With a gross tax, one could still pay taxes if costs exceed income. 10:53:16 AM MR. HANLEY presented a gross versus net tax example on page 7 and explained how it works per barrel price. If, at Field A, the cost per barrel is $10 and net income is $50 per barrel, and at Field B the cost to produce is $20 and net income is $40 per barrel, a 15 percent gross tax will be $9 on each field. However, the tax rate on the net income will be 18 percent on Field A and 22.5 percent on Field B. If a 20 percent net tax was in place, Field A would pay $10 in taxes while Field B would pay $8. This illustrates that the net system takes into account costs. A gross system does not maximize state revenues because some fields will be under taxed while others will be overtaxed. There is a tipping point; taxing a very economic field, on a gross basis, will cause other less economic fields to be overtaxed. 10:56:07 AM REPRESENTATIVE GUTTENBERG said this scenario has been presented by all of the companies, but the state must come up with a model to fit all of the companies' business plans. He said, regardless of what the state does, it will not be completely fair. He asked Mr. Hanley how he proposes the state strike a balance between the large and small companies. 10:57:02 AM MR. HANLEY said providing a net system should provide the best opportunity to create a balance and provide maximum revenue. He agreed that no system is perfect. He elaborated that the state system, with the PPT, will also have a gross system when the royalties and property taxes are accounted for. The net system does the best job of balancing the higher costs of new fields with the lower costs of older fields and incorporates the variable costs involved in exploration and development. 10:58:41 AM REPRESENTATIVE GUTTENBERG said if the state takes operating costs off of the table that will compensate everyone across the board. MR. HANLEY admitted that does sound plausible. Costs are a factor and the net system accounts for that, which is a positive. 10:59:30 AM REPRESENTATIVE GUTTENBERG asked how Anadarko's costs compare with other members of the industry. MR. HANLEY said industry groups publish standard models of costs around the world so rough comparisons could be made. 11:00:42 AM MR. HANLEY continued with page 8, which pertained to the ACES model. The original ACES proposal would impose a significant tax rate increase; the tax rate increase from 22.5 to 25 percent would have the biggest impact. The progressivity change, which Anadarko feels in an increase and elimination of the transition investment credits, would also significantly impact Anadarko because of the investments it has made. Anadarko and Conoco Phillips invested hundreds of millions of dollars for a satellite operation a year before the PPT took effect. Anadarko made its decision based on the aggregation decision made by the governor earlier. Because of the tax change, Anadarko could not get any tax credits for that project, which was a big hit. 11:03:39 AM MR. HANLEY continued with page 8, and said the second bullet point about stability comes into play because of the negotiations that will be forthcoming on the gas issue. He said in his view, everyone will be back within two years to discuss gas taxes. Assuming one passes, an open season will have to occur within the next three years. Everyone has acknowledged that the state has to know what the tax rate is on gas before the open season occurs. He said many consultants have testified that gas is less valuable than oil so should have a different tax structure. He said he can argue to management that stability will be provided, however if a gas tax is opened up two years from now, it is intertwined with oil so that discussion could be reopened. He pointed out Anadarko will have to take that issue into account when making investment decisions in the next two years. 11:05:53 AM REPRESENTATIVE FAIRCLOUGH agreed that oil and gas taxes will be intertwined in the future but separating that issue out in the next two weeks of this special session so that an oil tax structure will not have to be exposed to changes may not prove possible. She said the credits seem to be causing the most discussion. She has talked to the Administration and committee members about creating oil production stability but repeated that two weeks is probably not enough time in which to separate the two but the concern has been recognized. 11:07:28 AM REPRESENTATIVE WILSON asked if oil and gas taxes are treated the same anywhere in the world. MR. HANLEY said he suspects so and offered to investigate the answer. 11:08:20 AM MR. HANLEY emphasized that stability will be considered but it is not the primary driver. He pointed out it is unfair to require new legislators in two years to live by what was done by this legislature, especially since a lot of new information will be available. 11:09:04 AM MR. HANLEY described the chart on page 9, "Administration Field Economics Estimates." He explained that on the four fields modeled by the Administration, the economics significantly decrease. The Administration could argue that the value is still high enough to make the fields economic, but a $700 million increase in revenue, based on a $2.50 increase in the price per barrel on today's production, is not insignificant. A decrease of the net present cash flow of a field by 54 percent is significant. He told members it is important that the models incorporate geologic and commercial risks, particularly when looking at exploration economics. 11:10:53 AM MR. HANLEY finished with page 10, and summarized three comments on the Oil and Gas Committee version of CSHB 2001. Anadarko would prefer to have a progressive tax applied to net income - it supports the trigger as it was in the ACES plan. He explained: We can debate the dollar - the rate, but as a policy we think applying a tax actually, whatever it is, to the net makes more sense because it does take into account costs. So, as I showed you on that one slide, obviously if your goal is to get a certain amount of revenue, then under this proposal I guess I would argue you should apply it to the net, whatever the tax rate is, and, of course, if you're trying to get the same amount I will acknowledge that that .225 escalator will have to be higher because it's on the net. As I showed in that one slide, you're going to have a higher rate and apply it to the net - at least it will take into account the costs. The higher cost fields will have those considered. So, that's one of the things I suggest you would at least take a look at - is if you want to have that $50 trigger on the wellhead price, at least figure out the progressivity and apply it to the net income. 11:12:30 AM REPRESENTATIVE SEATON said Mr. Hanley's analysis is in direct opposition to previous testimony, which preferred a trigger point driven by the net. In previous testimony, the speakers said they wanted to make sure the trigger point was triggered by the net so that it included the profitability margin. He asked: I'm hearing you say that you don't care - well, you probably care but you care more about applying it to this increase - this progressivity tax considered a separate tax - applying it to the costs of the state, picks up additional portions of the cost that those high prices, instead of making sure that you've got a profitable margin on the field before progressivity, kicks in. Is that where you're meaning to come in the testimony here? MR. HANLEY said the answer is yes, however either approach is workable. He said something must be changed so that at least one of the factors goes back to the net. Anadarko Petroleum Corporation would prefer to go with the original ACES plan, he related. If that is not possible, then either apply the tax to the net, which would help account for costs or use the net as the progressivity feature. Either one would help more than the existing bill. 11:14:30 AM REPRESENTATIVE SEATON followed up by stating that the risk to the state has not been established. If the state applies the progressivity times the net, it will be sharing in the additional costs even at high prices. His concern is that when the upper regions of progressivity are reached, it will be at 25 percent in all of the bills. He explained: In all of the bills there's a 25 percent maximum cap so that we would actually be participating in the costs with additional 25 percent of the costs we would be absorbing at those high prices, so that would be 25 percent gain through the progressivity net in addition to the 22.5 or 25 percent portion of the cost the state is going to pick up. And then you add on the credits and those things in addition and it seems that my concern is that the state starts taking a large net present value risk for an expensive project - several billion dollars. All of a sudden we'd be not only putting in 40 to 45 percent of the costs but all of a sudden we're putting in 75 percent of the costs. It seems that might change behavior, as well as adding risk to the state. Do you understand that the same way? MR. HANLEY said he is not sure he understands Representative Seaton's concern. He pointed out this is not a base rate change, so that does not affect Anadarko's increase in the net income but the tax rate increase has always more than offset any value it gets out of the credit or deductibility. Anadarko has not seen a scenario in any of the proposals that provides an incentive to invest a dollar because it receives more than that in credits elsewhere. 11:16:59 AM REPRESENTATIVE FAIRCLOUGH asked if Anadarko Petroleum Corporation is advocating ACES versus the former PPT on the 20 percent progressivity rate instead of 25 percent with the lower start price of $30 per barrel in ACES. MR. HANLEY said Anadarko's number one preference is to maintain the PPT. He furthered: The approach versus the dollars - we still support the PPT and the ACES approach, which is calculated on the net and applied to the net. So that approach, in both PPT and ACES, is our preference. If you ask us specifically, when we get into the policy call on the dollars, our preference is to stay with the existing PPT. It starts higher. It escalates faster. What you find is just the numbers actually cross at about $80 a barrel net. At that point, we haven't gotten into the annualized versus monthly, but just with the progressivity itself, ACES versus PPT - they basically cross at 80 so the state is actually taking more at the lower end and less at the higher end. Our preference would be to stick with the PPT and ACES approach, figure it on the net, apply it to the net, and our preference would be to stick with the PPT policy, which started at 40, progressive .225. 11:19:10 AM REPRESENTATIVE FAIRCLOUGH noted the approaches have different curves and thanked him for the clarification. 11:19:24 AM REPRESENTATIVE ROSES said two consultants told House Oil and Gas Committee members the same thing - the state needs to try to capture more when profits and prices are much higher and capture less when they are lower to encourage investment. He understands that is the reason why the committee dropped the 10 percent floor. It was also the reason the committee moved the trigger point from $30 and $40 to $50 and for going to a gross progressivity as opposed to a net progressivity to capture the dollars on the higher end. He then said he now hears the different producers say they want net here and there but, when it comes to credits, they want gross. He said he is struggling with the consultants' testimony with how the companies keep picking this and that. He asked Mr. Hanley to talk about the committee's flawed thinking in dropping the floor to 10 percent to encourage investment. MR. HANLEY said he did not see inputs into the model but the 50 is now a wellhead price, not a net price. If one compares that, it didn't actually increase from the $40 in the existing PPT. If costs are over $10 per barrel, it would actually start lower. He furthered: When you talk about the consultants, if that was their view that you should leave some on the table, to the extent that the costs considered in that calculation were $15 or $20 per barrel, I've heard those numbers. I don't know what they were then. The 50 equated to a net is more like - if it were 15 that would be a 35 so it's actually - you know, you are taking more in your view starting at a lower price, which is what - at least your comments were the consultant said not to do. How that compares, you can get the guys to tell you what the numbers are. And then I would just argue that applying it to the gross is differentially affecting companies with higher costs to lower costs. You are leaving something on the table. If the escalator is the correct number, then some fields are paying less than they should be paying and other companies are paying more because they have higher cost fields. So those are the two criticisms I have of the Oil and Gas [Committee] version. REPRESENTATIVE ROSES said committee members have heard each producer say that does include a scenario in which they could pay taxes when they don't have a profit. He asked if the progressivity trigger, which was changed from $30 in the ACES bill to $50 in the House Oil and Gas Committee bill, will have to increase costs by $20 per barrel above the existing costs before that scenario would happen. 11:23:36 AM MR. HANLEY said he would have to do the calculations on paper to determine whether costs would have to increase $20 per barrel. REPRESENTATIVE ROSES surmised that Anadarko's concern is that as prices continue to rise, it will be taxed through progressivity when there is no profit. Therefore, the higher the taxes, the higher the deductions at the base level. For instance, at the 22.5 base rate, and allowing companies to deduct operating and capital expenses and credits, the taxes will be reduced because of the higher costs. He said he does not see it as a flat line. It will be a long way before the point to where gross progressivity will tax when there is no profit. He added he would like to see someone run the numbers because he thinks the curve is a lot more significant than people think. MR. HANLEY offered to do the number crunching to answer the Representative's question but thought unique circumstances would have to occur for that to happen. He said if an oil company gets a lease today, it will need to do seismic and development work, which can easily take ten years, while not knowing the price of oil in ten years. 11:27:15 AM REPRESENTATIVE ROSES offered that if oil were $30 per barrel, the committee would not be meeting today, despite the other, various reasons that have been offered for this special session. He noted: The fact is we're here because the prices are high and I can guarantee if the prices fall back to $30 a barrel, we'll be back discussing it because we don't want the oil companies to leave. So, what triggers us to be here for the high price would also trigger us to be back if the prices tank. So, I'm not as concerned about predicting what the prices are going to be in 10 years because we'll probably discuss this two or three more times between now and then. MR. HANLEY said the progressivity feature does create some stability in the system because it takes into account things that cannot be predicted. He thought that because it is increasing and the state is getting more revenue at higher oil prices, everyone is less likely to be back because people will feel like they are getting their fair share. 11:29:37 AM CHAIR GATTO felt progressivity could be the single most important aspect of the bill. He said no one involved in oil production and profits is saying they need a break. Some individuals have suggested that at $120, the state should get it all. He said everyone must find a compromise so that all are content with the product. 11:30:38 AM REPRESENTATIVE SEATON asked if Anadarko feels the 22.5 or 25 percent deductibility plus the 20 percent investment credit provides enough of an incentive to make a field go or whether it feels the state should take a greater share of those costs. MR. HANLEY referred to 2006 testimony about the PPT that looked at internal rates of return for satellite versus an anchor field project. He compared the 20:20 to the 20:25 and ELF system. Anadarko's view was that the 20:20 was the most encouraging and that the 25:20 was worse for exploration and the existing ELF system. He said ELF was a regressive system so that it took a significant amount of money when prices were low. He added: What happened was we gave up some of the upside. The PPT as it exists with the tax rate, as well as with the progressivity, particularly crossed that line for the ELF - compared to ELF. The companies got the high end on the ELF and gave up something on the low end - we would argue overtaxed when prices were real low. All the PPT did was shift that line so the state got more of the upside but did take some of the downside risk and I think that's what people said. If you take away the downside and take away the upside it's not a good system. We argued that we had some downside risk protection under the new system. We gave up some of the upside but the prices were higher. That kind of helped offset that so that overall it was a balance. So, when you ask me, as we started getting up into those 25 percent tax rates, overall our view was not as favorable to exploration as even the old ELF system. 11:34:02 AM REPRESENTATIVE SEATON said all comparisons to ELF need to be off the table at this time because the reason for that discussion was that Kuparuk, the second largest field in the United States, was going to be paying no tax. That system had been broken and outdated for some time. He said he is wondering what amount of state incentive is reasonable for development activities Slope- wide. He also asked whether the extra 10 or 30 percent EIC provides adequate incentive when Anadarko is making decisions. MR. HANLEY said the current system works for Anadarko Petroleum Corporation, which is focused on exploration. He cannot speak to heavy oil or infield drilling. He emphasized it is not adequate for gas. REPRESENTATIVE SEATON asked if Anadarko is supportive of the EIC as it came in the original ACES bill. MR. HANLEY said he could spend a couple of hours on that question. He stated there are many small things in the bill that don't rise to the level of the big policy calls for either side, but they do have an impact. He said overall the benefit in the bill was extending the time frame under which one could drill and get the EIC credits. Now a company can probably drill a second season and get those credits, which is a positive thing. However, all of the other things in ACES that relate to that are negatives. As an example, he pointed out that suspended wells were excluded from EIC credits. He was not sure what the rationale was behind that exclusion. He explained some of the difficulties of getting EIC credits for an existing well because of the wide discretion the state would have in determining "existing." He said Anadarko does not mind providing more information, but the qualifier for receiving that credit is unclear. He offered other examples of points in ACES that are confusing or do not indicate good rationale. He said the flat out prohibition on requesting extended confidentiality is problematic because sometimes unexplored acreage exists near leased acreage. Anadarko might want to lease the unleased area but would want to keep drilling information confidential, otherwise the state could say it wants to lease the acreage for more. He said the system works as is so he is not sure what problem will be solved. 11:45:56 AM REPRESENTATIVE SEATON said the legislature is trying to fully consider all of those issues so he hopes whatever passes is in place for quite awhile. He said when PPT was being established, he recalled, the legislature was looking for an expedited way for explorers to turn transferable credits in through the Alaska Retirement Board with 92 percent on the table. Anadarko Petroleum Corporation supported that concept at the time. He asked whether Anadarko still supports an expedited way to get the credits back by including that provision. 11:47:53 AM MR. HANLEY said the short answer is yes but it is not a particular issue for Anadarko because it has production at Alpine against which it can take most of its existing credits. He said it is more of a level playing field issue for some of Anadarko's partners. He pointed out the House Oil and Gas Committee version of the bill did not address the net operating loss and he believes the two should be matched. 11:49:57 AM CHAIR GATTO said the ACES bill is one of broad public policy that is being addressed in a 30 day session, which will be followed by a 90 day session. He said no doubt some details will need to be discussed later because of unintended consequences. The legislature is interested in fairness between the producers and the state and among the producers. The legislature views this endeavor as a partnership and expects the producers to come back during the 90 day session if it encounters an unforeseen problem. 11:51:32 AM REPRESENTATIVE HANLEY said he believes most producers will be reluctant to come back to ask for small changes because they fear the risk of reopening the issue. CHAIR GATTO said he was making no promises but the legislature might be willing to address certain problems. MR. HANLEY thanked Chair Gatto for discussing that possibility. 11:54:15 AM REPRESENTATIVE ROSES summarized various comments that he has heard in the hallways about why the House Oil and Gas Committee version will not work and he would appreciate having people come forward to discuss that because the committee cannot continue to debate the theoretical. 11:56:01 AM REPRESENTATIVE SEATON referred to the [AS 43.55].165(e) portions of the nondeductible lease expenditures. He asked the other companies if, in the modification of Section 6 in the L version of the Oil and Gas committee substitute, they would support adding "violation of law" and clarifying that would include criminal negligence, and removing Section 19, which pertains to unscheduled maintenance. He asked if Anadarko would support those changes. MR. HANLEY deferred to other company officials to respond to his question and said a response will be provided to the committee. REPRESENTATIVE SEATON offered to get Mr. Hanley a copy of an amendment he had drafted to that effect. 11:58:20 AM CHAIR GATTO referred to the 30 cent per barrel deduction, and asked if that is an appropriate device to take care of unscheduled maintenance. MR. HANLEY said it is essentially a gross tax that affects all companies, whether they are doing adequate maintenance or not. 12:00:17 PM REPRESENTATIVE SEATON clarified that various factors came into play when the 30 cents per barrel rate was determined. That rate was designed to cover more than poor maintenance. 12:01:24 PM CHAIR GATTO offered that the 30 cents could be spent on maintenance or paid to the state in order to provide the motivation for proper maintenance. 12:01:58 PM CHAIR GATTO announced that the committee would recess until 1:00 p.m. 1:08:00 PM CHAIR GATTO reconvened the hearing and introduced Marilyn Crockett and Tom Williams, Alaska Oil and Gas Association. 1:08:46 PM MARILYN CROCKETT, Executive Director, Alaska Oil and Gas Association (AOGA), informed members that AOGA had distributed a handout to accompany her presentation. She informed members that AOGA is a private, non-profit trade association. The members of AOGA represent the producers, explorers who hope to be producing soon; companies that are just starting to test the waters in Alaska - Agrium, Alyeska Pipeline, and the three in- state refiners. 1:09:17 PM MS. CROCKETT pointed out that when AOGA takes a position on an issue, it requires a 5/6 vote of committee members so that legislators and regulators know that AOGA's positions represent a broad majority of its membership. The association has gone one step further on tax issues. Its tax committee requires a 100 percent vote or no dissent on issues. She specified that her testimony today represents the views of AOGA's tax committee. She told members Mr. Williams has an extensive background in oil and gas tax issues, and tax issues in general in the State of Alaska. He is an attorney for BP and was the director of the tax division of the Department of Revenue from 1975-1979 and then became commissioner of that department. She continued: In these roles, he was the architect or co-architect, if you will, of many aspects of Alaska's oil and gas revenues that are still in place today, from the methodologies of determining gross versus net - gross value, excuse me, at the point of production to the methodology of determining shareable net profits under the state net profit leases system. Tom wrote the regulations that successfully implemented the former separate accounting tax, as well as the statutory language in the state's present income tax enacted on the oil companies in 1981 to replace separate accounting. He supervised the first property tax devaluation of [Trans-Alaska Pipeline System] TAPS when it came into production and he also administered the state's temporary two years' reserves tax in 1976 and 1977, some 30 years ago. He was also on the original board of trustees for the Permanent Fund and, most notoriously, Tom became the father of ELF in December of 1976. He served as vice president and general counsel for Cook Inlet Region, or CIRI, for almost four years before joining BP in 1987. He is, if you will, my tax expert. If I get questions that I am unable to answer, and I'm certain there will be a couple of them, I will defer to Mr. Williams to answer those questions. 1:12:17 PM MS. CROCKETT told members the focus of her testimony will be on the practical impact of the declining production levels on the industry and state and on some of AOGA's concerns with the legislation before the committee. She continued: Last year, when the legislature passed the PPT - we're here now a year later with the Administration telling you that it's broken. They say it's too complicated to forecast, that it isn't bringing in the revenue that was forecasted last year and they don't have enough capable auditors to enforce it. In discussing the merits of the proposal before you today versus PPT and the Administration's concerns, we must always keep our mind on the real world situation that Alaska faces and that's the situation of declining production. Production decline is a cornerstone of the state's economy and - production is the cornerstone - excuse me - and the decline is eroding that cornerstone. Even with the massive investments that have been made on the North Slope, production continues to decline at an average rate of 6 percent - in Cook Inlet at an average rate of 8 percent. Without those investments on the North Slope, that decline rate would be on the order of 15 percent so it is a significant contribution. With respect to the future of the North Slope, there is going to be a major challenge for North Slope production for Alyeska pipeline and TAPS when it gets down to about 300,000 barrels a day. That's the minimum technical capacity that the new electronic pumps that are being installed is capable of handling. 1:13:45 PM CHAIR GATTO asked what action will happen when production gets down to 300,000 barrels a day. 1:13:59 PM MS. CROCKETT explained that oil production is approaching 300,000 at a slow rate; Alyeska will continue to develop technologies and prepare for that declining flow rate. It's a very, very challenging problem; a number of options can be pursued but the difference could be getting oil down the line to Valdez in days - at peak production to weeks. 1:14:55 PM CHAIR GATTO asked if the issue is cavitation of the pump under low flows. He questioned why a pump that can move 750,000 barrels would have trouble moving 300,000 barrels. 1:15:11 PM MS. CROCKETT said she could not answer that question but added the terrain is not flat and that makes a difference. 1:15:49 PM TOM WILLIAMS, Alaska Oil and Gas Association, said "throwing a switch and turning the pipeline off" at 300,000 barrels is an extremely unlikely possibility. That amount is the threshold on which the new pumps will operate. He does not know that the engineers have come up with solutions for an amount lower than that. He said AOGA is looking at, with TAPS, cost structure to move oil to market. That may change when a point at which something different must be done. That could mean transporting oil in batches or heating oil but it will probably be more costly. 1:17:37 PM CHAIR GATTO said the legislature has projections that show no change at 300,000 barrels. 1:18:03 PM MS. CROCKETT said the 300,000 barrel threshold is focused on the mechanical ability available today. She continued: Again, recognizing that additional work will continue, especially if the decline continues at the rate that we're seeing to ensure that the pipeline is operational - but it's a data point that's out there as a point of reference for us. 1:18:30 PM REPRESENTATIVE FAIRCLOUGH said members were told in other testimony that 400-450,000 barrels are necessary to make it economical, so that economics, as well as mechanics, are involved in that decision. 1:19:09 PM MS. CROCKETT referred to a chart on page 3 of her testimony and said it describes the impact of different decline rates on production with production [levels] starting today. She said at the historical rate of 6 percent, it will take 15 years to get to the 300,000 barrel a day mark. If the decline rate drops to 3 percent, the time frame will be pushed out to 30 years, so the rate of decline makes a dramatic difference. She stressed her chart is not a prediction; it demonstrates the impact of getting to the 300,000 barrel a day level from the level today. 1:20:17 PM MR. WILLIAMS pointed to a footnote about the mathematical calculations in the graph. 1:21:02 PM MS. CROCKETT said the chart demonstrates the importance of investment necessary to extend the decline. She continued: And, of course, as you've heard over the last few days, there's three categories of investment that will make a difference in keeping that pipeline full - one is on exploration activities, of course, one is on investment and development in heavy oil and bringing new fields on-line and, of course, the third is investments in the existing fields and the infrastructure to keep those production rates from declining further. Now you've heard a great deal of testimony in your committee and in other committees focusing on the level of government take for exploring in Alaska and the competitiveness of these terms relative to the regimes elsewhere in the world. This kind of who takes more analysis is faulty for a couple of fundamental reasons. First, it assumes that the geologic prospects for a commercial discovery in Alaska are comparable to other regimes and, unfortunately, that simply isn't true. The North Slope has three major areas of significant oil and gas potential. The first is the existing area where activities are occurring now, between the Colville and Canning Rivers. We also have [National Petroleum Reserve-Alaska] NPR-A, of course, where companies are exploring with, unfortunately, some limited success. I'm sure that all of you have seen that there's been about 300,000 acres of leases turned back recently due to poor exploration results in NPR-A but companies are still exploring there so that's the other option. And then, of course, we have ANWR but, as all of you are painfully aware, the coastal plain of ANWR still is not open to oil and gas exploration. 1:22:40 PM On the exploration front, that's certainly one of the tools in the toolbox and it's an important one, it is the activity that will bring the state production in the future. Even when a commercial discovery is made, it takes years to bring us production on line and the challenge for us today is immediate, not 8 and 10 years out. It's an important tool in the toolbox, if you will, but it's not an immediate fix for us. Investment in heavy and viscous oil development is also a solution. It's a mid to long-term solution. Spending is underway, as you know, on evaluating some drilling that's been done on the North Slope in the Ugnu formation to continue to develop the technology to get that heavy oil produced but, until then, we have the production from West Sak to carry us for the immediate short term. 1:23:37 PM So this gets us to investment in existing fields. As you've heard, the drilling that took place in 2006 resulted in an additional 70,000 barrels a day of production from the Prudhoe field. If that was a stand alone field, it would be the fourth largest field on the North Slope. 70,000 barrels a day of new production from infield drilling is a very significant contribution to the production levels that we have today and largely result in the smaller decline rate from 15 to 6 percent that I mentioned a moment ago. 1:24:15 PM There are also major investments being made and yet to be made in the renewal of surface facilities for the existing fields. For example, the gathering centers and flow stations for the Prudhoe Bay area have been in service now for over 30 years. Prudhoe Bay and other producing fields are to continue to produce for the decades to come. Their original facilities will need to be overhauled or replaced. Also, as an increasing amount of heavy and viscous oil come into production, these facilities will need to be modified, retrofitted, and replaced in order to minimize the operating problems in handling this viscous oil. Regardless of the stimulus or purpose for making them, renewal investments and production infrastructure present a very similar cash flow pattern, as there is for investments in the original infrastructure. Consequently, an incentive that is effective for the initial development is equally effective for renewal as well. So, again, the harsh reality all of us face, and I know that you are very much aware of this, is the decline of production. It's a big challenge for us. We are now in the process of grappling with it and it's going to require massive new investments. 1:25:25 PM MS. CROCKETT continued: Turning now to the relative merits of the bill that's before you today versus PPT, AOGA submits that 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 that it was intended to do and it should do them well. Second, the Administration, in enforcement of a tax, must be as efficient as possible, consistent with ensuring compliance by taxpayers. Third, a taxpayer who wants to calculate and pay the correct amount of tax when it comes due - it has to be possible for them to do that. Regarding the first test, achieving what the tax is supposed to achieve, most new taxes have as their primary or only purpose new revenues. In the case of PPT however, things were not so simple. But as Pedro van Meurs explained repeatedly in his testimony last year and again at the beginning of the special session, 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 more state revenues than the ELF system would have. 1:26:29 PM CHAIR GATTO said he has heard differently, that there are certain dollar levels at which ELF brought in more revenue than the PPT. MS. CROCKETT said she had not heard that but clarified the total she is speaking to is in the aggregate. If one compares the production tax income to the State of Alaska pre-ELF and post- ELF, PPT has brought in increased revenue to the state. MR. WILLIAMS added: That statement is based in the context of the prices that we've actually had and those are above the range where you're talking about. It is possible, because it's a net tax, for the net amount to get to zero before the gross amount would get to zero and PPT is net, the ELF was gross. So, there are certain numbers where we make nothing under the net and the gross never goes away. 1:27:21 PM CHAIR GATTO asked if there is a cross-point. MR. WILLIAMS said there is and noted it is also possible, when oil prices are extremely low, to get to zero with a gross tax. He explained that is where the West Coast market value is down to the cost of transporting it there from the North Slope. He noted on December 23, 1998, the transportation cost was half of the market value on the West Coast. 1:28:05 PM CHAIR GATTO said it must be handy to own a refinery, trucks, and other parts, rather than just the raw resource. 1:28:16 PM MR. WILLIAMS said it is handy and is the reason the state income tax doesn't look just at the upstream income of a company, but also considers the vertically integrated components downstream. 1:28:33 PM MS. CROCKETT continued: According to the Department of Revenue, the increase was more than $800 million in the first nine months of 2006 and, at that rate, it would have been over a billion dollars in additional tax revenue for the full year. DOR also said at the time that the March 31 payments were about $137 million less than the $950 million it had estimated. I'll come back to the questions of forecasting in just a moment. For now, my point is that PPT has certainly outperformed the ELF tax, which is exactly what it was intended to do. As a consequence of the fact that field costs are higher than DOR predicted last year, the Administration criticizes PPT for failing to generate all of the tax revenues that the fiscal note for HB 3001 predicted. It's even been suggested that Alaskans were somehow promised that PPT would generate $800 million more this year than was projected and it is necessary, therefore, to raise the rate in order to make good on that promise. 1:29:31 PM This whole line of reasoning is flawed. First, DOR is complaining that they can't forecast PPT accurately because it has so many variables that effect the results. But if they can't forecast it accurately, then why should 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 one so good. 1:30:20 PM As I explained a moment ago, the purpose of the PPT was more than just to attract the tax revenues that it would generate. It was to create incentives for attracting massive new investments that will be needed in order to meet the threat of declining production. The system of tax credits that PPT provides significant incentives for investing in capital assets to explore for, develop and produce oil and gas in Alaska - for example: · there's a 20 percent tax credit on current capital expenditures · the transitional investment credit for expenditures undertaken prior to implementation of PPT, which have to be matched on a 2:1 basis for those prior capital expenditures · the tax credit for the carry-forward annual loss particularly benefits explorers who don't yet have production · the $12 million credit for small producers also is an incentive for those producers to continue to explore · and then finally the annual credit as an incentive for exploration and development So, had these incentives under PPT worked - the preliminary results so far show that they have - DOR's August 3rd report on PPT states that capital investments for FY 08 were 80 percent greater than previously estimated, despite the fact that operating costs were 101 percent over the prior projections. 1:31:22 PM REPRESENTATIVE ROSES said when almost every producer was asked whether the PPT drove their investments during the last year, they all said no because their planning started up to ten years ago. He said the producers were then asked how legislators would know in the future whether the current incentives have worked. The producers answered they hoped the state would be able to tell because they would be producing more oil and drilling more wells but they are planning ten years out at this time. They said the incentives may cause them to speed things up and bring on technologies that were not cost effective in the past. 1:32:29 PM MS. CROCKETT agreed Representative Roses is correct about investment decisions being made out into the future, but noted decisions to stop investing can be made very quickly, which is the other side of the equation. Clearly no decisions were made to stop spending under the increase in PPT last year. 1:32:51 PM REPRESENTATIVE ROSES said the largest investor in many of the exploration wells is the state. The producers can take credits against production they have in other locations, which takes away potential revenue from the state. When the state does get a return on its investment, it comes at a much lower rate and slower pace. 1:33:48 PM MR. WILLIAMS said he does not disagree but added the result will be production in the future for the next generation of Alaskans to benefit from. By providing the incentives, the decline is slowed, as is the problem of the 300,000 barrel threshold. The mathematics between a 6 percent or 3 percent decline provide almost enough time for a newborn Alaskan to grow up. He said AOGA's point is that the focus has often solely been on the dollars and cents this year and next rather than on the long- term reasons for that policy. 1:35:48 PM REPRESENTATIVE ROSES said if our objective should be to encourage more investment, and some of those investments are riskier and therefore more costly, it seems the credits should be adjusted according to the risk. He stated: In other words, those things that are going to be much riskier, which is outside of the current existing wells because we've heard the producers talk about taking the current well that exists and then running the horizontal wells out, we've heard them talk about the technology and how exact that science was and they could come literally within inches of hitting where they thought they needed to be because of all the seismic studies. It sounds to me like that is a lot less risky than going 40 miles off somewhere and drilling in an area where there are no existing wells. So, why would we not add a higher percentage of incentives for those types of wildcatting situations and reduce the percentage of incentives for those that are less risky potentials if we're talking about incentives as the key. 1:36:57 PM MR. WILLIAMS responded there are fundamental types of areas of investment to get more oil from the existing fields: infield drilling, replacing surface facilities that are close to 30 years old and were designed for 1.5 million barrels of oil per day, and should perhaps be redesigned to deal with the water and gas development and heavy oil and exploration. Infield drilling offers a short term ability to add production but the others are necessary as well. The known deposits of heavy oil and viscous oil are under the Legacy fields. The renewal of the surface facilities is of concern and is a backdrop to this session. To replace facilities so that they are adequate for 30 or 40 years requires a different type of investment than infield drilling. It's important to look at all of the puzzle pieces to find a good solution, however AOGA will make due with what the legislature decides. 1:39:04 PM REPRESENTATIVE GUTTENBERG said for the 20-some years that ELF was in place, the state's return intake was diminishing, theoretically because the investment was there but production has declined. Why is industry coming back now and asking for more incentives to stop the decline since the industry was not making those investments to stem the decline when most of the returns were going to the industry, he asked. 1:39:56 PM MR. WILLIAMS said that is partially incorrect because substantial investments were made in gas handling expansion and a seawater injection facility was built that provides 2 million barrels per day to keep the pressure up. He added that when he was commissioner, the counterpart of AOGCC was then called the Division of Oil and Gas. The division had a huge computer model that said the Prudhoe Bay field should produce 9.6 billion barrels, yet production is 2.5 billion barrels more than that and that is the result of investments. He conceded the ELF formula was flawed but he wouldn't say people didn't invest in Alaska to develop the Slope. 1:41:27 PM REPRESENTATIVE GUTTENBERG replied: And I didn't say that either. That was most of my work for 25 years. As far as investment for stemming the decline, and I don't know where that was or where that calculation was, but I know at the end of the day the pipeline has lasted a lot longer than they thought already and it has a longer life yet. Of course maintenance goes up ... I just look back and wonder - we thought they were making those investments then and the decline has been down. Now we're asking to increase our investment through the credits and all those other things. It's a question we're asking ourselves - how do we get to that? What is the right level of doing that when, from my perspective, it actually - when they had the advantage - more motivation to do that, that didn't happen. I recognize that you have a different opinion. 1:42:31 PM MR. WILLIAMS said one thing the ELF didn't have was tax credits - they are present here. After 1989, field size was the dominant element in the equation unless a field was close to averaging 300 barrels a day per well. Kuparuk's wells were going down to 300 barrels a day and, at that rate, the ELF formula became zero. 1:43:04 PM CHAIR GATTO asked if that applied to all wells in the field. MR. WILLIAMS said that is correct. CHAIR GATTO said there was concern that a company could add a few more unproductive wells to get the tax rate to zero. 1:43:34 PM MR. WILLIAMS questioned why a company would spend $1 to save 15 cents on taxes. CHAIR GATTO noted that depends on how many years one could save 15 cents. MR. WILLIAMS said he could provide a fairly straightforward demonstration, if members are interested. 1:44:03 PM MR. WILLIAMS again acknowledged the ELF was flawed and said: The point is: that is not where we are now. And, meanwhile, there was a lot of money spent developing fields, developing satellites, exploring for finding successes like Endicott and finding things that are less successful like Badami. And, still there are investments being made to develop new fields like NorthStar or Liberty. 1:44:52 PM REPRESENTATIVE GUTTENBERG said his point was that legislators are being asked to structure the oil and gas tax policy to create a behavior when no historical reason for doing so exists. 1:45:14 PM CHAIR GATTO asked what the output is of the Badami field. MR. WILLIAMS did not know. CHAIR GATTO said he has heard Badami was a "disappointment." MR. WILLIAMS said it was shut down for awhile and may still be. He offered to get that information for the committee. CHAIR GATTO said he is curious about the purpose of shutting it down and restarting it. 1:46:00 PM REPRESENTATIVE SEATON stated: ...We are in a position where tax policy does drive behavior, and previous tax policy drives behavior, and there were a number of wells - our information was - that were in Kuparuk that really weren't economic to keep running but that were kept running because it reduced the per-well production and so ELF went down. That doesn't mean that's bad. Whatever system we set up, you know, we have to look at those things and so a gross tax system can be gamed just like a net tax system can. There are different games in what we're hopefully trying to do and work with you folks in making sure we eliminate as many of those gaming possibilities as available under whatever tax system we come forward with. So, I don't think that we are totally in opposition saying oh, well a gross tax system ELF worked perfectly and didn't change behavior or didn't have unintended consequences and the same thing with the net tax system. And, so, there will be a number of amendments, I'm sure, offered to try to restrict those possibilities so that the desired outcome is there and I think that Representative Guttenberg's question about tax credits and all - I think we are trying to influence behavior and that's what the tax policy is for. Thank you Mr. Chairman. 1:47:40 PM MS. CROCKETT said she would agree that tax policy does drive behavior. She said legislators are attempting to strike the balance between influencing behavior so that the money does not get spent elsewhere as opposed to investing here. She submitted that tax policy influences behavior in a positive way. 1:48:23 PM MS. CROCKETT continued with her presentation. So, now moving on to the House bill, the committee substitute for HB 2001, how well does it stand up under the standard of fit for purpose? Certainly it would generate more tax revenue than the PPT will, even in the short term, but it is premised on the totally mistaken notion that increasing the government take from the economic pie will encourage greater investment, or at least not discourage it from what it would be anyway. No one has ever taxed economic growth into existence and this bill will not do so either. The second standard for evaluating the legislation versus PPT is 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 not possible to forecast the revenues from it with the accuracy needed for state budget purposes and, second, that the audit challenges of PPT leave the state's auditors hopelessly outgunned. So the questions that need to be answered then are how much merit do these criticisms have and would the legislation before you now address these concerns. Regarding the forecast for PPT, the Department of Revenue cites two major concerns with the forecast. One is that while costs would be expected to increase, the dramatic difference between what was predicted and what has actually been experienced brings into question whether the legislature made its decisions based on appropriate information. That's a quote. The other is that the department needs cost information about current and planned spending from the operators, producers, and explorers and this allegedly has not been forthcoming from them. Addressing the matter of the difference between the projected expenditures behind the fiscal note last year and what those expenditures have actually been, when the prior Administration saw information about expenditures last year, they chose not to rely on the representations about the 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 for the IRS. The federal partnership returns are not due with the IRS until October of the following year so, even as late as August of 2006, when the legislature passed HB 3001; the most recent returns available were for 2004. 1:51:00 PM On page 8 of the testimony, there's a chart showing the producer price index for oil and gas field machinery and equipment during the last decade. You can see, on the highlighted bar here and the graph that marks 2004, when you look at that bar and compare it out to what 2006 - the costs of doing business in 2006 were, you can see that there's a dramatic difference between 2004 and 2006. Now there was nothing sinister about what the Administration did, and I don't mean to imply that there was. The company said that the 2006 costs were high but the last tax returns at that time indicated the costs were significantly less with a fairly lengthy track record of gradual increases. 1:51:28 PM CHAIR GATTO noted oil prices increased by a 50 percent increase between 2006 and 2007, which had to make a dramatic change in the net profitability of every company that had produced any oil, as well as the state's revenue. He stated that has not abated yet so he suspects that rapid rise in costs had to do with decisions to take advantage of this high oil price environment and "pull out all of the stops." He asked whether it takes three months to increase or reduce production. 1:52:30 PM MS. CROCKETT said when prices are high companies drill more wells because the return on the investment is higher. However, more activity increases the cost of doing business because of a labor shortage, less steel available, etc. 1:53:01 PM MR. WILLIAMS explained that the graph shows what would have happened to the wholesale/retail prices of equipment over that period. He said the scope of work has gone up, which also increases costs. More people are working on the Slope now than for many years. 1:53:47 PM CHAIR GATTO said labor has increased in price. He assumed drilling rig crews must be imported from other places in the world. 1:54:10 PM MR. WILLIAMS said that 12 to 14 rigs have multi-year contracts on the Slope; the cost of the rig is set on the contract, but as those contracts roll over, the new contracts reflect any changes in labor costs. 1:54:36 PM MS. CROCKETT continued with her presentation. So back to the Department of Revenue's use of information that it had before it at this time. Again, they relied on the information that was reported in the tax returns and I suspect that, given the same situation if Revenue found itself in today, that they would do the same thing. It's a reliable source of information versus characterizations from the industry. The other criticism that DOR makes of PPT is that producers and other taxpayers are not providing information that it needs to forecast with sufficient accuracy. Obviously, AOGA is not privy to what taxpayers are reporting to DOR as they make their monthly installment payments and their annual true-up payments, but that information is available. DOR's second chief objection to the administerability and enforceability of PPT is the audit challenges, where it believes that it leaves its auditors hopelessly outgunned. AOGA does not have a position on the shifting of those classified positions to the exempt service. That's a decision for the legislature to make but there are some issues associated with audits and with PPT that we would like to address, however. This has to do with the starting point for determining how much a producer's deductible lease expenditures are. The PPT statutes currently allow DOR a choice between starting with the joint interest billings and invoices that operators bill to other participants or starting from a comprehensive set of accounting rules and principles that DOR writes up. What choice DOR chooses will determine nothing less than the very success or failure of PPT as a tax and for this legislation as well, if it is enacted. It's like having a tax based on your federal income tax and choosing between the federal return as audited by the IRS as a starting point or starting with the Internal Revenue Code, and leaving it up to you and DOR's auditors alike to find out what the right answer might be. 1:56:30 PM From the taxpayer's perspective, this means a near certainty of continual assessments year after year with additional tax, interest, and perhaps penalties, and 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 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 to be less than their face value. A taxpayer's only recourse in this situation will be to discount the face value of those investments in running the economic analysis about making an investment or not. So the effectiveness of those incentives will be less than what they should be and Alaska will fail to realize the full amount of new production it needs. The other choice that DOR could make would be to start with the operator billings to the other participants on oil and gas operations - and please note that I said start with those billings and not end. Anything in those billings that are non-deductible under the statute would have to be backed out. The central concept of lease expenditures is that they must be direct and ordinary and necessary costs of exploration development and production. It would be most surprising if there was anything in those billings that goes outside the 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've heard a great deal of concern expressed during these hearings about how companies might somehow game the system in order to reduce the tax that they will pay to the state. While so many are so worried about efforts by their companies not to overpay the state, why would most of these same people think that the companies want to overpay either one? If anything, since the operator usually is a direct competitor, they probably don't want to overpay that operator any more than they want to overpay the state. It's reasonable to rely on the operators - on the non- operators self interest to police and limit what the operator can spend money on and they do that policing by auditing the operators' invoices to them. In the context of PPT, the Department of Revenue should audit the audits to verify that operators do, indeed, audit an operator's invoices on a regular basis and that these audits are rigorous and at arm's length. But, once these things have been confirmed by the Department in its verification of the non- operator's audits, there is little point to DOR to spend the time and the effort to "replow" that the field that the company's audits have already plowed. Daniel Johnston, a consultant hired last year during the legislative debate on PPT, gave an informal presentation to members of the legislature, as you know, on October 19. During that meeting he praised the expertise of joint interest auditors and the ability for the state to utilize unit accounting. He went on to say that it would be extremely insightful for the state to get unit accounting and made the observation that state auditors are vicious, but that joint interest auditors are even more vicious. Of course for operations where there's only one participant, the applicability of joint interest billings doesn't really come into play but those joint interest billings, however, can be used as a basis for verifying expenditures that are ordinary and direct and lease expenditures tied to a particular operation, so, while you don't have the benefit of the joint interest billing itself for a single operator situation, the returns from that single operator can be measured against the joint interest billings from others. Unfortunately, in the legislation that we have before us today in Section 37, the ability of DOR to utilize the joint interest billings is being repealed. That ability does not require the Department to use them, but rather authorizes the Department to utilize those as one of the tools for auditing purposes. We believe that this repeal will mean that the Department cannot use those, even when DOR wants to allow their use. DOR has testified in other hearings that somehow they will still be able to require or authorize the use of operators' billings, even if the present statutory provisions are repealed. However, if you enact a law specifically saying that DOR can do something and then later on you repeal it, we believe that it means you cannot do that any longer. But even if you're persuaded by DOR that we're wrong on this point, why would you repeal those statutes and take the chance that the courts won't agree? I've spent so much time on this particular topic because of the situation a non-operator faces. All of the information it has about what's being spent on the operation is what it gets from billings by 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 of the books and records of the expenditure are with the operator and if a non-operator hasn't yet audited the operator, they'll have no idea what those books and records show. It's not feasible for a non- operator to be auditing the operator month-by-month, yet the non-operator must somehow have to be reporting and paying installments month-by-month throughout the year. Even by the March 31 true-up of the following year, it is unlikely that any audit of the operator's books and records will have begun by that date, much less completed. This is important because the penalty for misestimating the installments is principally in the difference between the rate of interest on overpaid installments and underpaid ones - by the March 31 true-up, is a very serious business. Interest at an APR of not less than 11 percent compounded quarterly begins to accrue and penalties of up to 30 percent for negligence and failure to pay can be assessed on the amount of any underpayment continuing after the 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? 2:01:10 PM Now this issue has been addressed by us and the Administration during hearings as I mentioned a moment ago, and they've stated that it is their intent to allow the use of the joint interest billings as one of the tools. I would encourage the committee to verify that with the Administration during your deliberations. In any event, if it is the intent to allow these to be used, there's no reason to repeal the specific authorization to do so. 2:02:39 PM And Mr. Chairman, I've attached to the testimony a white paper that provides some additional details about why we believe this is important. 2:03:14 PM REPRESENTATIVE SEATON referred to the joint venture billings and asked if the joint partners pay for items that are not deductible, such as lease expenditures under PPT. He questioned whether those things are segregated out as to what is deductible and non-deductible for our tax purposes or whether it is all combined and must be torn apart. He noted there are up to 20 non-deductible lease expenditures that are chargeable to the other partner. 2:04:26 PM MR. WILLIAMS told members a number of things are specifically excluded in the statute that don't go into joint venture billings - costs of disputes, arbitration between partners, etc. Some costs, such as the cost of response clean-up and remediation are not allowed. The billings have a long series of accounts so that each recipient can see each separate cost involved in the remediation of a spill. The recipients will be able to figure out what costs need to be removed from the deduction and the billing so the state would not be paying for those. From an audit standpoint, that will ensure that what is spent for a disallowed category has been removed. 2:06:37 PM REPRESENTATIVE SEATON responded: So, we've got this huge stack of accounts and of course there's no reason for the joint partners to be separating those items out that are non-deductible against PPT, so they're all going to be mixed in with all of the things that are allowed to be deducted by the joint partners - I mean allowed to be billed at the joint partners. Is that correct or is it segregated out so that it's fairly easily tracked without going into each account category? 2:07:14 PM MR. WILLIAMS explained the operator can't advise people that certain accounts are disallowed costs. Each taxpayer has its own tax department and responsibility for going through that. At least it will know what costs have been spent. He said if a cost can be argued either way that taxpayer will have to make a call and the auditor will check. However, in terms of the amount in each account, the question is whether those are direct costs of running the field - are they ordinary and necessary costs. With respect to those standards, a company won't give an operator a license to waste its money to run another field so that won't include a jet at headquarters. That discipline will exist among the partners; however, it will not exist for a company with no partners. He pointed out one company might have a 99 percent interest in a field and that is an area where DOR will have work. He added: But, for a number of the fields in terms of the audit workload, some of this can be made simpler than for these ones where you don't have the audits going at all between partners... Even now, I would be stunned if there was anything in the joint venture billings for PPT currently or under the proposed ACES legislation that is not a direct cost and not an ordinary and necessary cost of running that field, just because of each participant's desire to keep its money for itself and not to waste it, and not to let the operator waste it for them. 2:10:16 PM REPRESENTATIVE SEATON replied: I understand your point and the point of the Administration. The Administration is saying that they're going to use the joint billings as part. Each one of your companies on previous to the joint billing statements has to submit all of the tax, you know, accounting at the true-up time to the state. So, I guess I'm trying to weigh this. Let's say Company X has to file their PPT tax form on April 1st... and then they may modify it when things go down the line and they get some more billing or whatever - joint billing statement from the operator in October. They're still going to have to submit a revised PPT billing if there's something different. So, I guess the question is, does this make any difference as far as the tax liability or the tax timing or is it just simply that AOGA and the companies are wanting to have the auditors first check the submitted tax - PPT tax statement from each company against the joint billing statement but it doesn't prevent them from going any farther than that. Am I correct? I think many of us are quite confused at what this big problem is to tell you the truth. 2:12:07 PM MR. WILLIAMS explained the problem is that the existing authority that says the department may authorize or require the use of the amounts billed or billable by the operator (Section 165(c) & (d)), which will be repealed in the bill. If that statement is repealed, does that mean DOR cannot use them? He said as long as it is clear that the legislative intent is to allow them to continue to use it, that language can be removed. However, if that language is left by itself, it could create an unintended consequence that neither the Administration nor AOGA want. If a non-operator in a field cannot use the joint interest billings, it has no starting point from which to report and make its estimated payments. If it turns out that during the audit the auditor decides differently, the operator will be on the hook for not being accurate. 2:13:39 PM REPRESENTATIVE SEATON questioned whether this is the real criteria the non-operator needs to be able to rely on for the PPT tax filing and to determine whether DOR has the legal authority to require that is the crux of the matter. 2:14:08 PM MR. WILLIAMS said that is correct. The non-operator pays the billings; that is the cash out of his pocket. 2:14:27 PM MS. CROCKETT continued with her testimony. Progressivity, as you know, is a feature of the PPT. It's an addition to the PPT tax. Like the existing PPT, the present progressivity tax is based on the "net value" of production. But, unlike the basic tax, it is computed monthly instead of on an annual basis. The rate for progressivity in the current system is zero when the "net value" per barrel is $40 or less, and it rises linearly at a 0.25 percent point per dollar that the net value of the equivalent barrel rises above $40, then up to a maximum rate of 25 percent. The 0.25 figure, which sets the rate at which the tax rate rises, is known as the "slope." I should repeat that what I've just described here is the current system and not the system that's embodied in the committee substitute for you at this time. 2:15:26 PM The rationale for progressivity boils down to little more than, at these prices, that the oil industry can afford to pay more. If affording to pay is the rationale for setting taxes, then who was arguing not even 9 years ago to give the industry a break when the spot price for a barrel of ANS on the West Coast after spending the $4.26 for transportation to get it there crashed to $8.16 in December of 98. Nobody. It is this asymmetry that makes progressivity so objectionable to the industry. We have put all of the capital and taken all the risks in making that investment. Periods of high oil prices are not only an opportunity for industry to catch up for periods of low prices, but they are also an opportunity to make up for expensive investments that prove to be unsuccessful. The one example that I've included in my testimony today is the Mukluk prospect. Industry paid over $1 billion in bonus bids for that prospect in 1982, then it spent another $135 million installing a gravel island and drilling an exploratory well, which turned out to be, unfortunately, a dry hole. 2:16:34 PM REPRESENTATIVE ROSES agreed with Ms. Crockett's statement about spending $135.6 million in 1982, but said today, a considerable amount of credits under PPT and ACES would reduce the liability for that company to an amount considerably below $135 million. He stated the state has made a considerable amount of investment to help provide oil companies the incentive to do exactly that. He suspected that Ms. Crockett's statement, "We have put up all of the capital and taken all of the risk in making the investment ..." is inaccurate. He recounted that several producers have said one of eight or ten wells drilled are productive and said if the state is allowing exploratory credits at 20 percent and 22.5 percent off of capital investments on all ten wells, the state probably has taken an equal amount of risk in terms of the amount of money put up and probably has fairly significant investments. While he agreed with the concept, he felt it inaccurate to say the industry is putting up all of the capital and taking all of the risk. 2:18:32 PM REPRESENTATIVE FAIRCLOUGH said she is on the same page as Representative Roses as she construed Ms. Crockett's comments as a request to take the credits back off the table and that the industry would repay all of the costs the state has allowed as credits. She said there is some balance in the progressivity language to incorporate AOGA's truth and the state's truth. 2:19:13 PM REPRESENTATIVE ROSES clarified that he appreciates Ms. Crockett's and Mr. Williams' work but clarified his point is that a lot of people do not realize the amount the state invests to ensure the oil continues to flow. The legislature's most difficult task is to find the balance between the state's return on investment and the industry's return on investment. He noted the fact is the state and industry are partners with investment and risk. The state must determine a point where it encourages investment and captures the maximum return for the state for its investment and risk. 2:21:07 PM CO-CHAIR GATTO offered his opinion regarding public perception on the oil taxation issue: The public hears we want to take even more money from the oil companies. And I think it is important to recognize that the money comes from the oil. It's our oil and we share in the resource and the oil companies get a share and we get a share. And the debate may be over what's the fair way to put it. If we put in 50 percent of the money, do we only get 40 percent of ... the revenue, and if you put in less money you get more of the revenue, et cetera. And that's the debate. But the statement that we take from the oil companies is very far from truthful because we both take from the resource and it's only the way the allocation is made that determines who gets what percent. ... There are things that the public hears - sometimes in simple things like letters to the editor or talk show callers or newspaper articles or certainly trade publications, which are very strong depending on what side they're on. They're usually on the side of the oil companies and they have the most sway - how much more do you want to take from the oil companies? Well, we haven't taken any yet, so we're not taking any more. And, to me, that's an important distinction and Representative Roses and Representative Fairclough and the rest of us recognize that that distinction is very clear to us because we deal with it all the time. It should be clear to you because you deal with it all the time. And I think, in all fairness, when we do speak to the public at-large or write articles in the paper, that we ought to be at least somewhat more careful in describing what we take from the oil companies and the fact that you take all the risk and, yet, of the small amount of money being made that we take even more from you. That puts us in a horrible light. And I'd be willing to be in that horrible light if it was true and say I need to defend myself now, because what we're doing is unfair, is greedy - and, by the way, we get called greedy all the time, too. And I'm thinking - who gets most of the money here compared to the investment they make? Are we greedy for demanding for our shareholders what they deserve? And can we assign the term to some other partner of ours and saying, "You know, you're taking away from those single moms with three kids who are sick at home today and don't know what they are going to do for the next dollar." And they deserve something better than to be called greedy. So, I know we're kind of dumping on you about this, but you are ... with AOGA, not just with them, I mean you're important. And you get that message to any thousands of people. And I'm not sick of all the ads that have shown up, but I kind of smile at them sometimes because I recognize that this group here - and the building at large is responsible for making the most significant decision of the decade ... and maybe because many of us were here for the previous one, that we're involved in the most significant issues of the decade for us - declining production et cetera, high oil prices et cetera. And ... we're going to make that decision based on solid information that we get. But then there's all that stuff that goes out over the air waves that's - I don't want to say it's hurtful - but, it's inaccurate and we don't respond with a million dollar ad campaign saying, "You know, BP did not give us these parks." The oil in the ground gave us the money so that BP could get a share of that money and then give a little bit back to the community. I'll give you that. But sometimes the information is out there that, "You know, we're enjoying these parks because of an oil company." And I'm not sure that's fair, because we're enjoying the parks because of the oil resource that we own. And what we're doing is asking the companies to come out and say want to make some money? You want to make some good money? Come on out here, bring some drilling rigs. We'll get somebody to build a pipeline, we'll ship the oil, and we'll sell it to somebody else. And we'll all make money. And not that we are greedy for asking a share of the money since we started with the oil and other people brought in money and made a considerable amount of money. And, I'm going to apologize for all of this, but at some point, certainly as the week drags on, I really would like you to understand our position on this. I feel sometimes we're taken to be a little bit slow in that you make some accusations, we don't respond, you make some more accusations, we don't respond. Because, even though we don't believe them, and we hope lots of people don't believe them, sometimes responding just creates ill will and then we start a war in the media about who said what. And I want to thank my colleagues that we don't do that. 2:26:46 PM MS. CROCKETT said she agrees with a lot of the points Chair Gatto raised but said AOGA's advertising that has occurred over the past month has had one goal, that being to give the public a heads-up that the number one issue facing Alaska today is declining production. Therefore, it is important to strike the balance Representative Rose just spoke to. 2:28:08 PM REPRESENTATIVE GUTTENBERG admitted he finds AOGA's advertisements to be offensive. He noted last year at the close of the session, Mr. Hosie, a successful oil and gas attorney and successful litigant against the [oil] industry, talked to legislators about the obligations under the contracts. The state owns the oil and gas. It is not a producer, developer, or construction outfit. When the state enters into a contract with a successful bidder, they get 87.5 percent of the royalties; they are then obligated to look out for the state's best interest, no their own. That only happens when folks come in and convince legislators that it is more important to change the tax structure and give tax breaks. He surmised if the industry was looking out for the state's best interest in the long term, the state would not be looking at such a steep decline in production because maintaining production is in the state's best interest. He said the state has been encouraging more exploration, development, and new technologies for the last 20 years. Had the industry lived up to its end of the bargain, nobody would be having this discussion today. Alaska could have been the leader in oil technologies, but it is not. He agreed with Chair Gatto's comments about the partnership but said he has found the relationship to be disappointing in many ways because it has not always been above board. 2:32:15 PM REPRESENTATIVE JOHNSON pointed out the two basic ways to distribute the oil wealth are through taxation and jobs. He said the state needs its fair share but it also needs to keep people employed. He said he does not believe the importance of the employment issue has been discussed and should be considered in the balance. 2:33:44 PM REPRESENTATIVE WILSON said as she listens to all of the oil companies now, she recalls how the same industry representatives said the PPT would cause all kinds of problems when it was first adopted. Now they are saying it is wonderful. She said it is all relative. Now they are asking legislators to keep the PPT and not adopt ACES. She understands their positions but finds the situation to be ironic. 2:35:08 PM MR. WILLIAMS said he doesn't want to respond to the statements that were made as such because, as Chair Gatto said, a response can sometimes be counterproductive. He noted in a fundamental sense, the industry is repeating what it said last year - that somewhere between a tax system where the state takes nothing and where it takes 100 percent is a sweet spot. AOGA said last year it thought PPT overshot the mark; it is now saying the same thing. AOGA's point is that a sweet spot exists and AOGA is telling legislators where it sees that spot. That spot must consider the trade-off between jobs today and jobs tomorrow and revenue today and revenue tomorrow. At the end of the day, that point is the legislature's decision and everyone respects that. No one means to demean that or the difficulty of the task. He said industry representatives are urging legislators to get to that spot, despite the rhetoric. 2:37:36 PM CHAIR GATTO asked what the advertisements are saying. MR. WILLIAMS said he did not know. 2:37:39 PM REPRESENTATIVE EDGMON agreed with Mr. Williams' characterization of the situation. He said the discussion confuses him because it appears the progressivity theory gets both the state and producers to the sweet spot. He asked if AOGA does not support progressivity but agrees in concept that the state should get more on the upper end when the producers are getting more profit, and conversely both share at the lower end when oil prices dip. He asked what AOGA would support if it does not support progressivity. 2:38:30 PM MS. CROCKETT said AOGA's position is that PPT should not be changed. It contains a progressivity piece, something AOGA did not support last year, but it is current state law. AOGA believes the system in place today provides the sweet spot mentioned. 2:39:00 PM REPRESENTATIVE EDGMON asked why Ms. Crockett's written statement says the asymmetry makes the progressivity so objectionable to the industry. 2:39:16 PM MS. CROCKETT said AOGA supports the PPT in force today, which has a progressivity feature in it. She said AOGA doesn't really like progressivity as a general concept, but that is immaterial. The fact is the state law contains a progressivity feature and AOGA is willing to live with that law. It does not want that increased. 2:39:45 PM CHAIR GATTO noted Ms. Crockett's opening page says AOGA requires a 6/6 vote to adopt a tax policy - that being no dissent. He asked if the entire AOGA tax policy committee accepts the progressivity clause in the current PPT law, but objects to it in ACES, he would assume the entire committee objects to progressivity. 2:40:28 PM MS. CROCKETT explained the progressivity clause is an increased tax in the ACES legislation. CHAIR GATTO asked if the entire tax policy committee objects to progressivity in the ACES legislation. MS. CROCKETT said that would depend on what the progressivity contained in it. She said AOGA is living with a tax that contains a progressivity feature; its members have agreed that tax should not be changed. However, when you get into changing bits and pieces of it, AOGA has to step back and make a judgment call on whether it likes or dislikes the proposed changes. She repeated AOGA's position is that PPT should not be changed. 2:41:35 PM CHAIR GATTO said no one considers Ms. Crockett to be disagreeable but when the committee reads something in print that requires AOGA members to support it, members must ask the tough questions and AOGA must "slug it out" and support its statements. Those exchanges provide a golden opportunity to take the legislature's message back to the association that some statements need to be clarified. He questioned whether AOGA does not support any amount of progressivity in the ACES legislation. 2:45:37 PM REPRESENTATIVE FAIRCLOUGH said she appreciates the difficulty of representing so many industries within AOGA. She noted Ms. Crockett was the benefactor of an earlier discussion on progressivity and gross and net tax and how important it is for each legislator to represent their districts and all Alaskans and that the commonality is that everyone wants to do the right thing for Alaskans and the state. 2:47:15 PM MS. CROCKETT told members AOGA is concerned that the House bill before the committee does not meet the fit for purpose standard. AOGA is also concerned about the decline of production. AOGA hopes the legislature continues to strive for the balance discussed during the meeting. She thanked members for the opportunity to testify. 2:48:17 PM REPRESENTATIVE ROSES said his point was that he finds the producers' comments about their partnership with the state to be a bit disingenuous when they say they have made all of the investments and taken all of the risk. He repeated the word "all" bothers him because the state shares in that risk. 2:49:18 PM CHAIR GATTO congratulated Ms. Crockett on her appointment to AOGA's executive director position and apologized if his comments were aggressive. He repeated the frontal conversations must occur. MS. CROCKETT informed members a staff member from AOGA's production department is available to answer questions. The committee took an at-ease from 2:51:13 PM to 3:08:38 PM. 3:08:51 PM CHAIR GATTO reconvened the meeting and announced that the committee received a written response from Marcia Davis of DOR to a committee member's question. 3:09:49 PM PAT FOLEY, Manager of Lands and External Affairs, Pioneer Natural Resources Alaska, told members he would like to re- familiarize them with Pioneer as a corporate entity and give a status update of its projects in Alaska. He then said he would address the existing PPT legislation. [Mr. Foley's testimony accompanied a PowerPoint presentation.] 3:10:20 PM MR. FOLEY said Pioneer would like the committee to resist the temptation to makes changes to the existing tax legislation. He noted, in regard to previous questions about how quickly the industry can react, he would liken the industry to a steamship. It cannot start, stop, or turn on a dime, he noted. He said PPT is a tax system that will motivate investment but it is too early to see any behavioral changes from that tax policy. He submitted it may take several years to see any changes. 3:11:24 PM MR. FOLEY informed members that Pioneer is a large U.S. independent with operations in Alaska and the "Lower 48," which is its breadbasket. Pioneer does a lot of work in Texas, both oil and gas onshore, and has large coal bed methane assets in the Raton Basin [in Colorado] and it does business in South Africa and Indonesia. 3:11:51 PM CHAIR GATTO asked Mr. Foley to clarify whether his company replaced the Evergreen Resources operation in the Mat-Su Valley and, if so, to summarize the transition. 3:12:18 PM MR. FOLEY told members his company did acquire Evergreen Resources, primarily for its coal bed methane assets in Colorado. Evergreen's Alaska business did not fit Pioneer's business model so, when it took over, it surrendered Evergreen's leases within a year. 3:12:54 PM CHAIR GATTO asked if Pioneer obtained some leases on the other side of the Castle Mountain fault. 3:12:57 PM MR. FOLEY said it did not. He explained another company named Pioneer Oil came in and placed bids on some of those leases as soon as Pioneer Natural Resources Alaska surrendered them. 3:13:36 PM MR. FOLEY jested his company is the little company spending all the money on the North Slope right now. 3:13:52 PM MR. FOLEY told members Pioneer Natural Resources Alaska has about 1600 employees worldwide, most are located in its headquarters outside of Dallas. In 2006 its revenue was about $1.6 billion. Its market cap is about $6 billion. In comparison, ExxonMobil's market cap is about $500 billion. 3:14:46 PM MR. FOLEY said Pioneer entered the state in 2003 and acquired some leases. Pioneer drilled three exploration wells that have led to its Oooguruk development - Pioneer's flagship project on the North Slope. It has a 70 percent interest in that operation and is partnered with ENI, the Italian national oil company. Pioneer is also working on another project in Cook Inlet called Cosmopolitan in Anchor Point. That resource was discovered decades ago. Pioneer has acquired 100 percent of the leases; it has an appraisal rig working at that location today. It should finish drilling very soon and then spend several months testing the well. Hopefully that will lead to another development. He noted that Cosmopolitan is roughly similar in scope and scale to its project on the North Slope. 3:16:07 PM CHAIR GATTO asked if that project is similar to an on-land oil platform. 3:16:09 PM MR. FOLEY said that is a very good analogy; it is on land although the resource lays offshore, as far as 3+ miles, so Pioneer's entire development plan would be onshore drilling with extended reach wells. He said Pioneer is also an exploration company. It owns about 1.5 million net acres on the North Slope, the vast majority of it is in NPR-A. It has an exploration joint venture with Conoco Phillips and Anadarko. Since Pioneer entered the state, it has participated in the drilling of 11 exploration wells. He told members, "To be frank, we haven't hit the ball out of the ballpark yet." Oooguruk was originally a well that targeted a Kuparuk formation. That well failed in that target but a Jurassic resource was discovered, which is the focus of the Oooguruk development. The resource did not lie upon the leases Pioneer drilled; the vast majority was on adjacent lands owned by Conoco Phillips. Through a series of transactions, Pioneer now owns them. Pioneer employs 35 people in Alaska. 3:17:50 PM MR. FOLEY discussed a statistical summary of what Oooguruk is all about, and characterized it is an oil play. Pioneer is the operator with a 70 percent interest; its partner ENI has a 30 percent interest. The resource is in the 70-90 million barrel range. Pioneer has been working on the project for several years and if all goes well, production will begin in 2008. It will produce about 15,000 barrels per day at its peak and has a 25 year field life. 3:18:34 PM CHAIR GATTO noted Alaska will have oil for a long time. He asked if Pioneer's Cook Inlet area is a good one because it has a high likelihood of success. 3:18:37 PM MR. FOLEY said the Chair's question is actually focused on exploration. Cosmopolitan is a discovered resource. The original well was drilled several decades ago but was uneconomical to develop at that time. Pioneer has not yet made a development commitment but it is on the "radar screen." 3:18:42 PM REPRESENTATIVE EDGMON asked what will become of the Kuparuk island when the project is complete. 3:19:45 PM MR. FOLEY told members the island consists of 500,000 cubic yards of gravel that sits in 5 feet of water. The edge of the island is made from 4 cubic yard gravel bags that provide slope protection and prevent erosion. At the end of project life, the bags will be removed and it will be abandoned in accordance with the state's resource agencies at that time. It is possible that the best abandonment plan will be to leave it intact and let it erode naturally. 3:20:38 PM CHAIR GATTO asked about an abandonment plan known as the Cook Inlet hotel. He asked if any other use exists for a piece of land so beautifully isolated other than to abandon it. 3:21:05 PM MR. FOLEY pointed out that Oooguruk is in the Beaufort Sea, not in Cook Inlet. CHAIR GATTO recalled he was thinking of the on-land Cook Inlet project. MR. FOLEY said Pioneer sanctioned Oooguruk in 2006. It has constructed a gravel island, set modules on the platform, and installed a buried subsea flow line. Pioneer is weeks away from beginning a 3-year development program and very proud of its accomplishments there. It bought the leases in 2002 and drilled exploration wells. Hopefully oil will be flowing in 2008 so that in a 5-year timeframe, it will have gone from first well to production. 3:22:34 PM MR. FOLEY said during the past winter, Pioneer had over 600 contractors working on its project on the North Slope [Slide 6]. The total capital investment in that project will be $550 million plus. He noted the benefits of a project like Oooguruk are tax dollars, jobs, and state income taxes. It also has intangible benefits. Pioneer will be the first independent oil producer on the North Slope. It will enter into a facility access agreement with the Kuparuk River Unit making it the first third party owners to rely upon existing infrastructure to process its crude. A number of companies are watching closely to see if this endeavor is successful. Pioneer's leases are unique in that they have a net profit component, meaning 30 percent of net profits are paid to the state. 3:23:40 PM MR. FOLEY discussed slide 7, which refers to government take - the piece of the profit that the government enjoys. The reciprocal is the company take, the share kept by the investor. He said the punch line is that government take is dependent upon costs and burdens. 3:24:58 PM MR. FOLEY referred to a book authored by Daniel Johnston, an esteemed academic who testified before the legislature. One of Mr. Johnston's books details different elements of petroleum fiscal systems. In that book he highlights the simple point that high cost fields have a differentially high government take if a royalty component is included. 3:25:31 PM MR. FOLEY focused on the first two columns of the chart and told members he normalized everything at 100. A royalty that behaves as a gross tax comes right off the top. Most leases in the state are 1/8th royalty. All of the newer leases have a higher royalty rate, most are 1/6, and a few scattered leases have a net profit component. MR. FOLEY said to calculate one would subtract the royalty from 100 to get the net revenue. The next task is to remove costs. To differentiate the high from the low, he assumed costs were 20 percent of the gross revenue. The high end costs were assumed to be 50 percent. He said Mr. Johnston highlighted the Gulf of Mexico in his book, which provides a much simpler example because those operations are not subject to state income tax, property tax, a PPT, etc. 3:26:48 PM MR. FOLEY explained that once costs are deducted, the result is a taxable net income. Then the state would take its taxes - a state income tax, a PPT tax, and a federal income tax deduction. The AFIT is what remains after everything is paid. The company take would amount to the piece of the pie left over divided by the sum of gross revenue minus costs. The low cost would be 28.3 divided by 80 (100-20). The divisor in the high cost would be 50 percent, in the form of costs. 3:28:00 PM REPRESENTATIVE FAIRCLOUGH questioned why the chart shows a $1 difference between the high and low property tax. 3:28:12 PM MR. FOLEY said there is a difference between the high and low. Property tax is a function of depreciated capital, similar to a percentage of the assessed value of a house. REPRESENTATIVE FAIRCLOUGH questioned whether the higher cost would be due to a higher cost of infrastructure. MR. FOLEY said that is correct. 3:28:47 PM REPRESENTATIVE ROSES asked what the numbers look like when you start adding credits back for exploration. He asked if the whole dynamic would change as the percentages would start to shift toward the contractor. 3:29:13 PM MR. FOLEY said it would and that he made an attempt to incorporate credits in this analysis. The number under PPT is 28 percent, which equals 22.5 percent plus the progressivity. For the purpose of this calculation, he assumed 30 percent of the total cost. Then, he credited back 30 percent of the total cost of capital investment so the PPT is credited with 20 percent of the assumed capital. He stressed the numbers are hypothetical but this model has attempted to incorporate the credits so the PPT payment shown is net of credits. 3:30:37 PM CHAIR GATTO asked if 30 percent of the cost represents capital investment. 3:30:46 PM MR. FOLEY said that is just an example; it may be that the typical project will have a percent of total costs to be 50 percent operating and 50 percent capital, eligible for PPT credits. 3:31:17 PM REPRESENTATIVE ROSES asked about the PPT tax rate. 3:31:30 PM MR. FOLEY said it is 22.5, but under existing PPT there is a progressive element that has both a trigger point and a slope. He thought that to be 2/10ths of a percent per dollar. 3:32:02 PM REPRESENTATIVE ROSES clarified it is 2/10 percent on the net so that operating and capital expenses are removed before the progressivity kicks in. He pointed out that Mr. Foley's chart goes from 22.5 to 28 percent, which means that the 5.5 percent increase should have decreased if credits were taken into account. 3:32:35 PM MR. FOLEY replied: ... Again, the 28 percent is not - if you were to open this up as a workbook, you'd see that this number - 17 - is not 28 percent of taxable income. It's 28 percent of taxable income but there is also a credit. I think the number actually calculated at 19 or a number like that - I don't recall exactly - but it takes into account the credits that you'd enjoy by making a capital investment. We just selected - your capital investment will be roughly 30 percent costs. 3:33:20 PM REPRESENTATIVE ROSES asked to see that breakdown later. 3:33:35 PM MR. FOLEY clarified that his point is that high cost and low cost fields have different company takes. 3:33:53 PM MR. FOLEY said the column on the right illustrates a project with a 30 percent net profit component. He tried to keep the other variables the same. He explained that under the net profit system an additional 10 percent is paid to the state, which affects the government take and increases it up to 80 percent in this example. If the debate is about what is a fair and equitable share, not every field has the same fiscal regime if you want to implement a constant fair and equitable take across all investments. 3:35:01 PM REPRESENTATIVE WILSON asked if the net income was derived by dividing the 28.30 by 80. She asked if others needed further explanation. 3:35:28 PM CHAIR GATTO said the committee would work through and reach a conclusion and that Representative Fairclough would explain later. REPRESENTATIVE FAIRCLOUGH replied: Mr. Chairman, absolutely not. I think there is a variable of assumptions up there that are already being challenged and so we need to take it just as illustrative to understand that all of those variables - which we could go back and challenge. There's a different assumption - well, it may be the same assumption but there's an assumption on the cost of the assets or value of the assets and there's an assumption on some credits that our resident mathematician has pointed out that we might not all agree so I think that we need to take it as it is and continue. 3:36:18 PM REPRESENTATIVE SEATON said he also has some questions on the mathematics of the high cost of low gas but thought Mr. Foley was trying to illustrate that the bid taken with a 30 percent profit sharing program would have a different government take than the standard operation across the slope. He questioned whether the difference between the right-hand column and the other two is that the government take for the Oooguruk project with a contract with a 30 percent net profit share is different than for normal fields across Alaska. 3:37:18 PM MR. FOLEY said that is correct. He said the simple point is the government take is affected by cost and affected dramatically if a net profit component is involved. The government take is the highest when there is a high cost development with a net profit component. He added that although Oooguruk is not represented exactly, it is very similar to the right column. 3:38:14 PM REPRESENTATIVE ROSES asked whether that entity with which Pioneer negotiated agreement with the state for the well mentioned will be affected by changes to the taxation policy. 3:38:34 PM MR. FOLEY said that is incorrect. Pioneer has a contract and an oil and gas lease with a royalty component and a net profit component and it is subject to PPT and state income tax laws. REPRESENTATIVE ROSES asked if that additional. MR. FOLEY affirmed that is correct. 3:39:07 PM MR. FOLEY continued with slide 8, which describes where the net profit leases are located. Some are located in the Colville River Unit; 4 of the leases in Oooguruk are net profit leases; Nikaichuq; some are close to Duck Island. This graphic representation shows the net rates. 3:40:08 PM MR. FOLEY showed slide 9, which differentiates the leases by operator on the same map. 3:40:51 PM REPRESENTATIVE WILSON asked if Pioneer does not want a net profit situation. 3:41:09 PM MR. FOLEY said the legislature is considering a tax change and the basis of that change is for the state to get a fair and equitable share. He submitted on North Slope projects that have a net profit component, the government take today is 80 percent so those projects simply cannot afford to pay an increased tax. 3:41:50 PM REPRESENTATIVE JOHNSON asked what the benefit is and why anyone would enter into a lease that pays more. 3:42:13 PM MR. FOLEY answered the State of Alaska had numerous lease sales in the 1960s. All of the original sales had a 1/8th royalty. In the early 1980s, oil prices were high so the state started offering leases that had a net profit with the royalty. Most of those leases never got developed because the difficulty of administering that type of lease is fairly high. Stacked next to a lease with a 30 percent net profit, it is the lease without the net profit that would attract the investment dollars. The state had 3 or 4 sales with net profits and then returned to a flat 1/8th royalty or a 1/6th royalty. 3:43:20 PM REPRESENTATIVE JOHNSON asked about the amount of oil being produced out of the net profit leases and where they exist in the history of an oil project. 3:43:37 PM MR. FOLEY pointed to a red block on the far left of the map on slide 9 that contains leases in the Colville River Unit. He did not know if production is allocated to those leases. He told members the Department of Revenue publishes a report of income from net profit leases that would contain the information Representative Johnson is looking for. He pointed out the Oooguruk leases are colored pink; they are net profit leases. He did not know whether production is allocated to leases on the northern end of the Kuparuk River unit. He said Milne Point and Duck Island have some net profit leases. All of the leases that are still in existence today with a net profit component either have a certified well that holds them or they are within a producing unit, otherwise they would have expired years ago. 3:44:55 PM REPRESENTATIVE JOHNSON asked what the effect of excluding net profit leases from this legislation would be. 3:45:13 PM MR. FOLEY said Pioneer would be thrilled as it would dramatically improve the economics of its projects. 3:45:25 PM REPRESENTATIVE JOHNSON asked if that would equalize projects across the slope but not give Pioneer a benefit. 3:45:35 PM MR. FOLEY said it would put Pioneer on a level playing field. He stated: For absolute disclosure here, Pioneer also has sought and we have received royalty reduction for our project, so for a period of time, our royalty falls down to 5 percent and then escalates. The reason it does is our project is marginal. It would not have been funded in a low price world and because of this additional burden of net profit, it was uneconomic. 3:46:16 PM REPRESENTATIVE JOHNSON asked if Pioneer would be better off with a 5 percent reduction in royalty or with a net profits lease and the 5 percent reduction. 3:46:29 PM MR. FOLEY replied that Pioneer would trade its royalty reduction for the elimination of net profit in a heartbeat. 3:46:45 PM REPRESENTATIVE FAIRCLOUGH added: In response to Representative Johnson's line of thought, the advantage is that this acts like a license and the licensee knew that there was a fine [line] there that was uneconomical to develop and went in and developed that knowingly, and we had a previous owner that received benefit or a lack of benefit when they had to go sell the property under those same terms. And so, there could be said that whoever owned the lease prior to the current ownership took a net loss with those conditions over the course of the years that were applied on to it. And so, while I do recognize the value of your questioning and what it would do for the State of Alaska to encourage development and exploration and production of those wells, we should be careful in our thought process before we move forward on that without speaking to legal counsel as to the litigation that might come forward afterwards. It certainly is within our power to change the taxing policy but there are contracts out there with other explorers that would be implicated with that type of a decision - but being treated in a different manner also. It depends if they're the original holder of the lease. 3:48:07 PM REPRESENTATIVE JOHNSON said he would like to find a way to level the playing field for small producers. 3:48:29 PM MR. FOLEY said his point is a project with a heavy net profit can't afford additional tax burden. He said Pioneer is not specifically asking the legislature to reconsider its net profit interest; however he'd be pleased if it did. 3:48:49 PM MR. FOLEY moved to slide 10, which pertains to the existing PPT legislation. When Pioneer entered the state, it spent roughly $100 million between its first investment and the time PPT was enacted. Pioneer sanctioned its Oooguruk project prior to PPT. Pioneer views PPT as durable, equitable, and balanced. He explained that PPT is a tax increase over ELF but the benefit of the credits for smaller, more marginal projects is huge. Pioneer is taking PPT credits into effect when making investment decisions. He thought the new explorers trying to drill exploration wells are doing so too. He believes the credits are an indication of a true partnership. 3:50:22 PM MR. FOLEY told members the state is an investor in this project under PPT and the credit program. 3:50:36 PM MR. FOLEY said when Pioneer entered Alaska, it was attracted by the prolific petroleum system. When it started its exploration program here, it found all of its resources, although large, are challenged, either by viscosity, location, oil quality, or size. The odds are Pioneer's finds will be less attractive than it hoped. The PPT and credits enable marginal projects to go forward. 3:52:04 PM REPRESENTATIVE JOHNSON asked if manmade obstacles, such as access to the pipeline, will make putting oil in the pipe problematic. 3:52:53 PM MR. FOLEY told members a basin goes through a natural maturity process. It is typical for large companies to make early investments. Similar to the Gulf of Mexico, he believes the North Slope oil basin will undergo a change in which the activities of larger companies will decrease and the activities of smaller companies will grow. Pioneer has been negotiating for facility access with the Kuparuk River unit for facility access into its fields. 3:53:47 PM MR. FOLEY informed members Pioneer has avoided making capital investments to build its own production facilities. Instead, it is going to lease capacity from the Kuparuk River unit. The agreement is not yet signed but he is 100 percent confident it will be and allow Pioneer to stay on schedule and have first oil in 2008. He explained that TAPS is the Kuparuk River pipeline - they are common carrier open access lines, which simply means the pipeline has to take any barrel. It has a regulated tariff. 3:54:50 PM REPRESENTATIVE ROSES said he appreciates that what Pioneer expected to find was not what it found. He asked if Pioneer is planning to drill more wells. 3:55:09 PM MR. FOLEY said yes, Pioneer still has 1.5 million acres gross on the North Slope and has hopes for a continued exploration program. 3:55:23 PM REPRESENTATIVE ROSES asked if Pioneer would make the same decision to purchase its original leases, knowing what it knows today. 3:56:04 PM MR. FOLEY said he cannot answer that question without more thought. He said the cost environment on the North Slope is a bit higher than it expected and, because of inflation and pressure on the industry, costs are even higher. He added the price of oil is also a lot higher. Regarding tax policy, when Pioneer entered this state, it made a commitment to develop Oooguruk under the old ELF regime. Under ELF, Oooguruk would have paid zero taxes. Within days of sanctioning the project, a dramatic tax change under PPT was announced. He pointed out there are cost and price scenarios where Pioneer is better off under PPT than it was under ELF. 3:57:21 PM REPRESENTATIVE ROSES asked, given the situation under the House Oil and Gas bill - not ACES, would Pioneer make that same investment today. He asked at what point the state will provide enough incentives to get a company like Pioneer to drill a marginal field. He said Mr. Foley's inability to answer gives the public a sense of how difficult it is for the committee because it is dealing with hypothetical numbers. Although it has been getting more accurate information, that data has margins of error. 3:59:20 PM MR. FOLEY said he still is not going to answer the question. He appreciates the difficulty of the legislature's task. Pioneer is a for-profit company; Pioneer's task is simple - the legislature has to look after the state's resources and make decisions that are in the best interest of Alaska's citizens. He noted as taxes increase, the investments will wane so the question is how many investments the state is willing to forego. 4:00:31 PM REPRESENTATIVE SEATON said the committee is actually looking at a very unique situation in which someone sanctioned a project that is 30 percent net profit above PPT and went forward. The discussion about the change in ACES involves 2.5 percent. He said he understands Mr. Foley's concern about adding another 2.5 percent but ACES would be 55 percent. He said the project with the 30 percent net profit is not a normal one, but he feels the committee should consider a 2.5 percent increase under ACES on fields that already have the 30 percent net profit share. 4:02:32 PM REPRESENTATIVE JOHNSON pointed out this project was sanctioned under zero taxes with a 30 percent profit. 4:03:00 PM REPRESENTATIVE SEATON questioned whether Representative Johnson is saying Pioneer would be willing to trade PPT for a 30 percent net profits tax. REPRESENTATIVE JOHNSON said he misspoke; his point is it was sanctioned under a zero tax. 4:03:20 PM REPRESENTATIVE FAIRCLOUGH said she recognizes the zero percent but it was followed up by a PPT and the investment credits, which made it even more beneficial. She noted the old leases present an interesting dilemma when considering whether the legislature's actions today will make them more or less economical for development. 4:03:51 PM CHAIR GATTO noted the state does not grant grandfather rights. 4:04:02 PM REPRESENTATIVE FAIRCLOUGH said: It is an additional risk, but it is also another battle that we, as a resource committee, are challenged to make the best decisions in the balance that's [been] spoken of. And I feel obligated to say, well when people use the word partnership around here, we need to be very careful. So, for the record, we don't own anything on the North Slope because I don't want to have to take it down nor be liable for it so this partnership is incentive. If we have a partnership interest, some might think that we own some capital and we don't. We own resource that's in the ground that we are monetizing with incentives. Just for clarification on our partnership, I certainly am not indebting the state to have to pick up those pieces and remove them in that type of a partnership for future liability. It is a partnership in investing in Alaska's future, providing jobs and employment opportunities, providing incentive for development. I just want to be clear for all of us that are using that term that I wouldn't want to hold the state responsible for dismantlement, restoration and such in that type of meaning for the word partnership. So, for the legal record, any future litigations, we don't own a piece of that pipeline, a piece of the property that's up there. We are offering incentive credits for development. Thank you Mr. Chair. 4:05:32 PM CHAIR GATTO noted the legislature set aside 5 cents per barrel for dismantlement, removal, and restoration (DR&R). 4:06:14 PM MR. FOLEY said the next slide [11] is juxtaposed to Chair Gatto's comment about grandfather rights. During the transition period addressed under PPT, Pioneer made $100 million of expenditures. That amounts to $20 million in credits Pioneer will hopefully be able to enjoy when it starts paying PPT taxes. One element of the House version of ACES eliminates about 1/3 of those investment dollars. It would have an effective date of April, 2003, so that any capital spent after that would be eligible for the credit. Between December of 2002 and April of 2003, Pioneer spent about $30 million. It drilled 3 exploration wells that led to the development of Oooguruk. Those investments would be eliminated under the current House CS for ACES. 4:07:56 PM MR. FOLEY said ACES makes a change to progressivity. One fundamental change under consideration by the legislature is to have that based on a gross tax rather than a net tax. As a reminder, he told members a net tax rewards investments and places a higher burden on fields that make a high profit. The opposite applies to a gross tax; it treats an aggressive investor in the same way a harvester is treated. He questioned whether that is the policy the legislature wants to motivate. A gross tax would disproportionately place a burden on a marginal project. He pointed out that viscous oil and West Sak are challenged projects that cannot withstand additional tax burden. He encouraged members to keep the progressivity tax based on a net system. 4:09:27 PM REPRESENTATIVE SEATON asked if a marginal project has not recovered the percentage of net profits to trigger the progressivity tax so that even though the company has not built up a profit margin, whether that be ACES/30 or PPT/40, the progressivity tax is triggered when low profits have been made on a marginal field. 4:10:03 PM MR. FOLEY said the point he is trying to make is that right now, if the tax is based on net, so the trigger point is also based on net that takes into account that all barrels are not created equal. Some barrels on the Slope enjoy a high profit margin while others don't. The progressivity number for a high profit field today is higher than the number calculated for a low profit field. It does help level the playing field. 4:11:03 PM MR. FOLEY progressed to slide 13, which contained his final conclusions. He said Pioneer has been an aggressive investor in Alaska and hopes to continue to be one. To continue to attract capital, Pioneer will need to demonstrate that Alaska has a stable fiscal regime. Pioneer believes that PPT is a very balanced, durable, fair, and equitable program that produces revenues to the state while providing a modest incentive for new exploration. Furthermore, the [PPT] helps marginal fields get over the threshold. The House CS version would eliminate one- third of Pioneer's transitional capital that was invested on Oooguruk. He asked members to avoid any kind of a tax that is attached to the gross. 4:12:32 PM REPRESENTATIVE GUTTENBERG said Mr. Foley highlighted many of committee members' concerns. They want to reach out to the independents and make sure they are not harmed by Alaska's policies. Legislators are trying to get to a point where people look to Alaska and say it's settled down and will be stable for awhile. 4:14:42 PM REPRESENTATIVE EDGMON said Mr. Hanley of Anadarko Petroleum Corporation told members that 64 percent of North Slope reserves were tied to fields of 1 million barrels or less. That was based on USGS prospectivity. He asked whether Mr. Foley thought other independents were watching Pioneer and to talk more about his statement that the North Slope basin will increasingly attract small producers. 4:15:48 PM MR. FOLEY said Dr. van Meurs gave a presentation to the Senate in which he used the term "basin master." Although it has a bit of a negative connotation, he disagrees. He said typically, only the large companies have the courage to go out in the world and find and develop new basins. When they establish that position, they want to maintain and benefit from it. That is what happened on the North Slope and that is not a negative thing. Three companies developed the North Slope; small companies would not have the opportunity to explore the North Slope if it weren't for the existence of the pipeline and big field. He stated there is a natural evolution of a basin; it is dominated in the early years by the investors that took the risk. As time goes on, fewer big opportunities exist. Smaller companies work on smaller projects. He felt some of Alaska's policy needs to be directed at motivating new companies to come spend their investment dollars here. CHAIR GATTO said Mr. Foley used the term, "took all the risk." He asked if any places exist where a company goes in and is completely free to do what it wants without government involvement. 4:18:30 PM MR. FOLEY replied not to his knowledge but that may have been the case 40 years ago. 4:18:45 PM REPRESENTATIVE SEATON questioned whether Mr. Foley had any suggestions to help the legislature find a more streamlined way for small producers to take net operating transferable loss credits and refund those through the Retirement Board at a 92 percent rate. He questioned whether that would have value to Pioneer or whether the current system of credit refunds works well enough. 4:19:45 PM MR. FOLEY said speaking just for Pioneer, the current system works just fine. Pioneer has generated nearly $80 million in capital credits on its Oooguruk project so far. It has sold $25 million to the state at full face value. The rest has been placed at a discounted number that Pioneer is fine with. Having said that, he said it is a relatively thin market for the purchase of credits. Pioneer is able to sell its credits but in large dollar amounts. He can imagine that companies with a smaller number of credits would absolutely welcome an opportunity to sell credits. The type of legislation Representative Seaton suggested would create a floor for that type of market. 4:20:55 PM CHAIR GATTO said it is good to hear that Pioneer got 100 percent value on selling its credits. He furthered: ...I think Representative Seaton is saying here's a good deal - you've got credits, sell them for 92 cents on a dollar, and get that today instead of borrowing money at 85 cents on the dollar to continue exploration. The goal is one more forgiveness of some kind for you so that you can proceed in the same direction you are currently proceeding in and do better than you would ordinarily, or not do it and say 92 cents is okay but we can turn these into something better than that in 6 months and that's our decision. It's one more way to assist. As I said, we're all for independent producers to come in. I think we recognize it's our future as well as anyone recognizes it. When you get down to a certain number of barrels, the biggest guys who have billions of dollars in capital values go somewhere else and the smaller guys say what an opportunity. It's there - we know how much is there and we're more efficient so we can still operate the resource and then we'd like to be here to help in any way we can, including the capital credits. 4:22:38 PM REPRESENTATIVE JOHNSON recalled this issue was discussed in the House Oil and Gas committee. He questioned whether any companies do not buy credits as a function of policy. 4:23:05 PM MR. FOLEY replied he has personal knowledge of two companies that have made attempts to purchase credits. REPRESENTATIVE JOHNSON thought BP had a corporate policy to not buy credits, which thins that market. 4:24:07 PM CHAIR GATTO said this situation is providing a great opportunity in one day to go from the big guy to the little guy and the organization in between. 4:25:28 PM CHAIR GATTO introduced the next speaker. 4:25:46 PM MR. DUDLEY PLATT, a petroleum engineer, told members he has lived in Eagle River for 27 years. He has worked for Arco Alaska, the US Minerals Management Service, the State of Alaska and as an independent consultant. He told members, for the record, that he has numerous clients, one of them being the Department of Revenue. 4:26:48 PM MR. PLATT told members petroleum engineers can get involved in many facets of the oil industry - upstream, transportation, exploration, refining, or shipping. His career began doing reservoir modeling for Arco Alaska in the Kuparuk field. He then went on to field engineering. REPRESENTATIVE SEATON said the committee heard about the ability of TAPS to transport oil and at what level of production it would become problematic for the pumping system. He asked for further information about the new electric pumps and their capacity. 4:26:59 PM MR. PLATT said many numbers have been thrown around over the last 20 years as to the minimum throughput for the TransAlaska Pipeline System. He thinks of that as a mechanical minimum throughput. He recalled hearing referenced testimony today about the fact that an economic limit may be higher than the mechanical limit. However, the fact is that no one knows what that number is. They passed through that minimum on the way up and never had a chance to pass through it on the way down. Various government reports have used a number of 300,000 barrels a day. He has seen other government reports that say 200,000 to 400,000. The range of the new electric pumps is 200,000 barrels a day to 1.1 million barrels a day. They act like a dimmer switch - faster or slower. Any time crude oil is shipped through a very cold place issues arise, pump cavitation being one mentioned earlier. One of the biggest problems is the pumpability. To deal with that, heat is added to the cold viscous material. Chemicals can also be added but that is expensive. With a capital investment and increased operating costs, Alyeska should be able to put lined heaters in to promote the flow. The oil could also be "batched" down the pipeline. His thought on minimum flow is if 300,000 barrels per day is taken as the premise for the minimum throughput, the question is how much would the shippers be willing to spend to instantaneously acquire the leases to explore for crude oil, be a successful bidder, put together an exploratory plan, find oil, successfully delineate that field, do the 4 to 5 year design, construction and engineering to build facilities to produce an oil field at 300,000 barrels a day. 4:27:06 PM MR. PLATT said his arithmetical exercise is to multiply 300,000 barrels per day times 365. At $50 per barrel, the gross revenue is $5.5 billion. For every dollar increase in barrel price, the revenue is increased by $110 million. He said his guess is heat will be added to send the oil down the pipeline. He is sure something will be done; otherwise $5.5 billion in revenue will be lost. The higher the minimum input number, the easier it is to justify some remedy for the perceived problem. 4:27:55 PM REPRESENTATIVE SEATON asked at what point the lower volume becomes problematic for the pumping system. MR. PLATT said when trying to depreciate TAPS for property tax purposes, 200,000 barrels a day was used last year because that was the low end of the range of the pump. 4:33:09 PM REPRESENTATIVE SEATON said the bid specification on the pumps, 200,000 to 1.1 million, is probably an accurate number so that the limitation would be something other than the pumps being able to pump as little as 200,000 barrels a day. MR. PLATT said that is his opinion. 4:33:35 PM REPRESENTATIVE GUTTENBERG said his last job at Alyeska was taking Pump 6 off line. He related that he has talked to other people about the number of pumps taken offline and the risk, regardless of the pumps. He asked whether there is a plan for Alyeska and for the producers to recognize there will be a lower number of barrels going through the pipeline and whether the pump shutdowns are an indication of something else. MR. PLATT said he thought Alyeska is trying to be as efficient as possible by using the most current technology. He doesn't believe Alyeska would do anything to prohibit it from continuing to make the profits it makes by shipping oil. 4:35:06 PM REPRESENTATIVE GUTTENBERG said he heard Mr. Hanley say earlier that when Anadarko considers developing in a remote field, facilities access is an issue. It wouldn't be building its own facilities until it had a find of 400 to 500 million barrels. He said Pioneer is thinking about 100 million barrels. He questioned the possibility of a scenario where oil is found far away that would warrant another facility being built, like Prudhoe Bay. MR. PLATT asked if Representative Guttenberg was speaking to a stand-alone field. REPRESENTATIVE GUTTENBERG said it wouldn't be one field, it would be a cluster of fields, and it would be a cooperative venture to build a facility. 4:37:18 PM MR. PLATT cited some historical numbers: BP developed Badami at a time it thought it could get about 30,000 barrels per day from it. He thought BP believed Badami held about 100 million barrels at that time. The Alpine Field was scheduled to come on line at 60,000 or 70,000 barrels per day with a total recoverable amount of 265 million barrels. That project cost between $1 to 1.3 billion. Forced Oil spent a couple hundred million dollars on the west side of Cook Inlet chasing about 25,000 barrels a day at Redoubt Shoal, which never materialized. He noted that the numbers have to be adjusted up to today's dollars to make sense. Farther west in the NPR-A, FEX hit a discovery but it's too far west. [FEX] believes it is 300 or 400 million barrels, which they claim is not commercial due to the lack of infrastructure. 4:39:10 PM CHAIR GATTO asked if that is the case at $96 per barrel. MR. PLATT said they have been silent over the last couple of weeks. He reiterated that at the higher level, the farther away from existing infrastructure, the greater the hurdle. 4:39:37 PM REPRESENTATIVE SEATON said he heard that high chromium pipe is being used in the "workovers" in Prudhoe and Kuparuk. He asked Mr. Platt if he has any insight on high chromium pipe and what expense it would entail compared to other pipe. MR. PLATT asked if he is referring to drill pipe or the actual casing. REPRESENTATIVE SEATON said the actual production pipe. MR. PLATT said chrome pipe is much more expensive than carbon steel, at least 50 percent more, sometimes double, but it does not rust. 4:40:48 PM REPRESENTATIVE SEATON asked what chromium pipe would enable a company to do in those fields versus steel pipe. MR. PLATT said it would provide comfort and longevity. 4:41:18 PM CHAIR GATTO asked if using chromium is a phenomenal deal if the plan is to use the pipe for the next 40 years. MR. PLATT said that for the long haul, one can either buy cheap or buy quality. He thought that, regardless of the industry, companies would tailor the types of materials and engineering to the planned duration of the project. 4:42:12 PM CHAIR GATTO said these people are making a 100 percent increase in their investment dollar for pipe. He questioned the justification and asked Mr. Platt where he has seen this happen. MR. PLATT said there is a big distinction between a petroleum geologist and a petroleum engineer. He repeated if the planning horizon is a long time, one would plan accordingly. 4:43:08 PM REPRESENTATIVE SEATON asked if one was planning on producing gas and increasing the percentage of CO2 into the well that would normally be done so that the carbonic acid would not affect the wells. 4:43:39 PM MR. PLATT said CO2 is reinjected back into the well for several reasons. First, it is inert so it cannot be burned. Second, it has corrosive properties. Third, it is a wonderful solvent for use in enhanced oil recovery. CHAIR GATTO said someone might buy the privilege of putting CO2 in the ground if carbon caps or taxes are implemented 10 years from now. 4:44:32 PM REPRESENTATIVE GUTTENBERG said there is a lot of heavy oil at Prudhoe. Canadians have made advances in technology to extract oil from the tar sands. He asked if Mr. Platt sees any indication that new technologies are on the horizon. MR. PLATT pointed out that one has to distinguish between heavy oil and viscous oil. Water has an API gravity of 10 and flows easily. Viscous oil is very different - similar to Vaseline. Alaska has incredible resources. BP is trying very hard to commercialize the Ugnu resource. Various technologies can be used - one is called cold heavy oil production with sand and is currently being used in a pilot project. When he has asked about incorporating new technologies into his work, he has been told to wait two or three years. 4:46:49 PM MR. PLATT said attempts to put heat in the ground generate other problems. He is optimistic about the vast resources. With 25 billion barrels at Ugnu, 1 percent would equal another Endicott. He believes if any resource needs help on the North Slope, it is the viscous oils. 4:48:00 PM CHAIR GATTO thanked Mr. Platt and announced a meeting at Friday at 9:00 a.m., during which the committee would be hearing from the Administration and would address amendments. He planned to group amendments with a similar purpose together. The committee would work off of the House Oil and Gas Committee version. REPRESENTATIVE ROSES voiced concern that after a committee substitute is distributed, some members may not understand what the committee did, as happened in a prior committee. He suggested having a work session on Sunday, open to the public, whereby the committee substitute is presented and members have the opportunity to ask questions or make further changes and to make sure everyone on the committee supports it. 4:50:30 PM CHAIR GATTO said the committee will have finished the roundtable by then and hoped that would enable members to understand the committee's resolution on oil and gas taxes. 4:50:43 PM REPRESENTATIVE ROSES likened the situation to what happened in the House State Affairs Standing Committee when a huge pile of amendments was before the committee. He suggested putting a small group of members together who could give a presentation to the committee to ensure members understand the changes. That would also be instrumental in showing the public what and why the committee did and it will help the next committee of referral as well and save time. 4:52:33 PM CHAIR GATTO said he was agreeable to doing that. [HB 2001 was held over.]