Legislature(2007 - 2008)HOUSE FINANCE 519
05/02/2007 01:30 PM FINANCE
Download Mp3. <- Right click and save file as
* first hearing in first committee of referral
= bill was previously heard/scheduled
= bill was previously heard/scheduled
HOUSE BILL NO. 177 An Act relating to the Alaska Gasline Inducement Act; establishing the Alaska Gasline Inducement Act matching contribution fund; providing for an Alaska Gasline Inducement Act coordinator; making conforming amendments; and providing for an effective date. 1:40:17 PM CONOCOPHILLIPS ALASKA BRIAN WENZEL, VICE PRESIDENT, ALASKA NORTH SLOPE (ANS) GAS DEVELOPMENT, CONOCOPHILLIPS ALASKA, INC., ANCHORAGE, stated ConocoPhillips does not support AGIA as introduced by the Governor or the version adopted by the House Resource Committee (HRC). The bill requires critical changing in order to avoid delays. The applicant submitting an application should be able to obtain the requirements of AGIA's intent through a combination of terms and commitments. There should be a comprehensive package including critical up-stream resource terms balancing the risks, while continuing to provide maximum benefits to the State of Alaska. ConocoPhillips would like to find a way to make the Alaska North Slope (ANS) development commercially viable; then the pipeline becomes an afterthought. He reiterated, first, resource terms must be addressed. 1:42:38 PM Mr. Wenzel noted the question is in relationship of how to develop gas resources for the pipeline to succeed. He discussed the need for dialogue with the Administration in the attempt to find common ground fiscal resource terms that allow for the viability of the project. The process should include negotiations rather than competitive bidding. 1:44:38 PM Mr. Wenzel encouraged consideration of the full package and that the proposed version of AGIA does not include that. AGIA stipulates up-stream terms inadequate to ConocoPhillips. Representative Gara asked what "up-stream" means to industry. Mr. Wenzel replied, that is the portion allowing production of gas. Up-stream is a tax term. 1:46:01 PM Mr. Wenzel said ConocoPhillips supports changes to the terms of AGIA, with specific regards to the up-stream fiscal terms. The inadequate resource terms of the bill creates a situation of project risks & uncertainties, which more than out weigh the returns. He reiterated, unless AGIA is adjusted, ConocoPhillips is unable to make an application. 1:47:42 PM Mr. Wenzel discussed comments from the newspaper, indicating the project has a 50% rate of return. He claimed that the return could be closer to a zero percent and that the claims that the project is "wildly economic" are misleading and are based on assumptions that can not be guaranteed. There are risks and uncertainties, which out-weigh potential benefits if there is no clarity incorporated regarding the resource terms. Mr. Wenzel commented that the resource risks have always posed the greatest obstacles. Long-term clarity on State taxes and royalties is critical to the project. 1:50:02 PM Mr. Wenzel mentioned previous testimony heard from Ms. King about AGIA's restrictive approach and that she encouraged a mechanism be in the bill, allowing the resource lessees, resource terms. He emphasized that AGIA's bid requirements must be changed and warned about disadvantages to Alaska awarding an exclusive license to a single entity. There is a fundamental flaw in the AGIA plan, which is not founded on reasonable commercial expectations. The development of the proposed pipeline will be one of the largest public construction projects in the world. There are certain standard practices for structuring, planning and developing such a resource; AGIA tends to ignore business realities, requiring certification before all details are worked out. Sanctioning timelines for commercial projects this size are unreasonable. He discussed a clause in the bill, which prevents cost overrides. 1:53:56 PM Mr. Wenzel argued terms used in AGIA language regarding investment business criteria; if HB 177 is adopted as drafted, the State makes the choice to provide inadequate certainty regarding future tax rates. The manner that it is structured, every anticipated a tax rate increase would have to be built into the economics of the project. The ten-year term proposed in AGIA does not recognize the long term role of shipping commitments and the language could force a project developer to amortize their 10-year investment, increasing the tariff on the pipeline. He reiterated that AGIA does not recognize realities of financing the structure of such a large project. Mr. Wenzel commented on the lack of lending recognition, dangerous for Alaska trying to off-set the risks for the project. 1:56:56 PM Mr. Wenzel encouraged legislative consideration of industry recommendations that AGIA be changed so that they can submit a best proposal. As currently drafted, AGIA requires commissioner's to reject any proposal that does not match exactly AGIA terms. All processes should be transparent, allowing the applicant to put forth the proposal, meeting the needs of all stakeholders. 1:58:43 PM Mr. Wenzel advised the process-forward requires AGIA to be amended to include the fiscal terms. He surmised that the quickest way forward would be for BP, Exxon & ConocoPhillips to provide a combined proposal; companies that have much expertise & knowledge in gas resources. They should be included in the package. Mr. Wenzel continued, ConocoPhillips wants to adopt & develop the State's ANS gas resources and participate in a competitive process, recommending that AGIA be amended. He claimed that no one in the State can afford to wait for the proposals. Alaska deserves to see comprehensive and the best possible proposals. 2:02:15 PM Representative Gara referenced the up-stream portion of the project, noting the amount the State has already volunteered to pay for gas field development costs. Mr. Wenzel responded that all expectations regarding future resource terms would be built into future economics of the project. Currently, Alaska has an insufficient framework regarding resource terms. Representative Gara pointed out that the State pays 42% of the gas field development costs. Additionally, HB 177 reduces royalty by 2% by eliminating the higher overall costs, worth 2% to the producers. The contract contains a 70/30 debt ratio benefiting producers. Representative Gara continued, included is an $18 billion dollar federal loan guarantee for the pipeline construction and a $500 million dollar offer to help build a pipeline with a ten-year tax lock-in. He emphasized that HB 177 includes a lot of incentives. Mr. Wenzel thought the listed incentives had been mischaracterized. He stated that the Petroleum Production Tax (PPT) had been designed with a dollar goal for the State. Alaska could receive those dollars by either a production tax, gross revenue or net tax and the State chose a net tax because it helped provide incentive investment. Mr. Wenzel referenced the 70/30 debt ratio, which he thought would provide an artificial requirement on the pipeline owner and would not act as an incentive. At this time, the federal loan guarantees do not have regulations & the ability to use them has yet to be determined. That creates another uncertainty. There will be benefits to Alaska, however, producers must look forward to the entire mix of uncertainties and cost requirements for any project. Representative Gara emphasized that the producers get to deduct 42.5% of the costs, charging it back to the State. In a normal situation, a profits tax could not be deducted until there is a profit. Alaska allows the deduction of the gas field costs even before there are indicated profits. Alaska has always been a reliable partner compared to other places of industry investments such as Argentina, Russia (nationalization), Nigeria, & Viet Nam; Alaska stacks high in comparison with those places. Mr. Wenzel reminded members that ConocoPhillips invests heavily in Alaska and that every location around the world carries a mix of uncertainty and promise and that the recommendations made at the meeting takes that all into account. Concerns stem from the size of the project and the dependency Alaska has on the revenue from oil and gas. 2:09:22 PM Representative Gara voiced concern with a request for tax certainty. According to the legislative attorney, a ten- year lock-in might be unconstitutional. He questioned if the Court rules that the Legislature can not lock-in future legislature's tax rates, will the producer's back out. Mr. Wenzel stated that resolving the up-stream resource terms includes working with the Administration and Legislature to find the best mechanism to provide clarity on resource terms. He knew there could not be a 100% assurance on the project. 2:10:58 PM Representative Gara asked if ConocoPhillips could commit to acceptable terms, without the State fearing they would back out of the project if tax certainty was not allowed by the courts. Mr. Wenzel recommended determining backup alternative mechanisms and encouraged that the State work jointly with ConocoPhillips (CP) to provide the necessary comfort for the project to move forward. 2:11:49 PM Representative Kelly questioned if CP could alone make a proposal. Mr. Wenzel did not know; through AGIA, they could. However, their ability to advance a project alone would be less stable. He encouraged that the three producers work together; he wanted the support of the other two producers. Representative Kelly worried that a proposal including all three major producers could not be competitive. The Governor's attempt is to take elements including fiscal certainty. He asked if it was too early to create such a "deal". Mr. Wenzel did not think that the "deal" had been lost, not8ing that competitive could work. He stressed if AGIA is changed, including submission of a comprehensive proposal with the resource terms, could leave the door open for competitive bidding. Representative Kelly did not embrace such a view; he worried about the "only option" that would be provided by the three major producers. Mr. Wenzel countered that other bidding companies could attempt to be included in the proposal. He warned that there must be a trade off in terms and conditions of the open-season in order to guarantee that enough risk is mitigated. Representative Kelly supported Governor Palin's inclusion of as much competitiveness as possible in the legislation and worried about the proposal submitted by ConocoPhillips. 2:18:25 PM Mr. Wenzel explained in order for the process to move forward, AGIA needs to be changed to allow for comprehensive proposals; then the three major producers will come forward with a package proposal. He addressed the advantages of competitive bidding. Representative Kelly recommended reconsideration of both proposals [PPT & AGIA]. 2:21:30 PM Representative Gara asked if the pipeline is developed, could there be a guarantee that gas would be sold. Mr. Wenzel stated that CP wants the pipeline. Regarding Prudhoe Bay, the fastest move forward would not to be attempting to nominate the gas, which are practical & legal issues regarding gas allocations. Representative Gara asked if the pipeline proposal was passed, including a low enough tariff to guarantee production is economic, could Alaska count on an agreement with CP to sell gas to that project. Mr. Wenzel pointed out the amount of speculation regarding that concern. He noted that the goal of CP is development of gas resources. If there was a mechanism to accomplish that with the criteria needed, CP will undertake it; economics drive it. There are big concerns regarding the capital costs of the project. Representative Gara discussed the determination of the anticipated profit margins and that the State has determined the net present value, profit margins, gas production and best estimated tariff rates. He asked what the current net value ratio required by CP. Mr. Wenzel explained the rates can not be disclosed. The best way for the State of Alaska to manage a development project such as the proposed would be to align with the project developer and commodity seller. Alaska obtains revenue from the net cash flow and profit of the producers. 2:26:16 PM Representative Gara advised that producers need to inform the State of the benchmarks in order to address the internal profit needs. Mr. Wenzel maintained that the Governor has been attempting to "get around that", offering only competitive bidding. He argued, a new agreement must be determined. Representative Thomas voiced frustration with the process, pointing out the limited time left in the session. Mr. Wenzel indicated that producers raised their concerns during initial discussions & recommended switching bid requirements to bid variables as a way to provide flexibility. He recognized time is short & that there is not sufficient time to deal with changes needed in AGIA. He urged an alternate proposal. Representative Thomas asked that the producer's amendments be brought forward. Mr. Wenzel offered to provide language creating an alternate proposal. 2:31:33 PM Representative Joule inquired when the "window" closes. Mr. Wenzel did not know. He suggested there is a sense of urgency to move the project forward; ConocoPhillips wants to see that happen. Representative Kelly asked about the bid alternate approach and the economics of the project. Mr. Wenzel advised that if the project does move forward, ConocoPhillips is willing to be creative during the negotiating process. He hoped that applicants would be encouraged to submit multiple proposals. He spoke against the competitive bidding process established in AGIA. Representative Kelly asked if current language prevents that from happening. Mr. Wenzel indicated for ConocoPhillips, there is not adequate resource funding and that there are too many risks and uncertainties. Representative Kelly suspected that the gas price and fiscal certainty were the big issues. Mr. Wenzel pointed out in the current draft of AGIA, the producers were prevented of from proposing any alternate up-stream terms. Representative Kelly referenced the production gas tax issue; he did not think ConocoPhillips was prevented from offering bid alternate approaches. Mr. Wenzel responded they would look at that. 2:42:30 PM Representative Joule questioned the Legislature's role in this process. Mr. Wenzel responded that the Legislature has a role in structuring the basic needs for citizens and also providing checks and balances between the Administration and the industry. The Legislature must look at diversifying the State's economy and motivate projects which provide new industry. 2:46:10 PM Representative Gara noted that the Governor's proposal seeks additional bids; it includes twenty terms wished for the contract to move forward. Mr. Wenzel thought there could be delays if sufficient bids were not received. He reiterated the need to receive all bids up-front. 2:48:39 PM In response to a question by Representative Gara, Mr. Wenzel stipulated that the procurement process seeks to achieve uncertainty among the bidders. The applications must conform to the criteria and create the motivation. EXXONMOBIL CORPORATION MARTIN MASSEY, U.S. JOINT INTEREST MANAGER, EXXONMOBIL CORPORATION, advised that ExxonMobil has been in Alaska for over 50 years and has been a key player in Alaska's oil industry development. ExxonMobil holds the largest working interest at Prudhoe Bay [36.4%] and their current net production in Alaska is approximately 150,000 barrels per day. ExxonMobil has benefited from their involvement in the State of Alaska and believes Alaska has benefited. Commercializing Alaska's North Slope (ANS) gas would allow continuation of a mutually beneficial relationship. 2:53:06 PM Mr. Massey continued that AGIA is important to Alaska, the nation and ExxonMobil. The project has the potential to generate billions of dollars in revenues for the State, the U.S. federal government and Canada; it could provide a stable and secure source of clean energy for Alaska and North America for decades to come. For ExxonMobil, the project is significant and has the potential to add over 1 billion cubic feet per day of gas sales, which would be more than a 10% increase to the current worldwide daily gas production. The project could add over one billion oil- equivalent barrels to proved reserves, nearly enough to replace a year of production. Given the significant impact the project could have, ExxonMobil supports efforts to advance a pipeline project. ExxonMobil has spent more than $180 million dollars studying ways to commercialize Alaska gas. Since the 1970's, ExxonMobil has evaluated LNG, gas to liquids and gas pipeline alternatives. Based on those studies, it was determined that a project would result in the best value for the State & the producers. Mr. Massey stated that as written, AGIA does not encourage market-based competition due to its prescriptive nature. AGIA does not adequately address the significant up-stream issues and risks associated with the scale and magnitude of the project. ExxonMobil believes that AGIA would not create an acceptable framework for the world-scale mega-project unless it allows parties undertaking risks to make a proposal that properly manages the risks. The Administration's model fails to recognize the nature of such a basin-opening project. The up-stream pays for the mid-stream, which cannot be split when evaluating commercial viability. The State's economic model needs to be corrected. For best results, AGIA must establish the State's key objectives, allowing applicants flexibility to compete and define the parameters that are necessary to make the project commercially viable. Amending AGIA must be objectively driven, allowing for open competition, maximizing the number of applicants and allowing those applicants to propose innovative solutions to meet the State's needs. 2:56:10 PM Mr. Massey noted the tendency to underestimate the size and risk of the project, the largest in North America. Due to the size, there is a greater chance of cost over runs; steel prices have doubled since 2001 and worldwide projects are putting pressure on other resources. 3:05:34 PM Mr. Massey addressed the importance of alignment between the State and the producers and the benefits of a producer project. Maximizing the value to the State of Alaska and the resource holders means selecting the right design concept and then executing it to deliver low cost and fast completion. On this size & magnitude of a project, construction and operating experience must be a significant consideration. Only a limited number of companies can demonstrate the capabilities, financial strength and arctic experience to effectively participate in and manage world- scale mega-projects. Mr. Massey pointed out that the three producers have mega- project experience in numerous places throughout the world and have demonstrated success in meeting project objectives. ExxonMobil's arctic experience is extensive, with developments in multiple types of arctic environments. ExxonMobil's global project development leads the industry in project cost and schedule performance. ExxonMobil has also demonstrated leadership in safety, health and environmental performance. ExxonMobil has the financial strength to make the project a reality, maintaining one of the strongest financial positions of any company in the world. He added that they maintain the highest credit rating from Standard and Poor's (S&P) & Moody's triple A list. Mr. Massey pointed out that it is important to remember that the project is a basin-opening project, benefiting the State and the industry for decades. Basin-opening projects throughout the world have progressed and been successful when there is alignment between the host government and the leaseholders. The producers and the State both want a pipeline project to commercialize the ANS gas resources and open the basin to gas exploration. ExxonMobil believes a producer gas pipeline project would result in maximum value to the State with maximum incentive to control costs. Low capital and operating costs will result in lower treating and transportation costs and access to premium market price. The State will receive the majority of the revenue from the value of gas sales via revenue received under the lease royalty agreements and from production taxes; valued based on net-back received from the gas. rd Mr. Massey commented 3 party owners do not share the same incentives; they actually benefit from increased capital costs. Based on the demand for workers which the project generates, Alaskans are primary to successful project execution. Financial strength, experience and the ability to get the job done should be the critical components of any evaluation of proposals. When available options are considered, a producer pipeline will provide maximum value to the State of Alaska. Mr. Massey addressed the fiscal predictability importance for a mega-project. ExxonMobil must work with the State to explore important fiscal issues. Because of the nature and magnitude of the risks associated with the project, fiscal terms that are predictable and durable are necessary. The two risks: · Geologic and cost risks; and · Market risk is inevitable in a commodity business such as oil and gas. The risk of fiscal terms changing is of a different nature and outside the producer's control. There must be agreements allowing development of the project under predictable and durable terms with an adequate degree of certainty. It does not mean that taxes cannot change over the life of the project. Predictability means that the State's tax and terms are understood, defined and modeled for the purpose of evaluating the overall project economics. If fiscal terms can change in unpredictable ways in the future, then the industry is not able to make well-founded investment decisions on behalf of their shareholders, nor would lenders be as confident in providing financing for a project that size. The project requires massive investments before any revenue is generated from the investments. As a result, increases in taxes on oil and gas related activities during the life of the project could impact the commercial viability of the project and could increase lender concern. Because the fiscal terms can be modified under the proposed AGIA legislation, it does not provide the fiscal predictability necessary to ensure a commercially viable project. Mr. Massey pointed out, it is important to recognize that for mega-project development, governments need to provide long-term fiscal stability. Contracts should include fiscal stability protection and in some cases, it will run for the length of the contract; others for 40+ years. AGIA must allow applicants to put forward the best proposal on what is required to make the project commercially viable, allowing the State the opportunity to consider the proposals that have the best chance of actually delivering an Alaska gas pipeline. Mr. Massey outlined thoughts on how AGIA could be modified to ensure the best chance of a successful result, allowing the State to maximize value. Alignment between the State and the leaseholders is essential to a basin opening project of such magnitude; therefore, establishing the right approach when moving forward is the most important activity for a project. In calculating up-stream revenue, everyone must be aware of the taxes and royalties from oil and gas operations and set at a level, making the project viable and should be addressed at the beginning. To ensure that the project is constructed, it must be commercially attractive to the shippers at the time they make their transportation commitments. Shippers, particularly those who must substantially invest, develop and produce gas resources, will not be willing to enter into a long-term financial commitment for the transportation of gas if there is likelihood that initial rates would be increased in the future to accommodate expansions. Under the Alaska Natural Gas Pipeline Act, Congress struck what the proper balance between encouraging investment by those willing to commit to pay for initial capacity and encouraging exploration by providing an opportunity for future access to the pipeline. Because of the unique nature of the Alaska gas pipeline project, the Federal Energy Regulatory Commission (FERC) approved policies to enable a mandated expansion benefiting explorers. In addition, a pipeline entity should not be required to accept a FERC certificate irrespective of imposed conditions. · Under AGIA, the proposed up-stream inducements would require significant modification to ensure that a commercially viable project is obtained. · AGIA prescribes activities that must be completed within a specific timeframe or date certain. Setting arbitrary target dates is not consistent with good project management practices. · Milestones are not necessary if the project is commercially viable. · AGIA lacks specifics on key fiscal terms and other requirements. · Because of the complexity and risk associated with the project, the parties must have an efficient and impartial means of handling disagreements when they arise. Arbitration is the method used to resolve disputes under the State's Royalty Settlement Agreements. 3:16:48 PM Mr. Massey concluded that ExxonMobil is committed to the Alaska Gas Pipeline Project moving forward; however, the project cannot move forward if it is not commercially viable. AGIA, as written, does not provide for a commercially viable project. The Administration's stated goal for AGIA is to increase competition through an open and transparent process. The current AGIA form will result in less competition because it fails to adequately address the issues raised by parties who will ultimately pay for the project. AGIA appears to be based on flawed economic assumptions. The existing prescriptive terms in AGIA would preclude ExxonMobil from being able to make an open, competitive and conforming proposal. ExxonMobil possesses the financial strength and project experience required to make the project a success. He suggested that AGIA be amended to provide for a broad, objective-driven process, establishing how the State wants to achieve the goals and allows each applicant to propose how to meet the objectives and identify what is required of the project. Representative Crawford asked if the criteria were changed, would ExxonMobil then team-up with the two other major producers. Mr. Massey anticipated that they would work together, pointing out that nothing prevents submitting their own proposal. In the end, the final deal needs to be acceptable to all three majors and the State before a pipeline is built. 3:24:12 PM Representative Thomas questioned what will happen if the Administration does not accept the industry's proposal and decides to use the earnings from the Permanent Fund for financing the project. Mr. Massey stated that a decision could be made from an analysis of commercial viability and determination. 3:26:22 PM Representative Thomas inquired if ExxonMobil had amendments prepared. Mr. Massey responded that they would provide recommendations for legislative consideration. 3:28:05 PM Representative Gara suggested that the producers should take their recommendations and concerns to the Administration rather than to the Legislature. He asked how long ExxonMobil has known that they would not submit a bid under the AGIA plan. Mr. Massey indicated they have made it clear since the beginning, they would not apply under the AGIA form. Representative Gara noted for the record, he was more comfortable with the AGIA proposal and feared that ExxonMobil would not be willing to sell gas to any of the other bidders; he asked if ExxonMobil would be willing to make a public commitment. Mr. Massey proposed that the process be open and that all bids are public record. AGIA does not allow for that. At this time, ExxonMobil can not determine if they will commit their gas and will look at each proposal for commercial viability. 3:32:29 PM Representative Gara asked if Exxon would commit to sell gas to any pipeline project that provides an economic return. Mr. Massey reiterated, they would look at each project as proposed and would make a determination then. Representative Gara grilled ExxonMobil regarding withholding of gas. Mr. Massey informed members, he would want to consult ExxonMobil's attorneys. 3:34:29 PM Representative Gara agreed that a predictable, fiscal system is important. Mr. Massey maintained that in any mega project, fiscal certainty is the norm. He would not address specifics & terms. Representative Gara mentioned the 10-year tax lock-in and that it might not be enforced by the Alaska Court System. Mr. Massey commented that the State could maintain their long-range, predictable terms under the State Constitution and acknowledged it could be challenged. 3:38:16 PM Representative Kelly understood that each contract has terms and conditions; he questioned which items are of concern to the producers. Mr. Massey stated the structure is too detailed and that the State should establish objectives. He addressed the inappropriate target dates, which would lead to poor management. 3:41:17 PM In response to a question from Representative Nelson regarding deadlines, Mr. Massey responded that producers would be dictated by attempting to meet the unreachable deadline. The project will be completed at the maximum viable pace; deadlines are not necessary. Representative Kelly asked the greater issues. Mr. Massey responded that the expansion requirements are too detailed. Additionally, the rolled-in rates need work. He added that the $500 million dollars is not in the State's best interest and establishes an opportunity for those that should not be involved, to be players. Representative Kelly indicated that the $500 million dollars is not mandatory. Mr. Massey spoke to the Alaska hire, indicating that any applicant should propose how they would maximize Alaska hire; however, there must not be a Project Labor Agreement (PLA). 3:46:59 PM In response to further questioning by Representative Kelly, Mr. Massey noted the PPT gas tax rate that is too high. He observed that the Administration has acknowledged a need for predictable and durable terms; he emphasized that all terms must be predictable throughout the agreement and must occur in all forms. Representative Kelly asked when the industry needs to know about the PPT taxes. Mr. Massey replied, they must know before the project is started. 3:49:46 PM Representative Kelly asked about any "sweet deal" supported by the industry. He questioned how Exxon justified a no- agreement with a 15% floor, inquiring if that would affect the project. Mr. Massey stipulated that the 15% was not the only variable but significant. Currently, there are only 35 TCF discovered resources & 50 are needed to keep it full. There must be a structure which encourages exploration. He noted that up-stream terms will determine if & when exploration is done. 3:55:54 PM Representative Kelly asked if the PPT up-stream elements were set aside, would Exxon then accept the floor and provide bid variables. Mr. Massey advised they could not present a "commercially viable proposal" with those restrictions and that the 15% must be removed. 3:58:13 PM Representative Gara inquired if ExxonMobil operates in other places around the world that are subject to rolled-in rates. Mr. Massey commented that the difference is the significant size of the proposed project. Representative Gara asked if there was a risk for affordable, new shipper pipeline expansion. He thought there would be competing economic interests and asked if they were subject to rolled-in rate requirements for expansions around the world. Mr. Massey did not know. He said he has discussed regulating facilities throughout the United States (U.S.) and Canada. The State has available options for addressing that scenario & requires, initially, the shippers to subsidize. In dealing with the up-stream concerns, dictates if the project will move forward. Representative Gara acknowledged the State might need to adjust the gas tax; however, did not accept the industry's unwillingness to discuss lack of up-stream incentives. PPT subsidizes the gas field development cost by 42.5%. He reiterated that the incentives are substantial. Mr. Massey replied that the PPT taxes had increased and that there is no way to know the terms; without knowing the terms, the economic projection is un-determinable. 4:04:30 PM Representative Crawford realized that consumers would end up paying for the pipeline. If AGIA does not pass, perhaps the State could initiate a reserves tax. He observed that the industry has not compromised with the State. Mr. Massey agreed with Representative Crawford for a need of good-faith negotiations. He acknowledged that the project is huge, complex and involves significant risks. 4:08:37 PM Representative Kelly concurred that a deal should not happen until it is favorable for both sides. Mr. Massey stated that ExxonMobil will not give up because of the importance of the pipeline to the State, the industry and the nation, but reiterated the need for producers to have a commercially viable project. He lobbied for further consideration to open-up AGIA to a more flexible process. DAN DICKINSON, LEGISLATIVE BUDGET AND AUDIT 4:10:39 PM Co-Chair Chenault summarized previous questions received from the Administration: · How gas was taxed under the PPT and the PPT credit implications of the gasline; · Are PPT gas credits applicable to GTP in the AGIA bill; · How does PPT progressively work on gas; · What is the link to oil; and · How attractive is the pipeline using the IRR method. DAN DICKINSON, CONSULTANT, LEGISLATIVE BUDGET AND AUDIT (LBA) DIVISION, referenced the questions, indicating that gas is taxed the same as oil, on net value. When the net value is calculated, if there are investments down-stream to the point of production, they would not be eligible for the credit. In order to determine how gas is taxed under the PPT, it is important to look in five different places. AT EASE: 4:14:57 PM RECESSED: 4:15:20 PM / MAY 2, 2007 RECONVENED: 8:29:42 AM / MAY 3, 2007 DAN DICKINSON, CONSULTANT, LEGISLATIVE BUDET & AUDIT COMMITTEE, present a power point addressing answers from questions asked by the Legislative Budget and Audit (LBA) Division. The first question: • How gas is generally taxed under the PPT and what were the PPT credit implications of gasline work Mr. Dickinson stated that gas is taxed the same as oil on net value. He added that investment down-stream of the point of production is not eligible for credit. He pointed out how gas taxed occurred under the PPT and that oil and gas are taxed under five different measures: • 22.5% of net value • North Slope floor triggered by oil price • Progressivity triggered by single taxpayer net value • Private royalty @ 1.67% for gas - 1/3 of oil • Cook Inlet ceiling Representative Hawker noted that progressivity is a production tax and in addition to royalties. Mr. Dickinson said correct, pointing out that royalties are a large piece. 8:33:39 AM Mr. Dickinson added that production taxation amounts to 22.5% of the net value. To calculate net value: • Total up-stream costs deducted from the revenue streams from oil and gas sales • Gas Revenue Exclusion (GRE) mechanism provides an administratively simple way of adjusting the effective rate without changing the nominal rate or making many allocations 8:35:23 AM Mr. Dickinson directed comments to the North Slope floor, which is triggered by the oil price including an alternative floor and applicable to those prices. · In considering the future, if Prudhoe Bay is producing 250,000 bbls oil and 3 bcf of gas and · If the heating value is 1,000,000 btu per mcf, that translates to the equivalent of 500,000 bbls a day One-third of the field's production would be used to establish the trigger. 8:36:53 AM Mr. Dickinson noted that Question #3 addresses how PPT progressivity works on gas and the link to oil. Progressivity is triggered by a single taxpayer net value. • Progressivity is determined for each taxpayer on its total mix of oil and gas and all up-stream costs. • It is calculated on a monthly basis & monthly up-stream costs are one twelfth of the total annual costs. Slide 8 indicates an example of the progressivity triggered by a single taxpayer's net value with a destination value of $63.76 dollars; the gross value left to the State would be $58.76 dollars and a 2.94% progressivity percentage. He thought that gas price could "drag down" progressivity on oil. A significant influx of gas will probably reduce the progressivity paid on oil. 8:41:06 AM Representative Gara noted that at this time, there is no proposal to rewrite the PPT; he asked the value of Mr. Dickinson's presentation comparison to PPT. Mr. Dickinson stressed that there needs to be a change made to the PPT. From conversations last year, there was discussion on the comparison of distance gas to oil and assumed it was part of Question #3. Representative Gara asked if the intent was to "gear up" for another special session in order to discuss PPT. Co-Chair Chenault thought eventually that would need to be discussed. 8:42:58 AM Mr. Dickinson referenced Slide 9, which establishes progressivity charges at various destination values, including net deductions. Representative Gara inquired about the tax rate charged during those periods tax payments had been made. Mr. Dickinson could not respond. 8:44:15 AM Mr. Dickinson highlighted the private royalty amount of 1.67% of the gross for gas. The Cook Inlet area has specific ceilings: • With no direct effect on North Slope gas; • Expiring in 2022; • If a gas line is built from the North Slope to Cook Inlet, it could effect the differential taxation rates; • A ceiling is potentially different for each producer, with an average of 4.947% of $3.585 per mcf. 8:45:29 AM Mr. Dickinson pointed out that Slide 12 addresses Question #2, regarding PPT gas credits being applicable to the GTP in the AGIA bill, and that under the PPT, the GTP was not eligible for the credits. He added there are only up-stream costs qualifying as credits indicated in AS 43.55.023 (a), AS 43.55.023 (k) & AS 43.55.165 (a). Mr. Dickinson addressed "point of production", noting those areas are defined so that the gas processing is up-stream of the point of production and gas treatment is down-stream of the point of production. • In AS 43.55.900 • (21) gas processing • (23) gas treatment • (27) point of production 8:47:16 AM Mr. Dickinson provided the definitions from Statute (AS 43.55.011(27) of the point of production for oil: • (i) not subjected to or recovered by mechanical separation or run through a gas processing plant, the first point where the gas is accurately metered; • (ii) subjected to or recovered by mechanical separation but not run through a gas processing plant, the first point where the gas is accurately metered after completion of mechanical separation; • AS 43.55.011(27) "point of production" means • (B) for gas; • (iii) run through a gas processing plant, the first point where the gas is accurately metered downstream of the plant; • (C) for gas run through an integrated gas processing plant and gas treatment facility that does not accurately meter the gas after the gas processing and before the gas treatment, the first point where the gas processing is completed or where gas treatment begins, whichever is further upstream. AS 43.55.011 (21) provides definition of gas processing: • (A) means processing a gaseous mixture of hydrocarbons; • (i) by means of absorption, adsorption, externally applied refrigeration, artificial compression followed by adiabatic expansion using the Joule-Thomson effect, or another physical process that is not mechanical separation; • (ii) for the purpose of extracting and recovering liquid hydrocarbons [producing ngls/oil]. The PPT definition for gas treatment is found in AS 43.55.011 (23): • (A) means conditioning gas and removing from gas non- hydrocarbon substances for the purpose of rendering the gas acceptable for tender and acceptance into a gas pipeline system. • (B) includes incidentally removing liquid hydrocarbons from the gas. Mr. Dickinson referenced Slide 20, which defines gas treatment, language taken from AS 43.55.011 (23): • (C) does not include - (i) dehydration required to facilitate the movement of gas from the well to the point where gas processing takes place; - (ii) the scrubbing of liquids from gas to facilitate gas processing. He continued that under current law: • Gas Processing: Starts with gaseous mixture of hydrocarbons, producing natural gas liquids and gas by removing hydrocarbon liquids. • Gas treatment: Starts with produced gas and removes non-hydrocarbons to prepare the gas for tender to the pipeline. Nothing is produced. 8:49:29 AM Mr. Dickinson explained that Slide 22 demonstrates the definition of gas processing taken from AS 43.55.900 (7) "Gas processing" means the treatment of gas downstream of the point of production to extract natural gas liquids"; & AS 43.55.900 (7) "Gas processing" means post-production treatment of gas to extract natural gas liquids". Mr. Dickinson pointed out the AGIA definitions of gas processing found in AS 43.55.900 (7) has the same meaning as "gas processing" in AS 43.55.900 (21). He noted the graph on Slide 24 of the PPT point of production chart for gas. 8:53:51 AM Mr. Dickinson stated that if gas simply comes out of the ground, the point of production is measured from where it comes out, the first time. If there is a mechanical separation, it is again, the first point measured after mechanical separation. He referenced Slide 27, indicating a gas processing plant. Slide 28 is the most important focus, the integrated gas processing and treatment plant, with a point of production furthest up-stream, where either treatment begins or processing ends. Slide 29 indicates the Prudhoe Bay point of production under the PPT, central gas facility. 8:56:31 AM Mr. Dickinson explained that if CGF remains a separate plant and sends gas to a Gas Treatment Plant (GTP), gas would be produced as it is metered out of the plant. The GTP would be down-stream of the point of production for the gas and, thus, associated operating and capital costs would not qualify as lease expenditures under AS 43.55.165 (a) nor would capital costs qualify for credit treatment under AS 43.55023 (a). 8:58:13 AM If CGF remains integrated into a gas treatment plant (GTP) (produced gas is not metered), then the gas would be produced within that integrated facility, at the furthest point up-stream of the beginning of gas treatment or the end of gas processing. If the plants are integrated, the risk is that some gas processing will move downstream of the point of production, not that gas treatment will move up- stream of the point of production. Slide 35 uses Prudhoe Bay as the point of production under the PPT with an integrated GTP. If the two processes were to become intertwined or integrated, the point of production would move into the central gas facility, up-stream. As currently written, the law protects from situations where gas treatment plants are eligible for up-stream credits. 8:59:29 AM Mr. Dickinson discussed Question #4, regarding a determination of how attractive an investment pipeline would be. Previous testimony by Antony Scott, Commercial Analyst in the Department of Natural Resources, indicated that by using the IRR metric, the project could have high rates of return particularly, when a third party line is involved. That would not include the cost of the shippers' transportation commitments when comparing the independent pipeline with a producer owned pipeline. The question surrounds how that could affect the results. 9:00:14 AM Mr. Dickinson addressed the firm transportation commitment. • The shipper makes a transportation commitment (FT) to pay the capital portion of the tariff whether they use the pipeline or not. • It is that financial commitment that underwrites the pipeline: - Required by FERC before approving a project and - Required by lenders before lending money to a project. 9:02:52 AM Representative Gara commented that the shipper only cares about the costs of getting the gas out of the ground, shipping it and knowing what the tariff is. Once costs equal the tariff, the shipper's costs are free. He referenced previous comments made by Mr. Scott. Mr. Dickinson noted the figures in doubling the internal rate of return (IRR). [Addendum Page #7 & #9]. Vice Chair Stoltze asked if it was fair that no negative rate of return had been indicated, only profits. Mr. Dickinson agreed; however, pointed out that there have been negative rates of return and that a low rate of return is enough to "kill" any project. Representative Gara noted that in last year's proposal, the State was responsible for selling the gas. In the current proposal, the producers will be selling that gas and the risk of low prices has taken precedence. An entity could make a lot more money if they are both producing and pipeline owners of the gas, but the profit margins decline. The profit margins on production are higher and combining the two makes more absolute money. Mr. Dickinson pointed out that the attached slides indicate the opposite. Vice Chair Stoltze observed that Mr. Scott had rolled-in the risk factor into the model. Mr. Dickinson disagreed. 9:09:01 AM Mr. Dickinson provided an overview of the following slides, which demonstrate the internal rate of return (IRR): · Slide 40 - Calculated IRR at various price levels · Slide 41 - The IRR on a model of an owned project · Slide 42 - The IRR for a model capital component of tariff rd · Slide 43 - The IRR model 3 party line with no FT but with a tariff rd · Slide 44 - The IRR model 3 party line with some additional capital rd · Slide 45 - The IRR model 3 party line with even more additional capital rd · Slide 46 - The IRR model 3 party line with even more additional capital 9:16:50 AM Representative Gara understood that the FT was a significant cost to the producers. Last year, under the proposed PPT contract, the State had to cover 12.5% of the FT commitment - royalty in-kind. No one mentioned that could be a very risky cost to the State and asked Mr. Dickinson why it had not been indicated at that time. Mr. Dickinson responded that had been a 20% commitment for the FT. He agreed that it had been very risky and that he was sorry that it had not been identified. Representative Gara acknowledged that he had known it was risky and had asked those questions. Mr. Dickinson responded that the State concluded it was a risk the State could assume. 9:20:08 AM Mr. Dickinson continued, Slide 47 addresses the disclosure of long term obligations. The statement requires that an enterprise disclose commitments under unconditional obligations that are associated with suppliers financing arrangements. Such obligations are often in the form of take-or-pay contracts and throughout. Slides 48-51 provide examples of disclosure. 9:23:44 AM Mr. Dickinson referenced Slide 53, using a financial statement from BP, listing the unconditional purchase obligations, representing any agreement to purchase goods or services, enforceable and legally binding and specifying significant terms. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas feed-stocks and pipeline systems. The obligations are set out for five year periods of time. That information is required for disclosure. Slides 55 - 59 explain why that information matters to companies [listed below] who sell their investment services: · Moody' Investors Service · Standard and Poor (S&P) 9:27:34 AM Mr. Dickinson summarized by reading from an article written in the 1980's from the magazine "Society of Petroleum Engineers", addressing the perspective of people within a company, making errors in an analysis. Mr. Dickinson pointed out that even within the large companies, there is discussion regarding "creative financing solutions"; typically involving a lease like structure and not representing the true costs to the company. Instead, when those types of commitments are made, they need to be properly valued. He suggested that when the high rates of return are indicated, it could be because costs of the FT commitment are not properly valuated. 9:29:40 AM Representative Gara referenced comments made previously by Mr. Scott regarding the profitability analysis. Mr. Dickinson attempted to demonstrate how that presentation omitted the rates of return. Representative Gara questioned the accuracy of the proposed number. Mr. Dickinson suggested that there are problems with any analysis recommending avoidance. He encouraged FT be incorporated correctly. Representative Gara stated that it will be a profitable project at those prices and asked if Mr. Dickinson would dispute that. Mr. Dickinson acknowledged that it could be profitable, however, challenged the idea that it is "wildly" profitable. Representative Thomas believed that in theory, the State owns over 12 years worth of gas in Prudhoe Bay and asked why the State should not own those rights. Mr. Dickinson responded that such questioning was "treading on legal ground". The State of Alaska owns 12.5% of the hydrocarbons produced - when they come out of the ground. Mr. Dickinson advised that there are two aspects and one is putting the gas back into the ground, which helps the oil flow. The State receives 12.5% of those benefits. The State does not own any percentage until the gas is actually produced. 9:35:08 AM Co-Chair Chenault referenced Slide 42, inquiring how to identify the 10% interest charge on the FT. Mr. Dickinson explained that the assumption was using some information from the model. By using any arbitrary number & placing it into the formula, changes the payment amount. Representative Kelly asked 10% was the combined interest rate and profit. Mr. Dickinson replied it is. 9:36:37 AM HB 177 was HELD in Committee for further consideration.