ALASKA STATE LEGISLATURE JOINT MEETING HOUSE RESOURCES STANDING COMMITTEE HOUSE SPECIAL COMMITTEE ON ENERGY Anchorage, Alaska June 23, 2009 9:02 a.m. MEMBERS PRESENT HOUSE RESOURCES Representative Craig Johnson, Co-Chair Representative Bryce Edgmon Representative Kurt Olson Representative Paul Seaton (via teleconference) Representative David Guttenberg (via teleconference) Representative Scott Kawasaki Representative Chris Tuck (via teleconference) HOUSE SPECIAL COMMITTEE ON ENERGY Representative Bryce Edgmon, Co-Chair Representative Charisse Millett, Co-Chair Representative Nancy Dahlstrom Representative Jay Ramras Representative Pete Petersen Representative Chris Tuck (via teleconference) MEMBERS ABSENT HOUSE RESOURCES Representative Mark Neuman, Co-Chair Representative Peggy Wilson HOUSE SPECIAL COMMITTEE ON ENERGY Representative Kyle Johansen OTHER LEGISLATORS PRESENT Representative John Coghill Representative Mike Chenault Representative Lindsey Holmes Representative Harry Crawford Representative Bob Buch Representative Bob Herron Representative Mike Kelly (via teleconference) Representative Mike Hawker Representative Bob Lynn COMMITTEE CALENDAR OVERVIEW(S): TRANSCANADA AND EXXONMOBIL PARTNERSHIP REGARDING THE AGIA NATURAL GAS PIPELINE - HEARD PREVIOUS COMMITTEE ACTION No previous action to record WITNESS REGISTER TONY PALMER, Vice President Alaska Business Development TransCanada Alaska Company, LLC (TransCanada) Calgary, Alberta Canada POSITION STATEMENT: Testified as one of the presenters of the overview regarding the natural gas pipeline under the Alaska Gas Inducement Act (AGIA). MARTIN MASSEY, U.S. Joint Interest Manager ExxonMobil Production Company (ExxonMobil) Houston, Texas POSITION STATEMENT: Testified as one of the presenters of the overview regarding the natural gas pipeline under the AGIA. PAT GALVIN, Commissioner Department of Revenue (DOR) Juneau, Alaska POSITION STATEMENT: Provided testimony and answered questions on the Denali Alaska Gas Pipeline project on behalf of DOR. MARTY RUTHERFORD, Deputy Commissioner Department of Natural Resources (DNR) Anchorage, Alaska POSITION STATEMENT: Provided testimony and answered questions on the Denali Alaska Gas Pipeline project on behalf of DOR. BUD FACKRELL, President Denali-The Alaska Gas Pipeline (Denali) Anchorage, Alaska POSITION STATEMENT: Testified and answered questions on the Denali Alaska Gas Pipeline project. CLAIRE FITZPATRICK, Senior Vice President, Chief Financial Officer BP Exploration (Alaska) Inc. (BP) Anchorage, Alaska POSITION STATEMENT: Provided testimony and answered questions. WENDY KING, Director of External Strategies ANS Gas Development Team ConocoPhillips Alaska, Inc. Anchorage, Alaska POSITION STATEMENT: Provided testimony and answered questions. ACTION NARRATIVE 9:02:56 AM CO-CHAIR CRAIG JOHNSON called the joint meeting of the House Resources Standing Committee and the House Special Committee on Energy to order at 9:02 a.m. Present at the call to order from the House Resources Standing Committee were Representatives Johnson, Olson, Seaton (via teleconference), Edgmon, and Kawasaki; Representatives Guttenberg (via teleconference) and Tuck (via teleconference) arrived as the meeting was in progress. Present from the House Special Committee on Energy were Representatives Edgmon, Millet, Dahlstrom, and Peterson; Representatives Ramras and Tuck (via teleconference) arrived as the meeting was in progress. Representatives Coghill, Chenault, Holmes, Crawford, Buch, Herron, Lynn, Kelly (via teleconference), and Hawker were also in attendance. ^Overview(s): TransCanada and ExxonMobil Partnership Regarding the AGIA Natural Gas Pipeline 9:03:28 AM CO-CHAIR JOHNSON announced that the only order of business is a presentation regarding the TransCanada and ExxonMobil partnership as it relates to the Alaska Gasline Inducement Act (AGIA) natural gas pipeline. CO-CHAIR JOHNSON noted that the presenters have confidentiality, proprietary, and regulatory constraints, and asked members to respect those constraints. 9:06:30 AM TONY PALMER, Vice President, Alaska Business Development, TransCanada Alaska Company, LLC (TransCanada), began his PowerPoint presentation by explaining that ExxonMobil Production Company (ExxonMobil) is actively participating in the joint AGIA project; that the joint project team is separate from and independent of ExxonMobil's producing and marketing interests; and that the lead manager for the project, an ExxonMobil employee, will report directly to the management committee, which he himself will chair. 9:08:11 AM MR. PALMER stated that TransCanada and ExxonMobil have reached agreement to work together on TransCanada's Alaska Pipeline Project [slide 2]. There is already immediate ExxonMobil participation and project support via integrated teams working to advance the project. Both companies will jointly advance all aspects of the project - technical, commercial, regulatory, financial, and so forth. ExxonMobil is contributing prior study results and existing right-of-way (ROW) data, thus eliminating the need for TransCanada to reproduce that work. He also said that TransCanada and Foothills Pipe Lines Ltd. remain the Alaska Gasline Inducement Act (AGIA) licensees; that the rights and obligations under the AGIA are unchanged and remain with the licensees; that ExxonMobil is ready to work with the State of Alaska to enable full participation in the AGIA license; and that the project schedule is unchanged; for example, the initial open season is still targeted for completion by July 2010. 9:10:25 AM MR. PALMER said the AGIA project scope is unchanged and includes a gas treatment plant (GTP) and a pipeline from Prudhoe Bay to Alaska delivery points [slide 3]. Liquefied natural gas (LNG) will be provided to Lower 48 or Asian markets via Valdez, or to Lower 48 markets via the Alberta Hub. Furthermore, outside of the AGIA project and thus ineligible for AGIA reimbursement will be the advancement by TransCanada and ExxonMobil of an upstream gas transmission pipeline from Point Thomson to the GTP; that section of pipe will be offered for service to potential customers during the open season. 9:11:26 AM [Not on the official recording, but reconstructed from an alternate recording, was the following short bracketed statement]: MR. PALMER said: [The current alignment between TransCanada and ExxonMobil] is not contingent on any commitments by the state, and we can progress the project independently, if we so elect, using all jointly- developed assets and information. Clearly it's our goal, over time, to develop this project jointly with ExxonMobil to successful completion. In the event that we come apart for any reason, the jointly- developed assets will be on our hands, and we'll be in a position to use them to complete the project. 9:11:51 AM MR. PALMER, on the issue of legislation and regulation, said TransCanada will use the 2004 Alaska Natural Gas Pipeline Act (ANGPA) in Alaska and the Northern Pipeline Act in Canada [slide 4]. TransCanada has increased the up-front spending to $150 million, and this additional front-end spending reflects increased emphasis on early execution and construction planning, additional efforts in regulatory, environmental, and land areas, as well as the size, complexity, and execution challenges of the gas treatment plant (GTP). The legislature has appropriated about $45 million to date for this project, and TransCanada's expectation is that this amount will be sufficient to cover Alaska's share of the project through [this interim]. The development costs will be shared between TransCanada and ExxonMobil, and the two companies will retain the majority interest, with the state's total reimbursement contribution of up to $500 million to remain unchanged. 9:13:12 AM MR. PALMER explained that subsequent to the legislature's approval of issuing the AGIA license to TransCanada, ExxonMobil commenced the discussions and negotiations between Fall 2008 and May 2009 [slide 5]. These negotiations resulted in an agreement between the two corporations. TransCanada advised the state administration of these actions, but did not divulge the nature or details of the negotiations, he said. However, at the point TransCanada met with its board, TransCanada, under AGIA, had an obligation to share the information with the state, and did so in early May, including sharing the details of the structure of the arrangement between TransCanada and ExxonMobil. However, TransCanada did not believe this constituted a project change, which would have required approval by the state's administration. He emphasized that TransCanada did not find the negotiations to constitute a contract change. Subsequently, after six weeks of review the state ultimately agreed that no action was necessary. He recapped the "Bottom Line" on slide 5, such that TransCanada believes that real progress has been made to align the all parties for a successful project. He opined that the combination of these companies brings unrivaled expertise and experience to the project, and all share a common goal, which is realization of an Alaskan pipeline project. MR. PALMER offered to proceed to the more complex topic of the structure of the arrangement between TransCanada and ExxonMobil. 9:15:47 AM CO-CHAIR JOHNSON asked about the assets that ExxonMobil brings to the project, particularly the right-of-way of the Trans- Alaska Pipeline System (TAPS) information, and if the right-of- way costs will be a reimbursable expense. He said he thought the TAPS reimbursable expense has already been paid through tariffs. Thus, he surmised the information is owned by several companies and asked for the arrangement of how that would be shared. Further, he asked for clarification of how the producers could share something that technically belongs to a third party, which is TAPS. He said he did not expect an immediate answer to these questions. MR. PALMER offered to begin to answer the questions, but added that Mr. Massey, ExxonMobil, could also expand on his answer. He explained that the assets would not be reimbursable expenses, but would be contributed to the project. Thus, the Alaska North Slope (ANS) producer's study that ExxonMobil brings to the table will not be reimbursable by AGIA participants. He reminded members that only expenditures after December 5, 2008, are reimbursable under AGIA. He restated that none of the costs that TransCanada has incurred prior to December 5, 2008, are reimbursable. Further, the TAPS information is not reimbursable under the $500 million AGIA legislation. CO-CHAIR JOHNSON acknowledged the distinction for what is reimbursable, but related his understanding that the assets would be an expense to TransCanada. He said he anticipated that these costs would be rolled into the tariffs, which for a project of its size, the $100 million is not significant. However, he understood that the TAPS information has already been paid for in tariffs. He asked whether it would constitute a duplicate cost if the TAPS information is also rolled into the gas tariffs. He realized the administration may need to answer this question as, from inception, the legislature has been advised to contain costs for the pipeline. 9:18:32 AM MARTIN MASSEY, U.S. Joint Interest Manager, ExxonMobil Production Company (ExxonMobil) replied that clearly the TAPS information expense is not reimbursable under AGIA provision. However, the question of whether TAPS information will be valued in the tariff is a question that ExxonMobil cannot yet answer. ExxonMobil will make the case, if there is a case to be made, that TAPS information should be valued. Further, the Federal Energy Regulatory Commission (FERC) will ultimately decide if it is a legitimate expense, and whether the TAPS information has been already been paid. He added that all expenses included in the tariff will need to be qualified by FERC. However, this will be a future decision and the parties have not, as part of this agreement, made any consideration that the TAPS information is a value that must be included in the tariffs. 9:19:46 AM REPRESENTATIVE PETERSEN recalled testimony that TransCanada plans to build a pipeline from Point Thomson to the gas treatment plant (GTP). He asked if the route and pipeline size have been identified. MR. PALMER answered that work is currently underway and will be completed when the rest of the design work is done and that this information will be available for parties next year. While the initial assessment has been done and the route and pipeline size is generally known, it has not specifically been determined. CO-CHAIR MILLETT asked whether the line from Point Thomson to connect to the pipeline is a reimbursable cost through the AGIA process. MR. PALMER answered no. He related that the line was not part of the application process under AGIA so it will not qualify as expenditures and is not reimbursable. CO-CHAIR JOHNSON recalled testimony that the producers would have an option to use the pipeline or the GTP. If producers do not choose to do so, what other options would be available to them. MR. PALMER clarified that he was referring to not currently knowing the location of gas sources from producers or any potential customers. He pointed out that some parties might have a gas source at Point Thomson while others may solely have a supply at Prudhoe Bay. If the gas source is at Point Thomson, and the producers chose to use the main pipeline and the GTP, they would likely select usage of the pipeline. Otherwise, these producers would be in a position to build their own line, he added. CO-CHAIR JOHNSON stated that the line does not concern him since it is a relatively small cost, but the gas- to-liquids (GTL) option does. He inquired as to whether the producers would also have an option to build their own GTL plant. MR. PALMER answered that the pipeline will require pipeline quality gas. Thus, if the gas comes from Prudhoe Bay, it will be necessary to remove the carbon dioxide. In the event the producers elect not to use the plant, the gas would need to be gas that does not require treatment or they must seek an alternative to the proposed GTP, which is always an option for potential customers. In further response to Co-Chair Johnson, Mr. Palmer clarified producers would need to use the proposed GTP plant, build another GTP plant, or transport gas that is pipeline quality gas. 9:22:30 AM MR. PALMER continued. He detailed the "Project Framework" between the two companies listed on slide 6 of his presentation. He stated the objectives are clear - to perform the necessary work to facilitate completion by TransCanada licensees of open seasons in Canada and the U.S. by the July 2010 target date. Additionally, another objective is to continue to pursue the regulatory authorization for pipeline construction. He offered to walk members through the flowchart beginning at the right side [of slide 6]. He stated that TransCanada and ExxonMobil have reached an Interim Project Agreement (IPA) to complete the project work and transfer that project work to the AGIA licensees, which is depicted by an arrow. The AGIA licensees will transfer back the parties' non-voting interest. Thus, TransCanada would retain 100 percent of the voting interest as the AGIA licensee. However, TransCanada's subsidiaries, as well as ExxonMobil, will be earning nonvoting interest. In the event ExxonMobil resolves all issues with the state and ExxonMobil becomes a full participant, the nonvoting interests will be converted into voting interest, and ExxonMobil would become a full participant, or basically a common shareholder of the AGIA licensee. 9:24:47 AM REPRESENTATIVE RAMRAS asked when questions could be directed to the leaseholder. MR. MASSEY explained that the structure is under discussion. Once that is completed, the leaseholder will be better able to answer questions. After the structure discussion, he planned to leave in order to allow TransCanada to provide an update on the specific TransCanada project. Since ExxonMobil is currently becoming a shipper/producer, in that status he is not entitled to any special preference. Thus, ExxonMobil will be party to information at the same time as any other shipper or producer. He offered to answer questions after Mr. Palmer has completed his discussion on the project framework. CO-CHAIR JOHNSON noted that the FERC requirements were discussed and agreed this is an area that will require care be taken. 9:26:10 AM MR. PALMER went on to explain that those AGIA licensees will then determine and submit any qualified expenditures for reimbursement. Once reviewed and approved by the state, reimbursements will be made to the AGIA licensees and will flow through to the ExxonMobil entity. Thus, as the TransCanada and ExxonMobil entities incur the costs, the reimbursement will be shared by the parties. 9:27:03 AM MR. PALMER elaborated that the IPA establishes the basis under which TransCanada and ExxonMobil work together [slide 7]. He identified that the Project Funding Agreements (PFAs) are companion agreements to IPA, and are executed simultaneously with IPA, with a separate PFA for the U.S. and Canada since they are separate licensees. He noted that the PFAs provide a bridge between the TransCanada licensees and IPA parties. The TransCanada licensees maintain the interface with the state and retain AGIA obligations, while the TransCanada licensees maintain sole discretion over the request for reimbursement for qualified expenditures. MR. PALMER related that he already addressed the first bullet on the top of slide 8, a continuation of the project framework, such that TransCanada's licensees will have the right to all work provided to them by IPA parties for purposes of meeting the TransCanada obligation under the AGIA license. He highlighted that this is critical, not only for the project completion, but also under AGIA, and under certain circumstances the state would have the right to take over and will need to have those assets. MR. PALMER continued. He said that all major project components, including regulatory filings and open season contracts will be made or entered into in the name of and on behalf of the AGIA licensees. The AGIA licensees have the right, at all times, to progress the project alone, if they so choose. He added that clearly that is not TransCanada's intent, but they do have a right to all the jointly-developed assets and both parties will retain rights to the project information. The parties have agreed to a reasonable transition period to sole management by TransCanada in the event of a termination. Thus, ExxonMobil could not pull up stakes if it terminated its affiliation, but would need to provide a reasonable transition period for an orderly management of the project. The parties will earn nonvoting interests in the TransCanada licensees upon transfer of the work product, he stated. MR. PALMER continued with the project framework [slide 9]. Once ExxonMobil is a participant in the TransCanada's license, nonvoting interests will convert automatically to voting interests in the licensees. State reimbursements will be distributed in proportion to their participating interests in the IPA. The IPA includes the typical joint venture terms, and in terms of the structure of the management of the project, TransCanada and ExxonMobil have fully integrated teams engaged on the project. 9:29:32 AM CO-CHAIR MILLETT asked for clarification of what it means to have ExxonMobil become a participant in the TransCanada license. MR. PALMER explained that as the legislature is aware, ExxonMobil must resolve some issues with the state before it becomes a full participating party in the AGIA licensees. He stressed that if ExxonMobil resolves its issues, then ExxonMobil will become a voting shareholder in TransCanada's licensees. While ExxonMobil does not currently hold that status, ExxonMobil is earning nonvoting interest which is, in effect, a financial interest rather than a voting interest. However, once the issues are resolved ExxonMobil will convert to a full common shareholder with financial voting interest. 9:30:38 AM CO-CHAIR MILLETT asked for clarification of unresolved issues. MR. MASSEY explained that, first, it is important to note that TransCanada's obligations under AGIA are unchanged with this new relationship. He stated TransCanada is fully committed to meet its AGIA obligations. Secondly, ExxonMobil has come to understand that the state has approved AGIA, that the administration and the legislature represent the preferred process for an Alaskan pipeline project. In order to be successful in the project ExxonMobil must work within that framework. He emphasized that ExxonMobil needs to have predictable and durable fiscal terms as a condition of any project in the world of this magnitude. He restated that ExxonMobil realizes that working through AGIA is the means to achieve the project. The good news is that ExxonMobil is working with TransCanada to progress the project and is willing to work parallel to the state to address the fiscal terms. He offered his hope that ExxonMobil achieves confidence with the technical work done during the open season, and if so, the only remaining issue will be to assess predictable and durable fiscal terms. 9:32:14 AM MR. MASSEY, in response to Co-Chair Millett, reiterated that no conditions were necessary in order to join TransCanada. However, ExxonMobil hopes that by working with TransCanada and the AGIA process, it can address durable and predictable terms, he said. He defined durable and predictable terms as everything in AGIA or not in AGIA that relates to understanding whether the project will be a viable project. In other words, he asked whether ExxonMobil could predict reasonably well what the taxes and the state take will be such that ExxonMobil can make a determination about the viability of the project. He related that if it is in the AGIA and relates to the overall state take and how the state's return might be influenced over time then yes that would be something to discuss with the state. CO-CHAIR MILLETT clarified her interest is in knowing if other issues within the AGIA framework should be addressed for ExxonMobil as a producer or shipper. MR. MASSEY responded that ExxonMobil appreciates what the state would like to achieve under the AGIA process. He opined that working with TransCanada, ExxonMobil can meet the state's goals under AGIA as well as TransCanada and ExxonMobil's needs. He said, "That is our hope and that's what we're going to try to work toward in achieving with our discussions with the state." 9:34:34 AM REPRESENTATIVE RAMRAS remarked that he is glad ExxonMobil is at the table. He questioned whether ten years [of unchanged state taxes in AGIA] would qualify as a definition for durable. MR. MASSEY answered that there is a moral obligation for the ten years in AGIA. He interpreted the AGIA statutes to mean that the state will make an effort to avoid changing the terms within the ten years, but not a guarantee since nothing in AGIA prevents the state from changing the terms within the ten year period. He stated that he likes the dictionary definition of durable, which is lasting and enduring, but whether that translates to ten years, or to a longer period is a matter that ExxonMobil will need to discuss with the state. REPRESENTATIVE RAMRAS surmised that ten years is not good enough, but also that the state may extend terms for a longer period. He related his understanding that ExxonMobil "Mid- stream Gas Investments LLC" is interested in the GTP, while the larger ExxonMobil entity would be willing to talk to the state about the ten-year term contained in AGIA, with perhaps some implied notion that the terms would be extended for a longer period. MR. MASSEY clarified that he was referring to the producer/shipper who would commit the gas to the project. With respect to the issue of the pipeline, he said ExxonMobil and TransCanada hold the same view: that this issue needs to be worked on between the state and the shippers to insure a successful open season. He offered his belief that the 10 year period is not sufficient, but the 35 years previously agreed to was enough. The question remains as to what the terms will be for this pipeline, but the open dialogue continues. 9:37:52 AM REPRESENTATIVE DAHLSTROM asked whether ExxonMobil will have equal voting rights with TransCanada. MR. PALMER explained that in the event ExxonMobil resolves its issues with the state and converts from nonvoting to voting, TransCanada will retain the majority, and ExxonMobil will hold a minority voting interest. 9:38:28 AM CO-CHAIR JOHNSON related his understanding that TransCanada either pre-filed or would ask to pre-file with FERC. He asked whether FERC will require TransCanada to modify its application. MR. PALMER explained that TransCanada pre-filed with FERC at the end of April 2009. That pre-file application was made under TransCanada's name, which is the entity that will move forward, although ExxonMobil will contribute to the work jointly with TransCanada. He said that TransCanada licensees will still pursue all the regulatory applications and contracts with customers in their own name. He clarified that applications and contracts would be pursued in the name of the AGIA licensees and no issue has arisen with the FERC. MR. PALMER continued. He stated that approximately 70 people are currently working on fully integrated teams staffed by TransCanada and ExxonMobil, with ExxonMobil as the IPA lead and TransCanada as the sub-IPA lead for the Canadian portion of the project. He related that TransCanada is primarily responsible through the open season for the overall pipeline and compression work, while ExxonMobil will be responsible for the GTP. Thus, the bulk of TransCanada's employees will work on the pipeline, but will be supplemented with ExxonMobil, and conversely ExxonMobil employees will primarily handle the GTP, supplemented by TransCanada's staff. He identified Paul Pike as the IPA lead who will report to the management committee, currently chaired by him. The management committee will have representatives from ExxonMobil and TransCanada, and project costs will be jointly funded based on the parties' proportionate shares. 9:40:56 AM MR. PALMER, stated that TransCanada believes this addition represents real progress to align all essential parties for a successful project [slide 10]. Last summer TransCanada was successful in obtaining the legislature's approval for the license issued on December 5, 2008. He recalled that ExxonMobil testified that joining TransCanada supports the progress of the project under AGIA and their willingness to become a full participant in those licensees. He remarked that in the event discussions occur between ExxonMobil and the state, that TransCanada will not be a party to the discussions, but will remain an interested observer. 9:41:53 AM CO-CHAIR MILLETT recalled that immediately after the AGIA license was signed, TransCanada's chief executive officer (CEO) stated that nothing moves forward unless ExxonMobil is happy. She asked for clarification of what that statement would mean. MR. PALMER interpreted that what TransCanada's CEO meant by the statement is that during any major pipeline project some alignment must occur between the principal producers in the basin. Potential shippers must be aligned in some fashion or there will not be a successful project. He recalled his frequent testimony that TransCanada needs customer contracts and regulatory approval. Thus, what TransCanada's CEO recognized in his statement is that ExxonMobil is the largest holder of discovered reserves on the North Slope of Alaska. Therefore, TransCanada needs alignment with ExxonMobil, as well as with the other two producers. TransCanada seeks that approval. He stated that while he would not speak to what brought ExxonMobil to the table, TransCanada is very pleased. TransCanada is in the position of providing a credible cost estimate for third party producers because of its alignment with ExxonMobil. He noted that TransCanada does not profess to be an expert with GTPs. However, with ExxonMobil on board, TransCanada has the strongest player in the GTP business worldwide, which adds to the project. Further, with ExxonMobil jointly working on the pipeline, TransCanada hopes that the revised cost estimate will also satisfy other similarly situated producers. He suggested that Mr. Massey may wish to address the committee on the matter, but from the TransCanada perspective the alignment with ExxonMobil is satisfactory. 9:44:15 AM MR. MASSEY related that ExxonMobil evaluated the full range of options of how to progress the projects, which included consideration of joining Denali, joining TransCanada, considering itself alone, or postponing and showing up during an open season. ExxonMobil analyzed what could move the project forward and the success in bringing all the parties together pointed to TransCanada via AGIA as the best opportunity for success. 9:45:33 AM CO-CHAIR JOHNSON asked about the statement that TransCanada would not be involved in the negotiation of physical terms. He opined that one major hurdle remaining is the type of structure with the state that will insure durable fiscal policy. He asked how TransCanada's stockholders could allow TransCanada to "sit on the sideline" during that process. MR. PALMER answered that TransCanada's stockholders expect TransCanada to keep its word. Further, TransCanada has agreed with the state to remain outside negotiations. He said that TransCanada's CEO has repeated this agreement on numerous occasions, most recently to the governor of Alaska the day prior to the announcement of the transaction. 9:46:27 AM MR. PALMER outlined the benefits of alignment with ExxonMobil [slide 10]. He related that TransCanada has over 2,000 pipeline employees and currently transports 20 percent of North American gas daily. He detailed recent TransCanada activities, including that TransCanada is a 100 percent owner of a $12 billion Keystone Project underway that will take 4.5 years from announcement to completion, will span 4,000 miles, and traverse 13 states. Secondly, TransCanada is involved in building a $2 billion project, to move gas from western Alberta to eastern Alberta, at the existing Meikle River Compressor Station. The North Central Corridor Project, comprised of a 42-inch pipeline, is currently under construction, with the first phase completed last winter and the second phase next winter. Another project, Bison, will move gas out of the Rockies connecting to TransCanada's pipeline in the Midwest. Additionally, TransCanada was awarded the right to build the Guadalajara Pipeline in Mexico. MR. PALMER described further benefits of alignment with ExxonMobil [slide 11]. He related that the financial and project management strengths of ExxonMobil are generally recognized. ExxonMobil is the recognized industry leader in execution of large complex projects, has substantial financial resources, and is the largest holder of discovered Alaska North Slope natural gas resources. Further, ExxonMobil has the expertise and technology for GTPs as well as pipeline systems, has been in Alaska for decades, brings to the project previously described assets, as well as the commitment to the timely development of Alaska's gas resources. This combination brings unparalleled experience in project execution. ExxonMobil's focus is on costs and schedule. TransCanada and ExxonMobil share a common philosophy in that they are jointly committed to advance the project, need the full support of the state, the U.S. and Canada government, North Slope producers, and other interested parties to fulfill the project. Yet, TransCanada recognizes that to succeed in a project of this scale requires alignment with government. He highlighted TransCanada has previously succeeded in these types of projects. However, commercial ventures cannot succeed alone; they require alignment. TransCanada is ready to move forward with other parties when they are ready to do so MR. PALMER stated that Mr. Massey will excuse himself at this time if there are no further questions for him. 9:50:47 AM CO-CHAIR JOHNSON recalled prior testimony that ExxonMobil is the largest holder of gas reserves on the North Slope, which he assumes also include Point Thomson. With respect to Point Thomson, he asked whether it was part of the discussion during ExxonMobil's negotiations and whether the state was involved in discussions regarding the settlement of Point Thomson. He asked Mr. Massey to state the facts for the record. MR. MASSEY answered there were no commitments from the state to sell Point Thomson in order for ExxonMobil to join TransCanada. He related that with respect to Point Thomson, the state continues to have technical questions about the proposed project. The state is currently going through its due diligence process, is reviewing work that has been accomplished, which has led ExxonMobil to believe that Point Thomson is the right project to propose. He said he hopes the state will conclude and agree that ExxonMobil has taken the right approach. Once that process is completed, ExxonMobil can hold good settlement discussions that will result in an outcome that both parties are comfortable with to allow them to move together on Point Thomson. Point Thomson as critically important to the gas pipeline as it represents 25 percent of the gas resource. Thus, he offered his belief that it is important to resolve this matter and move forward. CO-CHAIR JOHNSON asked if it would be a fair statement to say that without Point Thomson the probability of a pipeline is diminished considerably. MR. MASSEY answered yes. He reiterated that Point Thomson represents 25 percent of the gas resource, and said that it would be a much different project without Point Thomson. However, that does not necessarily mean that Point Thomson must be available on the "first" day because it is possible to "flow" Prudhoe Bay harder and bring Point Thomson in later. Many permutations can be considered for the overall project success. Ultimately, Point Thomson gas is needed in order for the pipeline to be a go, he said. 9:53:38 AM MR. MASSEY, in response to Co-Chair Johnson, responded that if Prudhoe Bay is the only field the risk is higher, but if Point Thomson is available then two fields are involved, and it would reduce the risk of the big financial commitment to underpin the pipeline project. Thus, it is important for ExxonMobil to know of the gas commitment. In further response to Co-Chair Johnson, Mr. Massey stated that ExxonMobil is optimistic the issues related to Point Thomson will be resolved before the initial open season. However, if that is not the case, then ExxonMobil will reevaluate the project at that time. He opined that it is difficult to speculate any outcome at this time. 9:55:22 AM MR. MASSEY, in response to Representative Olson, confirmed that the state did not make any assurances related to Point Thomson in order for ExxonMobil to join TransCanada. He reaffirmed there were no linkages of any kind. CO-CHAIR JOHNSON asked whether ExxonMobil would still be involved in the pipeline project had it not obtained the leases back. MR. MASSEY answered yes. 9:57:20 AM MR. PALMER highlighted the alternatives between delivery points in Alaska, and Alberta Hub enroute the Lower 48 [maps on slide 12]. He reviewed the project schedule [slide 13], pointing out that the FERC pre-filing request was met at the end of April, some two years earlier than originally contemplated in the AGIA schedule. The FERC indicated it preferred TransCanada to pre- file, TransCanada held comprehensive discussions with FERC, reached an agreement, and the pre-filed application was accepted on May 1, 2009. He noted the only other change to the timeline shown is the addition of a Canadian timeline. In response to Representative Ramras, said that TransCanada's preference and goal is for customers to commit gas in the initial open season. However, it would not be unusual for potential customers to condition their bid, which he characterized as often the norm. While is possible that fiscal issues may remain an issue for ExxonMobil or other potential shippers, and may be set out in their conditions, this is clearly nothing that TransCanada can resolve. He related that if a resolution was not forthcoming after July 2010, TransCanada still has an obligation to continue to solicit the market every two years. MR. PALMER recalled past testimony and then addressed one of the strengths of the AGIA process. He indicated that TransCanada was initially not amenable to continue regulatory approval subsequent to a failed open season, that TransCanada agreed it would continue to seek customers, but would not spend the hundreds of millions of dollars for regulatory approval without committed customers. However, AGIA was passed with the obligation to continue regulatory approval and the state agreed to a financial contribution to the regulatory costs and so will share those costs. MR. PALMER addressed the timing of the project, such that in the event of an unsuccessful open season in the summer of 2010, that TransCanada will continue to pursue customers and the regulatory approvals as it is required to do under AGIA. If resolution is reached on fiscal matters in 2011 and customers are willing to commit, then TransCanada would not need to wait two years and a delay would not jeopardize the schedule. However, the schedule would be jeopardized if regulatory approval is given, but customers have not committed since regulatory approvals and customers are both required. 10:02:20 AM MR. PALMER, in response to Co-Chair Millet, explained that TransCanada reached an agreement with FERC on the information that must be submitted as part of the FERC pre-file, as well as the timing of submittal of additional information. This became necessary since TransCanada would normally pre-file post open season and would have more information to submit to FERC. He restated that TransCanada and FERC agreed on the timing of submitting information to FERC. 10:03:32 AM MR. PALMER, in response to Co-Chair Johnson, responded that to determine whether it is considered a failed open season or not would depend upon the conditions set by potential shippers during the open season. It is not unusual for customers to have conditions for regulatory approvals and sometimes for fiscal resolution, but those types of conditions cannot be resolved by TransCanada. Thus, the outcome would depend on what conditions potential shippers required. TransCanada would consider it a failed open season if, after the July 2010 date, it cannot readily resolve any of the conditions set. In further response to Co-Chair Johnson, Mr. Palmer answered that so long as the standard terms are met, and the only condition that customers place on their commitment of gas is FERC approval, TransCanada would determine it to be a successful open season. CO-CHAIR JOHNSON clarified that he was referring to the state fiscal concerns. MR. PALMER agreed that at some point unresolved fiscal concerns would result in an unsuccessful open season. MR. PALMER, in response to Co-Chair Johnson, outlined that in the event the state fiscal issues are not resolved, TransCanada would take the same actions to prepare its October 2012 FERC filing. However, he emphasized that TransCanada would have a much stronger FERC filing if it has full gas commitments without state fiscal concerns by October 2012. TransCanada will pursue FERC regulatory approvals whether it has succeeded or not during the initial open season. However, the application would be commercially weaker if it does not have customer commitments. He reiterated that if customers are ready to commit before 2012, "great." TransCanada will also hold a second solicitation during the summer of 2012. He said he hopes whatever issues potential customers may have would be resolved by then. Again, TransCanada is not in control of those issues, he stated. 10:07:22 AM MR. PALMER addressed matters that arose during his testimony in 2008. He reminded members that last year TransCanada started a ten-year schedule; thus, TransCanada is one year into that process. He highlighted accomplishments since June 2008 [slides 14 and 15]: TransCanada's application was reviewed, the AGIA license was approved by the legislature, the AGIA license was issued on December 5, 2008, and an AGIA coordinator was appointed. TransCanada has achieved real progress toward a broader alignment with ExxonMobil. TransCanada has performed engineering, environmental, and limited field work towards the capital cost estimate with significant Alaskan participation. The addition of ExxonMobil's personnel broadens the expertise and experience of TransCanada's project team, and enhances credibility with potential customers and the likelihood of success. TransCanada is currently holding discussions with potential customers for deliveries in Alaska and to Lower 48 markets via the Alberta Hub, and is drafting commercial terms for the initial open season. MR. PALMER, in regard to the liquefied natural gas (LNG) project component, stated that TransCanada has moved forward with cost estimation and drafting of commercial terms, has been holding discussions with potential customers which resulted in modifications to a 3.0 billion cubic feet per day (Bcf/d) design. Potential customers can now select Valdez as delivery point in an initial open season. He opined that TransCanada does not believe sufficient gas will be committed in the initial open season for 4.5 Bcf/d to the Alberta Hub and 3.0 Bcf/d to Valdez. It will be either one or the other, but not both, he said. MR. PALMER continued with the project accomplishments. He addressed the Canadian regulatory accomplishments listed on slide 16, including that ExxonMobil reviewed and endorsed the Northern Pipeline Agency (NPA) as the Canadian regulatory model for the project, re-staffing of the NPA is underway, the NPA is coordinating the project within the Canadian government with Canadian provinces, and multi-department meetings have been held with federal agencies, the British Columbia and Yukon governments. He restated that on the U.S. regulatory side, TransCanada pre-filed with FERC two years earlier than the approved AGIA schedule, is progressing communications with FERC project staff, has held multi-agency meetings, and continues to hold ongoing discussions with federal and state coordinating agencies. 10:11:42 AM MR. PALMER, in response to Co-Chair Johnson, answered that TransCanada will bear the full cost of the NPA, that the re- staffing will end up as part of the tariff, which is the usual and customary process. If there is an unsuccessful project, TransCanada's shareholders would bear the costs. In further response to Co-Chair Johnson, Mr. Palmer responded that specific legislation is limited to this project and not for any other project. He added that the pre-build costs are charged to the western Canadian producers, but for the northern section the costs are as previously described. He elaborated that there is not any current activity with the NPA since they are not approving facilities, but in the event that the NPA approves facilities the pre-build costs would be charged. 10:13:48 AM MR. PALMER continued his review of project accomplishments [slide 17]. TransCanada has contacted all Canadian right-of-way First Nations and offered to negotiate first participation agreements, he said. Five of eight Yukon First Nations parties are currently ready to hold discussions, and TransCanada has held negotiations with some parties. In response to, Co-Chair Johnson, Mr. Palmer acknowledged that negotiations have been held with more than one party, and while he is not certain whether that number has now increased to two or three, it is not as high as five. MR. PALMER, in response to Representative Olson, answered that with respect to British Columbia's First Nations, TransCanada has made the same offer. He related that Fort Nelson on south is an active project area and is being processed on an integrated basis as TransCanada proposes pipelines into those sections of British Columbia. 10:16:07 AM MR. PALMER updated the committee on the partnership with other subsidiaries of TransCanada, stating that Alaska Northwest Natural Gas Transportation Company (ANNGTC) might cause delays. There are partnership agreements related to efforts in the late 1970s and 1980s to build a gas pipeline from the North Slope to markets in the Lower 48. He recalled extensive testimony last year that ANNGTC would not be an issue, but since some parties expressed concern, TransCanada took additional actions: The ANNGTC partnership is currently in dissolution, and the conditional FERC certificate, federal right-of-way, and water permits have all been returned. He advised that TransCanada did not own six withdrawn partners, but has in hand full releases from all but one of the six withdrawn partners. In response to Co-Chair Johnson, Mr. Palmer emphasized that all of the parties were substantial and significant commercial parties. He said he is not at liberty to disclose any names due to ongoing negotiations. 10:17:46 AM MR. PALMER recalled identifying a significant upside by commercially aligning the section of the project from Fort Nelson to the Alberta border with TransCanada's Alberta Hub system. He elaborated that it would physically be the same pipeline, but commercially, it would be averaged with the Alberta system. This pipeline represents about a 200 mile section of pipeline and, if successful, would result in an 18 cent per thousand thousand British thermal units (MMBTUs) benefit to the Alaska customers or about $300 million per year. This project still requires regulatory approval, but TransCanada has made significant progress. He pointed out that the Alberta section of the pipeline system has been provincially regulated for 50 years and prohibited from physically or commercially crossing any borders. One significant TransCanada accomplishment is an application a year ago with the National Energy Board (NEB) and the Canadian government, with Canadian approval for TransCanada's Alberta System. Additionally, TransCanada has proposed two small pipelines into northern British Columbia - Groundbirch and Horn River - to move shale gas. If successful, it will be excellent precedent for the Alaska project, he predicted. 10:21:10 AM MR. PALMER, in response to Representative Ramras, related that TransCanada's Anchorage office answered his letter on June 17, 2009. He recalled the questions about the differences between the proven reserves and total reserves. He explained that Horn River is in the early stages of development as are many other shale reserves in North America, but proven reserves are not clearly defined today. He acknowledged differences in Canadian and U.S. terminology for "gas in place". Canada's "gas in place" implies the total reserves including proven, probable, potential, and speculative. He estimated a range of 100 - 400 trillion cubic feet (tcf) for Horn River reserves. The recoverable resource is expected to be 20 - 50 tcf, which includes proven, probable, and potential, but not speculative gas reserves. It is probable that the 20 - 50 tcf will be recovered, but the speculative reserve will not likely happen, although it is too soon to know. He estimated that 20 to 50 tcf of gas will likely be produced over the life of the basin. In response to Co-Chair Johnson, Mr. Palmer clarified the effect of these basins on TransCanada's proposed Alaska pipeline under AGIA. If 20 to 50 tcf is produced overall, Western Canada's production, which has recently declined, would be enhanced He emphasized that these projects must compete in the marketplace, which helps illustrate why TransCanada is so focused on cost and schedule. The proposed AGIA pipeline project will be a competitive project if TransCanada can contain its production costs to below $3. He underscored that every project estimate he has reviewed shows that ten years from now the projected cost of the proposed pipeline will be at $6 - $8 or higher. Thus, if costs can be held to $3, TransCanada's AGIA pipeline project will certainly be competitive. However, dramatic cost increases or significant price reductions will impact this project. It does not change TransCanada's commitment, but reinforces that costs must be controlled. 10:25:09 AM MR. PALMER pointed out that developing a pipeline is very different from developing shale gas since the bulk of the cost is for exploration and development, which has always been the case for Alberta gas, relative to Lower 48 gas, since its gas is farthest from market. Thus, TransCanada has had to focus on keeping pipeline costs low. Alaska is no different except it is even farther from the markets. If Alaska gas can be held to a $3 range in 9 years time then it will be competitive with other sources of gas. He said he would be surprised if shale gas price stays at $2 forever, but shale gas prices affect the economics of every project, including the proposed TransCanada AGIA pipeline project. Current total gas produced in North America is about 75 Bcf per day. He conveyed that without drilling any wells in North America the natural depletion is still 10 to 15 Bcf per day, which is huge. Producers will drill when it is profitable to do so and producers believe that over a sustained period they can make a profit, they will continue to drill either to maintain or grow production. He reiterated that he did not believe that $2 or $3 is sustainable, unless a massive amount of gas is discovered. He pointed out the discrepancy between oil prices in Alaska in the $60 - $70 range and the world market. If natural gas prices in North America are vastly different on a worldwide scale, he predicted that parties are likely to commit to the proposed TransCanada AGIA project. He doubted that over time the gas to oil ratio of 17, 18, or 20, similar to today's ratio will be maintained. However, if the gas to oil ratio does prevail, producers can make significant money shipping gas off this continent to other countries. MR. PALMER, in response to Representative Ramras, indicated that TransCanada currently employs two Alaskans. More importantly, TransCanada employed 84 Alaskans last year, which continues to ramp up. TransCanada will leverage TransCanada and ExxonMobil employees' skills and power to contain costs and advance the project competitively worldwide. In further response to Representative Ramras, Mr. Palmer explained that it is not relevant as to the duties of the two employees, but TransCanada plans to ramp up the number of Alaskan employees as the project advances. TransCanada currently provides lower project costs by using in-house expertise. REPRESENTATIVE RAMRAS pressed for the duties of TransCanada's Alaska employees. MR. PALMER replied that TransCanada currently has an office manager and an external affairs position in Alaska. TransCanada normally hires contract employees during the development stage of the project. MR. PALMER, in response to Co-Chair Millett, answered that subsequent to the AGIA application, TransCanada has not been inactive in Washington, D.C., that TransCanada provided comments to the U.S. Senate Energy committee when it considered loan guarantees being increased. He acknowledged that during the U.S. national elections and transition period, TransCanada has been inactive and will have to reassess with ExxonMobil how the structure will move forward. CO-CHAIR MILLETT asked for a summary of TransCanada's comments before the U.S. Senate Energy Committee. MR. PALMER answered that TransCanada supported the proposal to increase the loan guarantee from $18 billion to $30 billion, and to provide access to the federal financing bank. If access was in place, it would potentially lower the cost of borrowing for the project. He noted a 1 percent change in the interest rate would lower the toll by $.09, or $150 million per year for the project. He said he was not necessarily suggesting the change would be 1 percent, but used it to provide a point of reference. It is also an indication of why the loan guarantee is important for TransCanada's AGIA pipeline project and why TransCanada supports any moves by Congress to enhance it. In further response to Co-Chair Millett, Mr. Palmer related that TransCanada supported the initiative when it passed from the U.S. Senate Energy Committee, that the proposal must still go to the full Senate, and if it does pass, that it will substantially enhance the loan guarantee. 10:33:36 AM MR. PALMER, continuing with TransCanada's accomplishments, turned to slide 18, and explained that FERC also requires an in- state gas study, which was awarded to Northern Economics, and whose subcontractor is the Institute of Social and Economic Research (ISER). This work is underway and will assist to identify the in-state offtake locations. TransCanada's Anchorage office opened in early 2009, some 18 months in advance of its schedule, with a planned expansion later this summer as the project ramps up. MR. PALMER, in response to Co-Chair Johnson, offered his understanding that the in-state gas study would be filed with FERC and thus be made public. MR. PALMER reviewed the next steps through open season to July 2010 [slide 19]. He stated that this period, TransCanada will: complete the capital cost estimate by the end of the first quarter (Q1) 2010, including engineering, environmental, and field work; finalize commercial terms and precedent agreements; advance Canadian First Nations participation agreements, as well as the Fort Nelson issue. TransCanada will complete the in- state gas study later this year and will continue to have ongoing discussions with potential customers. TransCanada prefers a dialogue between the state and ExxonMobil to achieve a successful initial open season. Additionally, TransCanada will file an open season package with FERC and hope to obtain approval. He concluded his presentation by stating that TransCanada will conduct the open season and hope for success during the 13 month period. 10:36:35 AM MR. PALMER, in response to Co-Chair Johnson, answered that the TAPS study will not shorten TransCanada's timeframe to complete the open season. He explained that TransCanada's other critical path items need completion prior to the open season due to the advances necessary in many areas. He pointed out that the open season packet submission date is the end of January 2010, leaving the company with seven months to complete all the necessary work. In further response to Co-Chair Johnson, Mr. Palmer related that time is money but work is also money, too. While the study will reduce the amount of work, it will not shorten the timeframe to conclude the open season. He offered that two components are replacement of work and delay. To date, TransCanada and ExxonMobil have not put a value on the TAPS study, nor sought reimbursement, although TransCanada will ultimately need to provide a value for FERC, who will judge the value. 10:39:27 AM CO-CHAIR MILLETT asked whether TransCanada sees the link between fiscal stability, the gas tax regime in the state, to a successful open season. MR. PALMER responded that in the past few years potential customers related that they perceive a link and would need resolution on the fiscal stability issues. However, he is not familiar with the details and the discussions are between the producers, the administration, and the legislature. In further response to Co-Chair Millett, Mr. Palmer answered that pipeline companies seek successful open seasons and will control what they can to meet their goals of holding them. In the event that potential customers have other issues to resolve with government entities, pipeline companies have no area of influence, but will work to encourage resolution of the issues. 10:41:15 AM CO-CHAIR EDGMON recalled the AGIA vote, and an understanding that AGIA was awarded to an independent third party. Today, the context is different, in terms of alignment between the independent third party and one of the leaseholders. He then posed a scenario in which ExxonMobil would earn full voting rights with TransCanada and resolve its issues with the state. He presumed in the scenario that ExxonMobil would then seek different fiscal terms from the legislature than the AGIA license envisioned, as well as changes to the rolled in rates and expansion terms. He inquired as to whether any scenario exists in which the $500 million state contribution would be negotiable as part of the tax regime discussions, since TransCanada's partner is the largest corporation in the world. 10:44:01 AM MR. PALMER answered that the AGIA terms were established for any party to bid, with terms similar to those that an independent pipeline would supply to potential customers. At that time the state did not know the identity of the bidders, and whether a bidder would be TransCanada or perhaps all three major producers. The terms were set to satisfy the state regardless of the owner's identity. The outcome: TransCanada prevailed in the AGIA award. He offered that TransCanada committed to the AGIA terms, which have been reaffirmed during its alignment with ExxonMobil. He pointed out that part of the difficulty within TransCanada during the AGIA process was the obligation to go beyond an unsuccessful open season. However, the state's financial contribution of $500 million helped resolve that issue for TransCanada. He recapped that the contribution is excluded from the rate base, will lower the state's tolls, will result in a higher netback to the state, and will increase state revenues so long as the project succeeds. He acknowledged that while the state risks its $500 million, TransCanada's shareholders also face risks. In the event that TransCanada has a successful open season and has rock solid commitments for 4.5 Bcf per day, there is no question the value of the state's $500 million investment would decrease. However, TransCanada has not changed its commitment to the project since AGIA. The AGIA obligation rests with TransCanada, and he surmised that AGIA contemplated that at some point TransCanada would be successful in attracting customers. Currently, TransCanada continues to seek customers. He recalled testimony last year by producers that indicated TransCanada's cost estimate would not be credible. He opined that it will be difficult to argue that when TransCanada is working with ExxonMobil. He acknowledged TransCanada does not yet have gas commitments. If TransCanada attains them in 12 or 13 months, the state's investment has less value to the pipeline, but it absolutely has value to TransCanada today, he said. MR. PALMER summarized his response, which is that he cannot give a definitive answer except to restate TransCanada remains committed to its AGIA obligations, the AGIA obligations contemplated terms that are similar to those for an independent pipeline, the winner happened to be TransCanada, and TransCanada will provide the service it is obliged to provide. 10:48:06 AM CO-CHAIR JOHNSON summarized Mr. Palmer's response, such that TransCanada is committed to the terms of the AGIA agreement and expects the same commitment from the legislature. Thus, he suggested that the answer to Representative Edgmon's question is that the state's $500 million is not on the table, will still be available even if the initial open season is successful, and is committed regardless of who partners with TransCanada. He asked Mr. Palmer if he had any issues with the response. MR. PALMER answered no. The committee took an at-ease from 10:49 a.m. to 11:00 a.m. 11:01:05 AM PAT GALVIN, Commissioner, Department of Revenue (DOR), explained that the state's role was to review the agreement between TransCanada and ExxonMobil and determine if the new relationship required additional approval under AGIA, specifically with respect to Section 210 of the Act, which pertains to modifications of the AGIA license. The state team was provided with all the documents associated with this new relationship, including the interim project agreement (IPA), the project funding agreement (PFA), and all the ancillary documents. The DOR brought together members of the state team, and also outside consultants to review the commercial, technical, and legal aspects of the proposed project in order to provide guidance to determine if this relationship modifies the state's interest under the AGIA license. Through that process the DOR sought and received oral and written clarifications from TransCanada and ExxonMobil with respect to the agreements to better understand the relationship. Ultimately, DOR determined that there was no diminishment of the state's rights under the AGIA license as a result of the new relationship with ExxonMobil, and that TransCanada retains all the obligations under the AGIA license and has structured this agreement with ExxonMobil to preserve its opportunity and right to respond to the state's requirements under AGIA. COMMISSIONER GALVIN related that the state's final conclusion is that no action is necessary by the state regarding the alignment with respect to AGIA. He offered that the state is excited about this development, that alignment is precisely what AGIA intended to provide and facilitate, and that ExxonMobil brings tremendous value to this project. The administration has concluded that from the state's perspective this alignment is very good for the project, and the administration looks forward to further alignments as the project proceeds. 11:05:10 AM COMMISSIONER GALVIN, in response to Representative Kawasaki, answered that no discussions were held with TransCanada to change AGIA. In further response to Representative Kawasaki, he stated that the administration also did not hold discussions about making changes to AGIA in the upcoming legislative session. He related that the representations made throughout the state's discussions are embodied in TransCanada's testimony. Further, the state will continue to pursue a durable system. However, the state holds firm to its position which is that the state currently provides a durable and economic fiscal system. Inducements in AGIA allow the shippers to take advantage of the ten year period, with respect to taxes. The royalty provisions provided within AGIA would extend the length of the leases, which are not limited to ten years. Again, there were not any overtures or discussions held during this period with regard to changes to AGIA. 11:07:53 AM REPRESENTATIVE RAMRAS asked what the administration is doing to modify royalties to satisfy ExxonMobil's concern about a financial stable tax regime. COMMISSIONER GALVIN replied it would be an overstatement to say that the administration intends to satisfy ExxonMobil's demands via royalties. The administration is holding discussions with regard to establishing the upstream royalty provisions available under AGIA. The state is implementing the terms of AGIA in order to put in place an opportunity for shippers that make a commitment at the initial open season to enjoy a more favorable methodology with regard to valuing the gas, as well as enjoy modifications to the state's rights to switch between "royalty- in-value royalty-in-kind options." Those terms are not viewed as a vehicle for satisfying the producers' desires, but rather are seen as clarification and implementation of the terms of AGIA, and to establish the methodology legislation process. 11:10:02 AM REPRESENTATIVE RAMRAS described royalty-in-kind (RIK) or royalty-in-value (RIV) and suggested Commissioner Galvin elaborate on the definitions. He asked if the administration is contemplating relaxing the royalties' regime. 11:11:10 AM COMMISSIONER GALVIN explained the oil and gas royalty revenue process. The royalty revenue the state receives represents the state's benefit for owning the resource and leasing the right to explore and develop it to companies. The terms of these leases establish contractual relationships between the parties and the state with respect to the state's royalty share of the gas. This is how any other owners of oil and gas resources would establish their royalty rights, and the state has done so with its leases. In most instances in the North Slope, a 12.5 percent rate is the norm; a 12.5 percent ownership of the oil and gas that is produced. The state has the option to either take possession of the oil and gas at the wellhead or be responsible for the delivery and sale at the market. Or the state can allow the producer to bring the oil and gas to market and the state receives its share via that transaction. The AGIA provides an opportunity to clarify within the royalty structure the determination of the value of the gas. For example, under the oil system, the lease establishes a value, referred to as the higher up, that the state is not bound by the best price a leaseholder may achieve in the market. Instead, the leaseholder remits the royalty based on the highest value that is received by any of the leaseholders within a particular pool; the state receives the highest value among any of its competitors. Thus, the state wants to protect value, and when the state receives a royalty payment, it verifies the payment everyone else received and performs a "true-up" at the end, such that if someone else received more, the state can collect the value from the leaseholders. Companies do not like that as it provides uncertainty; they make a good faith sale, and after the fact must pay the state additional money as the result of someone else receiving a better price. COMMISSIONER GALVIN noted that with the gas market, the state will offer in AGIA to create some methodology to establish the value different from the "higher up" process. Under AGIA, the state will create a formula based upon prices that will provide greater predictability for the companies in terms of what the royalties will be based upon. The state views these changes as a value to the producers; as an inducement to producers to commit their gas to the open season. Additionally, the state can provide more predictability to producers with respect to the RIK and RIV. In most instances the state has the right to switch between with a relatively short notice of six months, or so, but this unpredictability has been problematic for producers, who must take firm commitments. Thus, one time the shipper may ship a volume of gas and the state request that they ship more gas, or the state may inform the shipper that six months from now, the state will ship some of the gas and the shipper will have less. Thus, the state shrinking its options with respect to switching and providing more certainty represents value to shippers. He recapped that those are the two things on the table in terms of the state evaluating royalties on gas as the open season approaches: what is the methodology for establishing the value under royalties and what is the methodology for switching between RIK and RIV. 11:15:56 AM COMMISSIONER GALVIN, in response to Representative Ramras explained that the state considers its current tax system sufficient to provide an economic project for all participants. If the producers provide the state with information that demonstrates changes are necessary, then the state would be willing to consider changes. He characterized the premise of the state attempting to satisfy producers through royalties as a faulty premise. He suggested that the state fiscal system, royalty and tax, is sufficient at this time; that the durability is sufficient for this project in AGIA. He noted that Mr. Massey expressed some concern over the lack of contractual stability to the ten year tax commitment. He recalled that the administration's original AGIA proposal contained contractual gas tax certainty provisions, subsequently removed by the legislature, which the administration believes should be considered collectively by the state. The current package is a reasonable proposal, and the state's system is adequate. He restated that the DOR is willing to address producers' concerns over time as the project moves forward. The AGIA process will continue to move forward; Mr. Palmer agreed that the AGIA process will continue through an open season to the FERC certificate. 11:20:00 AM CO-CHAIR JOHNSON asked whether the changes would be in statute or regulation. COMMISSIONER GALVIN answered that in order to make changes to address concerns, the producers would require statutory changes; whether or not that is ultimately needed is yet to be determined. He clarified that the revenue Representative Ramras brought up earlier points to the necessity of some regulatory aspects of AGIA not yet resolved; the state has an obligation to put regulations in place that clarify the royalty aspects of the upstream inducements. He reiterated that issues related to durability and fiscal issues would require statutory changes. 11:21:44 AM REPRESENTATIVE RAMRAS asked whether the administration will offer the largest tax concession in the history of Alaska in order to invite ExxonMobil into AGIA. COMMISSIONER GALVIN said no. 11:22:08 AM CO-CHAIR MILLETT asked if the administration is waiting for the producers or the legislature to propose changes to the fiscal tax regime. She remarked that the number one impediment to the gas pipeline is fiscal stability. COMMISSIONER GALVIN recalled earlier discussions, then stated that the DOR considers significant distinctions between what the producers want, voice, and ultimately need to commit their gas to the AGIA project. The question is whether the state needs to do anything to arrive at what producers need. He said AGIA was designed to move the project forward as the discussion ensues. Thus, time and goal are not lost, which is first gas under the timeline of AGIA framework. The state considers it a significant downside for the state to become desperate to resolve fiscal terms at an early juncture. He characterized the previous administration's agreement as ill-advised because it gave up considerably more than necessary in exchange for very little in return. The AGIA process provides for forward movement; the costs, economics, and the fundamental underpinnings of this project become clearer as the date approaches. The state's fiscal issues are only one component of the process, and it is not in the state's interest to feel compelled to satisfy the fiscal component before an open season. He recalled Mr. Palmer's testimony that regardless of whether the state reaches agreement with the producers, the AGIA project will move forward along the timeline until TransCanada acquires a FERC certificate, which is a critical component of AGIA, with respect to the state's interest. It is a critical component because the administration did not wish the project to stall and place the state in a leveraged position. He recapped his answer: the state does not intend to negotiate against itself, to sabotage itself. The state will not propose a tax change simply to "throw something more on the table." The analysis indicates the project is economic under the current system, he advised. However, the state is willing to listen to any proposal the producers wish the state to consider. He said, "We believe the ball is in their court. The state has put together a fiscal system and a durability package already. We don't need to negotiate against ourselves; we'll wait to hear what the producers have to say about that." 11:26:38 AM COMMISSIONER GALVIN, in response to Co-Chair Johnson, identified that Marty Rutherford remains the gasline team lead. Commissioner Irwin retains the prerogatives as it relates to Department of Natural Resources (DNR) issues, and he retains the prerogatives for DOR. Thus, the three would respond to any requests by the producers and are prepared to respond. CO-CHAIR MILLETT asked if it is in the state's best interest to hold negotiations on fiscal terms in the event of a failed initial open season. COMMISSIONER GALVIN answered no, it is not in the state's best interest. However, nothing is prohibiting the producers from clarifying their position with regard to a durable fiscal system. The state doesn't need to continue to put forward additional proposals or add more value. The state is not seeking to postpone the discussion. He suggested that those who create the perception that the open season is a deadline to conclude fiscal terms are creating a false deadline. He agreed alignment and forward progress is in the state's interest, and whether that happens before or after the open season will not change the timeline since AGIA is designed to prohibit delays. He suggested that the state needs to be open and willing to engage in the fiscal regime discussion, but additional deadlines or inducements are unnecessary. 11:31:12 AM COMMISSIONER GALVIN, in response to Co-Chair Millett, answered that the renegotiation of the state's royalty terms, and the legislature's statement that it will not change the fiscal system for ten years is a reasonable starting point and significant advancement for the state. The question is where this position is in relationship to ultimately what will be necessary to have the project move forward. In further response to Co-Chair Millett, Commissioner Galvin said that the state has always been willing to talk to producers about the fiscal regime. 11:32:53 AM COMMISSIONER GALVIN, in response to Co-Chair Johnson, deferred to TransCanada and ExxonMobil, with respect to the confidential information about terms and whether it will be made available only to the legislature in an executive session. He offered that the AGIA provisions require confidentiality. However, he also considered that TransCanada and ExxonMobil would likely share information. In further response to Co-Chair Johnson, Commissioner Galvin advised that any confidential information released to the administration would require specific authorization from TransCanada and ExxonMobil prior to releasing it to the legislature. He further explained that under AGIA, a distinction was made between the protocols of the application process which had specific provisions for the legislature to gain access through confidentiality agreements, and the post- licensure that does not have a similar protocol in place to share information with the legislature. 11:34:35 AM COMMISSIONER GALVIN, in response to Co-Chair Johnson, Commissioner Galvin said the evaluation team included members of the DOR, DNR, and Department of Law; legal counsel from Greenberg Taurig, LLP, who provided FERC pipeline expertise; Gaffney Cline and Associates; Goldman Sachs; C. Scott Hobbs of Energy Capital Advisors, Inc.; and Patrick Anderson of PINGO International Inc., a technical contractor on pipeline issues. CO-CHAIR JOHNSON asked whether the contractors were included in the AGIA budget or if there will be a request for supplemental funding. COMMISSIONER GALVIN offered that with the acceleration of the schedule, the administration would likely request supplemental funding next legislative session. In further response to Co- Chair Johnson, he recalled that leading up to the open season the figure was $84 million, of which the state would reimburse half, and the revised amount is $150 million for the same time frame. The schedule DOR has reviewed exhausts the $42 million through the first quarter of 2010. Thus, a supplemental is necessary to reimburse expenditures into the first quarter. CO-CHAIR JOHNSON inquired as to whether the outside consultants are being paid by TransCanada or the state. COMMISSIONER GALVIN answered the outside consultants are paid by the state. 11:37:47 AM MARTY RUTHERFORD, Deputy Commissioner, Department of Natural Resources (DNR), explained that the department requested re- appropriation of some funding to pull $.7 million from the $5.5 million, which was initially requested for the first year of AGIA, and the re-appropriation was not made to the team. Thus, the department would likely request a supplemental appropriation. CO-CHAIR JOHNSON recalled that ultimately some producers have suggested they want to own a portion of the pipeline commensurate to the amount of gas they commit to the pipeline. He further recalled that is the case with ExxonMobil, but he was not certain of other producers. He questioned whether the current situation creates a producer-owned pipeline. COMMISSIONER GALVIN answered that AGIA was designed to ensure that whoever owned the pipeline would act like a third-party owned pipeline. He asserted that DOR has never deviated from that stance. He denied the supposition that AGIA was intended to preclude the producers from owning the licensed project, pointing out that at least two-thirds of the must-haves in AGIA's structure anticipate that it will be a producer-owned pipeline in the sense that contractual agreements are necessary in order for it to act like a third-party pipeline. If it was designed to be an independent pipeline, that the contractual agreements would be unnecessary. Regardless of who owns the AGIA pipeline, it will act like a third-party pipeline, which is the intent. Thus, the state can enjoy the values of an expandable, open-access low-tariff pipeline, regardless of ownership. 11:42:19 AM REPRESENTATIVE RAMRAS questioned whether Commissioner Galvin is emphatically stating that the terms for royalties on North Slope gas would not change in order to induce the producers to come together on a pipeline. CO-CHAIR JOHNSON clarified that the question is whether the administration will ask the legislature for those changes. COMMISSIONER GALVIN said he was unaware of any discussion. It is DNR's purview, not DOR's, he continued, and he is unaware of any modifications with respect to the AGIA pipeline. 11:45:54 AM BUD FACKRELL, President, Denali-The Alaska Gas Pipeline (Denali), began his PowerPoint presentation by stating that Denali is still moving forward [slide 2]. Denali was created by BP Exploration (Alaska) Inc. (BP) and ConocoPhillips to build the Alaska Gas Pipeline (Denali). Denali is uniquely qualified to build the complex and enormous project, he said. Denali brings unparalleled North Slope and Arctic experience to the project, and Denali has worldwide experience in construction and operation of mega projects by virtue of its two owners. Additionally, Denali brings a strong balance sheet to the project. Denali remains on track to conduct an open season in 2010 and is in position to provide a superior commercial offering, which should be good for the state. Finally, Denali has not changed its focus, despite the economic turmoil, and remains focused on the long term view, he stated. MR. FACKRELL provided an overview of the gas fields located on the North Slope [slide 3]. He informed members that the Prudhoe Bay and Point Thomson field contains the majority of the 35 Tcf in discovered gas resources. According to a 2004 U.S. Geological Survey (USGS) additional 100-200 Tcf in undiscovered potential resources has been identified, he said. Of the 35 Tcf, BP and ConocoPhillips are 50 percent leaseholders of the resource. Additionally, BP and ConocoPhillips operate 99 percent of the North Slope production today. He pointed out that the Oooguruk field, operated by Pioneer Natural Resources Company, is the only field currently in production not operated by BP and ConocoPhillips. Thus, Denali producers provide over 30 years of operating expertise on the North Slope. These two companies built the North Slope infrastructure and the gas treatment plants along the pipeline corridor, he advised. MR. FACKRELL reviewed the regulatory framework in the U.S. and Canada [slide 4]. He explained that the proposed pipeline is controlled by the federal governments' in the U.S. and Canada. In the U.S., FERC is responsible for authorizing and regulating the project. The AGIA is not an exclusive license to build a pipeline; Denali can proceed outside AGIA, and is doing so. MR. FACKRELL related that in Canada, Denali is using the National Energy Board (NEB) process which incorporates all of the modern environmental regulations and is open to any project proponent. He remarked that the NEB and FERC have a history of working together to approve cross-border energy projects. MR. FACKRELL focused on the Denali Terms of Service summarized on slide 5 of his PowerPoint presentation. Denali is an open access pipeline. "That's the law," he said. FERC was here a year ago and testified to that fact." Denali's offering includes a gas treatment plant (GTP) and Denali brings unique expertise to building the GTP. He recognized the importance to Alaskans for distance sensitive transportation for local use that Denali will use. He remarked that Denali will use FERC- mandated rolled-in rates, which is part of the FERC governing process. The Denali pipeline design will provide for efficient expandability and will solicit shippers every two years regarding pipeline expansion. He stressed the importance that North Slope exploration occurs, that 35 Tcf will not provide enough gas for a 30-year pipeline, and that additional gas will be needed. Denali will have at least five offtake points in Alaska and will provide the necessary offtake points in Canada. MR. FACKRELL reviewed Denali's progress and key accomplishments [slide 6]. Denali has spent $100 million in the past year to move the project forward. Denali has mobilized its project team and has a core team of 80 to 90 people located primarily in Anchorage or in its Canadian headquarters. At FERC's suggestion, Denali pre-filed with FERC over a year ago, and has forged an extremely beneficial working relationship. Denali also filed the right-of-way on Alaska lands with the U.S. Bureau of Land Management (BLM), which represents one-third of the proposed pipeline route as well as an interactive process with BLM. 11:52:53 AM MR. FACKRELL pointed out Denali's successful 2008 summer field program, which primarily focused on the corridor between Delta Junction and the Canadian border. Work was performed on hydrology studies, archeological surveys, and contaminated sites. Additionally, Denali held extensive outreach programs in Alaska and Canada. He highlighted workforce development, including that Denali partnered with the University of Fairbanks (UAF) on an archeological assistance program. The surveyor apprentices completing the program can be used by anyone, he noted. Denali held extensive meetings with Alaskan and Canadian government officials. Finally, Denali awarded two major contracts, with Fluor/Worley Parsons for the GTP, and with Bechtel for the main proposed pipeline to assist with the engineering cost estimate and the compressor station design. MR. FACKRELL listed many of the contractor companies supporting Denali's work [slide 7]. He characterized the Denali team as a "top-notch, class A team, Alaskans, Arctic experience, Alaska experience, and two worldwide engineering companies to supplement that. We're poised for success." 11:54:45 AM MR. FACKRELL stated that Denali is focused on the initial open season [slide 8]. Denali's 2009 program is much broader than its 2008 program, such that Denali will conduct the work necessary for the 2010 open season. Denali is focused on the cost estimate, which is a critical component of the project, since it is vitally important to convey confidence to potential shippers that Denali understands the costs, given the degree of definition currently available' and using the assistance of contractors like Fluor/Worley Parsons and Bechtel. Denali has ongoing work with agencies such as DNR, FERC, NEB, the Office of the Federal Coordinator (OFC), and BLM. Denali is actively working with the FERC on its pre-file application; FERC requires a third-party environmental contractor, and Denali is actively working on a contract with Argon National Laboratories, to be the specified FERC contractor. MR. FACKRELL offered that Denali has engaged in conversations with Department of Transportation & Public Facilities (DOT/PF) because the infrastructure will need to be updated for this pipeline project, including roads, ports, highways, and the rail system. Additionally, Denali is involved in a field work program focused on Canada. He restated efforts taken with the Alaska Workforce Development. Stakeholder engagement activity continues in Alaska, and BP and ConocoPhillips have large operations in Canada, which assists with First Nations and other aboriginal groups along the proposed corridor. MR. FACKRELL concluded by reiterating that Denali's focus is on the initial 2010 open season and the cost estimate that will provide confidence to shippers [slide 9]. Denali is positioned for a superior commercial offering, which will benefit the two owners, the citizens of Alaska, and the state. He emphasized that Denali does not require outside funding, and Denali's long- term focus protects it from disruptions by the current economy and competition. 11:58:33 AM REPRESENTATIVE DAHLSTROM asked whether satisfactory agreements have been reached with all of the First Nations groups along the proposed route. MR. FACKRELL characterized the work with First Nations parties as a process. Although Denali has not reached agreements with all of the parties, it feels good about the progress. 11:59:17 AM MR. FACKRELL in response to Co-Chair Millett, pointed out that all pipeline companies have testified to the importance of fiscal stability; that shippers want to know the fiscal regime. MR. FACKRELL, in response to Co-Chair Johnson, said that as a pipeline company, Denali will not be negotiating with the state on fiscal certainty; that is the role of shippers and producers. MR. FACKRELL, in response to Representative Ramras, commented that Denali believes it has a level playing field, and finds DNR cooperative and the people qualified to review its application. Although Denali does not currently have a signed reimbursable services agreement (RSA), Denali is moving forward with the process, and is continuing to perform field work. Denali does have an RSA with BLM for the filing on the right-of-way, he noted. 12:02:27 PM MR. FACKRELL, in response to Representative Ramras, responded that there is only enough natural gas available for one gas pipeline. He said, "Let's make sure we're clear on that. There will not be two pipelines built." Denali has held conversations with FERC about the process, and FERC intends to allow two applications to move forward since producers could commit gas to two competing gas pipeline companies. However, economics will win out in the end and once financial commitments are secured, only one pipeline will go forward. REPRESENTATIVE RAMRAS pointed out that in Oregon five pipelines and two LNG facilities have all been permitted, but Oregon recognizes that only one LNG and one pipeline will be built. 12:03:40 PM MR. FACKRELL, in response to Co-Chair Johnson, offered to put on the record Denali's independence from the producers. He referred back to slide 5, stating that Denali is an open access pipeline, according to the law. He said: When the Natural Gas Act for Alaska was passed in 2004, it designated FERC to set up a set of rules to govern this pipeline and conduct an open season. As part of that we have to be separate, a distinct entity. We have to function separately from the shippers. And that is what we are in the process of doing right now, making sure we are compliant with that, and it is our intent when we go to open season that we will be able to pass the muster on FERC rules, but FERC is going to be very careful about that governance piece and ensure that no one has an opportunity, our two owners don't have an opportunity on shipping side beyond any potential shipper out there. CO-CHAIR JOHNSON stated that Denali has partners that are producers. TransCanada has a partner that is a producer, providing information to them on the 2002 study. 12:06:13 PM MR. FACKRELL, in response to Co-Chair Johnson, responded that in 2001-2002 the producers, ExxonMobil, BP, and ConocoPhillips, performed a study for about $125 million over an 18-month period. All three producers have proprietary rights on the information and can share it. Denali has held that information since Denali was formed, which is similar to TAPS. Thus, Denali has used the study for over a year to build its cost estimate and work program, including updates. In fact, Denali expended effort to update its cost estimate to give shippers confidence on the overall project cost. In further response to Co-Chair Johnson, Mr. Fackrell advised that the original study cost about $125 million, but he was uncertain of the cost of the TAPS study. 12:07:32 PM MR. FACKRELL, in response to Co-Chair Johnson, advised that every piece of the tariff is subject to FERC's review and approval; FERC will analyze whether the tariff is being paid twice. 12:08:47 PM CLAIRE FITZPATRICK, Senior Vice-President, Chief Financial Officer, BP Exploration (Alaska) Inc. (BP), stated that she recently assumed responsibilities for upstream gas activities. She represents BP as a potential shipper and leaseholder. She provided a shipper's perspective on regulations, shipping, open season, and ExxonMobil's joining TransCanada. She stated that FERC requires separation of interest from pipeline activities, which means that selling and shipping activities must be separated from direct or indirect interest in a pipeline. She cannot discuss Denali as a legal entity, but just matters related to potential shipper and leaseholder. Her primary objective is to monetize the gas, which needs to be economic. Since BP is also an operator at Prudhoe Bay, BP has requirements and agreements with working interest owners to ensure that as information is shared with TransCanada, ExxonMobil, or Denali, that it is shared on an equitable and unbiased basis and the working interest owners must be made aware of the information, as well. As a shipper BP continually evaluates opportunities to monetize gas, and to identify ways to eliminate or decrease identified risks. The Alaska gas project has many risks and many will be borne by the shippers. She reviewed four key risks: actual presence of the gas, market value of gas, costs associated with the gas in terms of tariff, and fiscal framework. MS. FITZPATRICK discussed the actual presence of gas, recalling that 35 Tcf was previously mentioned, which is not enough to fill the pipeline for 30 years. She said BP's risk is how much gas is available, and what commitment BP will make. She related that BP has observed huge volatility of gas not only in oil prices but gas prices in the market value of gas. However, BP must view selling gas in a market of 2020 and beyond in Alaska, Canada, Lower 48, and possibly broader than that if LNG is also considered. Thus, the risk analysis is much different when considering longer term versus shorter term gas sales. MS. FITZPATRICK, with respect to costs associated with the gas, stated that these costs pose a large impact, and range from combined capital and operating costs, which are paid by the shipper in the form of tariff. MS. FITZPATRICK, with respect to fiscal framework, stated that tax and tax stability are important to BP, recalling similar words expressed by other speakers today as predictability and durability. BP has not approached the state with what BP would need to make this project viable, since it is based on ongoing analysis. All of these risks must be taken under consideration, and BP must arrive at what is an acceptable risk as a shipper in order to make the commitment. She restated that BP is continuing to make those assessments. 12:14:24 PM CO-CHAIR JOHNSON inquired as to the point at which BP as a shipper will determine whether the fiscal framework is appropriate. MS. FITZPATRICK responded that all scenarios will be reviewed; that it is a balance between must-haves and need-to-haves. She related that once BP gets to open season and reviews the initial package, BP will assess the quality of the engineering and the risk and variables. If that starts to eliminate a lot of the risks, then the total acceptable risk begins to change. Currently, BP runs various scenarios to frame up ideas of at what point does the project break. She speculated that BP would likely be ready to begin discussions, ahead of receiving the full initial open season package. CO-CHAIR JOHNSON asked for clarification of the timeframe for commitment of gas. MS. FITZPATRICK FERC answered that FERC will specify the timetable, but she recalled the preferred timeframe is 90 days. CO-CHAIR JOHNSON in terms of timing, when the state would hold discussions on the fiscal stability. MS. FITZPATRICK related that after BP reviews the open season packet, and assuming it is acceptable, BP would then indicate that it was prepared to make a commitment based on certain conditions, and fiscal stability is likely to be one of those conditions. MS. FITZPATRICK, in further response to Co-Chair Johnson, offered that BP would prefer to have fiscal stability ironed out prior to committing gas, but she is not sure it is a viable outcome. 12:19:33 PM MS. FITZPATRICK described the open season process, such that all open seasons will be treated equitably, that BP is indifferent to pipe ownership, but its interest would be to obtain the best option for BP. The firm transportation commitment decision is huge since it means that BP will commit a certain volume of gas for a certain timeframe, on the basis that conditions will be resolved to everyone's satisfaction. The firm commitment is made up front, at which time BP accepts identified risks and parameters, including that BP may commit to unknown gas and price. During the open season BP will assess the quality of the work and best estimates will be made and built into the risk assessment. With respect to the impact of ExxonMobil joining TransCanada, ExxonMobil brings experience, which suggests that quality brought to open season will be higher. Furthermore, competition is good for the shipper since it provides the shipper with options. Ultimately, BP will make the choice that is best for its shareholders. 12:22:11 PM REPRESENTATIVE RAMRAS recalled Mr. Massey's testimony that ExxonMobil desires ownership in proportion to its volume of gas and asked if that is a requirement of BP. MS. FITZPATRICK responded that BP assesses risk and absolutely wants interest in a pipeline equal to its own interests. However, BP has instances in which it ships product through someone else's pipeline. Thus, it really depends on the circumstances. 12:23:16 PM REPRESENTATIVE RAMRAS remarked that ExxonMobil is tough in business and dynamic. He posed a scenario in which ExxonMobil engages in a discussion regarding durable and predictable terms and enters AGIA as a builder. In that situation its interest in achieving a low tariff would be beneficial to other producers. Thus, if terms are acceptable to ExxonMobil, would BP would be more or less likely to join the project. MS. FITZPATRICK answered that BP would perform an independent assessment of fiscal terms. In the scenario described, she said she hopes that BP would have been a party to the negotiations for fiscal terms, and if so, the terms may be favorable to the company. However, the fact that the terms are good for one party is not a guarantee that it is good for another, since the pipeline companies are independent. REPRESENTATIVE RAMRAS surmised that if BP is successful in negotiating terms with the Palin Administration, similar to those negotiated with the Murkowski Administration, that BP would review the four categories of risk. MS. FITZPATRICK noted her agreement. While the terms under the Murkowski Administration were more favorable than the current terms, BP would still need to evaluate them, she said. 12:26:41 PM MS. FITZPATRICK, in response to Representative Coghill, answered that FERC sets out requirements for separation of function to ensure that shippers without affiliates and pipeline companies without connections to producers receive fair treatment. In terms of FERC's assessment of bids, the economics are considered, but multiple risks are involved and BP performs a total risk assessment. REPRESENTATIVE COGHILL recalled the reference by TransCanada, BP, and Denali about their responsibility to their shareholders. He stated his interest in knowing the "tipping point," realizing that both risk and return on investment are considerations. MS. FITZPATRICK agreed that it is about return on investment, but she would not be performing her duty if BP shareholders thought the investment into an affiliate company would not produce a better return. CO-CHAIR JOHNSON pointed out that the responsibility to the stockholder is the same, that it is sometimes difficult to understand the separation. He remarked that FERC has made the clear distinction so the stockholders do not need to make the determination. 12:29:13 PM MS. FITZPATRICK, in response to Co-Chair Millett, responded that she cannot comment whether BP is talking to any other pipeline companies, since she is not a party to the conversations. However, as a shipper, she said that BP is holding discussions with TransCanada and Denali and is making it clear that they each have access to exactly the same information. 12:30:29 PM REPRESENTATIVE DAHLSTROM asked if ten years of tax stability would be sufficient. MS. FITZPATRICK answered that ideally the producer would like tax stability for the timeframe of the commitment. 12:31:23 PM REPRESENTATIVE COGHILL surmised that BP holds contracts on North Slope operations in Prudhoe Bay, and that gas from those fields will be part of the open season. He asked how BP manages discussions with respect to competing interests in the unit agreement. MS. FITZPATRICK replied that the agreement used is the actual working interest owner's agreement and the parties must reach agreement for gas offtake, although multiple scenarios exist to do so. While it is managed through contractual agreement, the process can be very complicated. 12:33:28 PM CO-CHAIR JOHNSON suggested that having ExxonMobil joining the team must be helpful in terms of confidence of the shipper. MS. FITZPATRICK agreed. 12:34:21 PM REPRESENTATIVE RAMRAS asked whether discussions and strategies are being held with ExxonMobil, the leaseholder, to obtain fiscal certainty from the state. MS. FITZPATRICK replied not at the moment. In further response to Representative Ramras, she said that given the relative recent announcement of ExxonMobil joining with TransCanada, that BP has not had a conversation about the matter so she could not answer. 12:35:52 PM CO-CHAIR MILLETT asked if BP, the shipper, is holding discussion with TransCanada about joining the projects together, that Alaskans would enjoy having one project moving forward. MR. FACKRELL responded that at this juncture Denali is not holding discussions with TransCanada. The Denali owners did not file application under AGIA because they did not agree with the terms, so to join owners now would be problematic. In further response to Co-Chair Millett, she said that Denali has not yet held discussions with ExxonMobil, the shipper, but anticipates it will do so. Denali wants to insure proper separation, and plans to hold discussions with all shippers. 12:37:50 PM WENDY KING, Director of External Strategies, ANS Gas Development Team, ConocoPhillips Alaska, Inc. began by stating that she is representing ConocoPhillips as leaseholder and prospective shipper. ConocoPhillips is a major owner of North Slope oil and natural gas leases, and is the largest oil producer in the state, she pointed out. First and foremost, ConocoPhillips will seek the best solution to transport North Slope gas to market, and ConocoPhillips will remain engaged and interested in all gas pipeline projects. She characterized ConocoPhillips as keenly interested in a gas pipeline project. With a 36 percent ownership in the Prudhoe Bay unit and an interest in the Point Thomson field, ConocoPhillips is motivated to monetize the natural gas in an economically viable way. Additionally, ConocoPhillips is one of the largest active explorers in the state. However, it is not just the aspect of ConocoPhillips's portfolio. Any gas pipeline will have an implication on the life and viability of all North Slope assets, such that if the gas pipeline happens and extends the field life, it will increase the opportunity for more oil to flow down the TAPS pipeline, and it will impact the economic viability of satellite fields. It will also incentivize oil and gas exploration. Thus, as exploration occurs for natural gas, more oil is likely to be found. 12:40:48 PM MS. KING discussed a list of economic drivers going into an open season, beginning with the view of long-term natural gas prices. Each company will make assessments spanning a 20 to 30 year timeframe to project natural gas prices for the life of a potential project. Another economic driver will be to assess the natural gas that is available to ship, including deliverability of the gas - the volume, rate, and length of time. Typically, the nature of the terms of the shipping commitment are not necessarily a commitment to ship gas, but merely a commitment to pay a toll, whether or not gas actually flows, and represents a risk borne by shippers of whether the gas will be there over the specified timeframe. Additionally, ConocoPhillips will review the transportation costs for the actual toll to move gas from the North Slope to the Lower 48. The fourth economic driver includes all other terms and transportation fees, including many details. One key detail will be the term or the length of the long-term shipping commitment. Other economic drivers include the financial arrangements, and how that translates into an actual cost of service; and the receipt and delivery points, and whether ConocoPhillips obtains the best opportunity to move natural gas to the Lower 48 markets for the lowest cost possible. ConocoPhillips will review all tariff terms and conditions, as well as all state and federal tax and royalty structures. She noted the potential for changes to the federal tax structures. Thus, perspective shippers will be engaged in projecting actual tax and royalty terms that will apply over the period of any shipping commitment. She offered her belief that the risks of the project remain high. 12:44:11 PM MS. KING, in response to Representative Ramras, responded that ConocoPhillips views ExxonMobil's involvement as a positive step, and one that will increase the quality of an initial open season. She differentiated between the diverse interests and equity between ConocoPhillips and ExxonMobil on the North Slope. Thus, ConocoPhillips will be actively engaged in the pre and post-open season process, and will continue to monitor ExxonMobil and TransCanada in order to ensure shareholder return as the prospective pipeline project. In further response to Representative Ramras, she answered that ConocoPhillips has indicated numerous times its willingness to make changes from the previous contract under the Murkowski Administration. She offered that this is not the starting point. Instead, ConocoPhillips views the current situation as an open discussion about the terms and conditions today as a prospective shipper. With anticipated updated cost estimates, ConocoPhillips will consider the appropriate package that will move the issue forward, being mindful that there are broader discussions happening, not just with state taxes and royalties. 12:49:12 PM REPRESENTATIVE RAMRAS offered his view that ExxonMobil was the toughest negotiator during the negotiations between the producers and the state under the Murkowski Administration. ExxonMobil was the producer that demanded the hardest terms at the table, while ConocoPhillips exhibited the most flexibility in revisiting terms. It is interesting to view ExxonMobil on the inside while BP and ConocoPhillips are on the outside of the current AGIA pipeline, he said. 12:50:27 PM CO-CHAIR JOHNSON noted his appreciation for the institutional knowledge brought forth today, the focus on the future, and how to bring forth Alaska's natural gas resource into a natural gas pipeline. He characterized that process as problematic without everyone on the same page. 12:53:27 PM ADJOURNMENT There being no further business before the committees, the joint meeting of the House Resources Standing Committee and the House Special Committee on Energy was adjourned at 12:53 p.m.