ALASKA STATE LEGISLATURE  JOINT MEETING  SENATE RESOURCES STANDING COMMITTEE  SENATE SPECIAL COMMITTEE ON ENERGY  March 17, 2010 3:39 p.m. MEMBERS PRESENT  SENATE RESOURCES Senator Lesil McGuire, Co-Chair Senator Bill Wielechowski, Co-Chair Senator Charlie Huggins, Vice Chair Senator Hollis French Senator Bert Stedman Senator Gary Stevens Senator Thomas Wagoner SENATE SPECIAL COMMITTEE ON ENERGY Senator Lesil McGuire, Chair Senator Bert Stedman Senator Bill Wielechowski MEMBERS ABSENT  SENATE RESOURCES All members present SENATE SPECIAL COMMITTEE ON ENERGY Senator Lyman Hoffman Senator Albert Kookesh COMMITTEE CALENDAR  OVERVIEW: SB 143 - RAILBELT ENERGY & TRANSMISSION CORP - HEARD SENATE BILL NO. 301 "An Act relating to the power project fund; authorizing the Alaska Energy Authority to charge and collect fees relating to the power project fund; authorizing the Alaska Energy Authority to sell and authorizing the Alaska Industrial Development and Export Authority to purchase loans of the power project fund; providing legislative approval for the sale and purchase of loans of the power project fund under the memorandum of understanding dated February 17, 2010; and providing for an effective date." - MOVED SB 301 OUT OF COMMITTEE AGIA Regulations presented by the Department of Natural Resources - HEARD PREVIOUS COMMITTEE ACTION BILL: SB 301 SHORT TITLE: POWER PROJECT FUND SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 02/26/10 (S) READ THE FIRST TIME - REFERRALS 02/26/10 (S) RES, FIN 03/15/10 (S) RES AT 3:30 PM BUTROVICH 205 03/15/10 (S) Heard & Held 03/15/10 (S) MINUTE(RES) 03/17/10 (S) RES AT 3:30 PM BUTROVICH 205 WITNESS REGISTER JAMES STRANDBERG, P.E., Project Manager Alaska Energy Authority (AEA) Anchorage, AK POSITION STATEMENT: Supported SB 143. ANTHONY SCOTT, Commercial Analyst Division of Oil and Gas Department of Natural Resources (DNR) Anchorage, AK POSITION STATEMENT: Presented AGIA regulations for the DNR. MARTY RUTHERFORD, Deputy Commissioner Department of Natural Resources (DNR) Anchorage, AK POSITION STATEMENT: Presented AGIA regulations for the DNR. FRED HAGEMEYER Black & Veatch, Corporation consultant POSITION STATEMENT: Presented AGIA regulations for the DNR. DEEPA PODUVAL Black & Veatch consultant POSITION STATEMENT: Presented AGIA regulations for the DNR. ACTION NARRATIVE 3:39:38 PM CO-CHAIR WIELECHOWSKI called the joint meeting of the Senate Special Committee on Energy and the Senate Resources Standing Committee to order at 3:39 p.m. Present at the call to order were Senators Huggins, Stedman, Wagoner, Stevens, French, McGuire, and Wielechowski. ^Overview: SB 143-RAILBELT ENERGY & TRANSMISSION CORP.  CO-CHAIR WIELECHOWSKI announced the first order of business would be an overview of SB 143, also known as the GRETC bill (Greater Railbelt Energy Transmission Corporation). 3:40:33 PM JAMES STRANDBERG, P.E., Project Manager, Alaska Energy Authority (AEA), said he had 11 power point slides that he hoped to use to summarize the work the administration in cooperation with the Railbelt utilities has done to date with the Railbelt G&T (generation & transmission) restructuring effort and what the new corporation is all about including its initial tasks - should this bill pass. He said last year he appeared before them with a very different GRETC bill. At the end of that session the bill was held in this committee at the request of the Railbelt utilities that wanted to take a year and involve all the boards of directors for the utilities in a task force to make the plan more responsive to their needs. They came up with a committee substitute (CS) to SB 143 that has major support within this utility group. His agency, the AEA, working with the Governor's office participated in the majority of these task force meetings and acted as both advisor and observer as the work on the bill progressed through the summer. The Attorney General's Office provided a representative as well to assist in drafting changes to the legislation. They are awaiting the CS from the drafters. He said the fiscal note will be reduced generally because they have taken a hard look at the requirements for forming the business and with the new framework there is a lesser fiscal requirement. That is also forthcoming. MR. STRANDBERG said that AEA accomplished the REGA Study to understand the economics of regional G&T organizations, and that study found that forming a GRETC-like company could save ratepayers significant money through reduced rates over the long term. AEA also completed a regional plan for future generation transmission projects (RIRP) in the late fall, which indicated several things that add to the urgency of forming a regional entity such as GRETC. First this study defined critical near term projects that a unified G&T company should take on from critical fuel supply projects to near term transmission projects to needed generation additions. It also identified a critical capital shortfall where the cumulative capital needs for the region are much larger than the abilities of the Railbelt utilities to raise capital for projects defined in the RIRP. This plan concluded that a GRETC or GRETC-like unifying organization with state financial backing is the best approach to achieve a future of reliable and affordable electric service. It would save the ratepayers a lot of money over the long run and forming that entity will give them the ability to meet the capital needs of the future. Without that they will have a very hard time raising money. 3:46:13 PM He said he would next explain how the CS is different from the original bill. He developed four topics in his summary: the governance of the new company, the powers of the corporation, external controls for the corporate activities and a discussion of the initial tasks for GRETC. The key points of the Board of Directors make up are: · The corporation is a private not-for-profit entity (not a state corporation). · Each of the six Railbelt utilities regardless of size, generating capacity or transmission line ownership, will have two board members and two votes. · GRETC has 6 public utility members and 12 board members; it has one public member that is appointed by the Governor from a list of three candidates supplied by the public utility members. Public utility members do not have terms of service, but the public member has a four-year term. The board will be required to designate a chief executive officer. 3:47:40 PM Types of business GRETC can undertake: · Providing wholesale power to its Railbelt customers (one of the distribution utilities that would buy wholesale power.) No retail customer relationship. · Providing wholesale power is at the center of the corporation's purpose and GRETC can undertake a considerable number of tasks to generate and sell its wholesale power that are allowed under the new language in the bill. 3:48:27 PM MR. STRANDBERG said GRETC is now a voluntary organization similar to the JAA effort that was made several years ago, but there are significant differences in approach now (slide 8). CO-CHAIR WIELECHOWSKI asked why it is in the best interest of consumers to have an all volunteer corporation. MR. STRANDBERG answered to get to the goal of becoming a unified operation their studies have indicated companies need significant flexibility to make mid-term agreements so that two utilities can have agreements but still participate in GRETC. They believe through state funding they will have the ability to channel the organization more towards the unified organization. Extensive conversations with the utilities on these matters have revealed an understanding that they need the flexibility now to really take up the issues in the Railbelt, as well as a need to focus over the long run into a tighter integration. 3:52:19 PM MR. STRANDBERG said that GRETC is now much more flexible so utilities can act to meet the future wholesale power needs of their regions. One point is that utilities under this statute really can undertake their own projects, approach GRETC for power supply or do any number of arrangements for providing wholesale power. A critical difference is that the earlier bill's intent was that the company would evolve towards being an all-requirements provider for wholesale power in the Railbelt. That language has been left out of the CS that rather provides the flexibility to make different arrangements. Another difference is that GRETC now has the Railbelt Integrated Resource Plan (RIRP), last year it didn't. Another critical difference is that four utilities now must agree to join GRETC before it can actually form. SENATOR WAGONER asked if Homer Electric were to join this organization, would its administration would have to go to the annual meeting. MR. STRANDBERG answered yes; the commitment would have to be approved by their board. SENATOR WAGONER said "Good luck," because he knows the politics of the situation in his area. MR. STRANDBERG said participating with boards' members has been a very interesting and positive process over the past year. This flexible platform is what all the groups as a whole saw would allow them to get through their board processes and really begin unifying over the long haul. CO-CHAIR WIELECHOWSKI said he understood that all the utilities support the CS. MR. STRANDBERG said that is correct. 3:55:05 PM He went to the External Controls in slide 9 saying a lot of people have talked about rate regulation and the RCA issues. AEA sees a definite need for oversight for consumer protection as well as financial oversight to make sure the company is managing money correctly, particularly if the state is going to back it in some way. The third thing is to make sure the corporation is actually doing its job. The significant protections in the CS include: RCA economic rate regulations which would sunset at the end of five years unless the legislature took further action. Also included is a requirement for a management audit done in accordance with the National Association of Regulatory Utility Commissioners (NARUC) standards. 3:56:59 PM The near term tasks for GRETC (slide 10) are: forming the company, getting the legal documentation together, and hitting the ground running and actually starting the work. AEA has accomplished the RIRP which is being provided to the utility for GRETC for its consideration as it starts up its operations. The plan has a priority list of projects, business functions and contractual agreements that need to be accomplished. The AEA has spent a lot of time over the last three years working with the utilities with this plan, and clearly utilities take issue with things like committed units. So, their expectation and hope is that utilities will take the plan to heart. Finally, the CS has the requirements to develop a capital improvements plan and a financial management plan. Last, there is a critical need to begin generation of transmission projects in the Railbelt. 3:59:02 PM SENATOR HUGGINS said he implied phases, but he didn't see that broken down anywhere and asked if he had that somewhere. He thought Mr. Strandberg was expecting this to change over time; and that is implied in the sense that the RCA goes away at the end of year five. MR. STRANDBERG said the first five years will be very critical. They need to induce the utilities to provide their board members to come to the table and actually meet and create bylaws. They will have to hire a CEO, and certainly, if there are major projects and the utilities actually come to the table and begin to do major projects with this company and the state begins to pour money into that, they are going to need to get the external controls going right away. A major amount of oversight is necessary in these formation phases of the company and likely there will be a need for agency involvement "to make sure public benefit flows." SENATOR HUGGINS said he had discussed four big debate points so far and asked if any are remaining. MR. STRANDBERG said the RCA was a major sticking point. Utilities wanted to be able to continue making near term arrangements for power. There was concern that if utility operations were consolidated, one group of ratepayers could end up paying more when another group was paying less. There was concern that the evolution to an all requirements provider was too constraining and it didn't really reflect some of the arrangements that would be need to be made in the near term. SENATOR HUGGINS said it appears the business of being able to develop projects outside of GRETC by one of the members is a fracture waiting to happen. MR. STRANDBERG said that is always a possibility. If all the utilities can't see an economic incentive to unified operations under this arrangement it is likely that bilateral contracts will continue. This corporation will be a success if the utilities can see economically that it's to their benefit to unify. CO-CHAIR WIELECHOWSKI said it's an interesting balance they are trying to achieve. Finding no further questions he ended the Senate Energy portion of the hearing and announced an at ease from 4:04-4:05 p.m. SB 301-POWER PROJECT FUND   4:05:13 PM CO-CHAIR WIELECHOWSKI called the Senate Resources portion of the meeting to order at 4:05 p.m. He announced SB 301 to be up for consideration saying it's a good bill and he had held it over to give members the opportunity to review it over the weekend. CO-CHAIR MCGUIRE moved to report SB 301 from committee with individual recommendations and attached zero fiscal note(s). There were no objections and it was so ordered. 4:07:40 PM at ease (projector difficulties) 4:08:49 PM ^Update: AGIA Regulations by the DNR CO-CHAIR WIELECHOWSKI called the meeting back to order at 4:08 p.m. and said the next order of business would be an update on AGIA regulations by the DNR. ANTHONY SCOTT, Division of Oil and Gas, Department of Natural Resources (DNR), said the first part of the presentation is the valuation principles of natural gas. He would then step through an example of how they would actually value royalty gas under the regulations - a little more complicated process than what they saw last week with the Department of Revenue (DOR). He would also talk a little bit about the RIV/RIK switching problem for the state's producers under the lease and the solution they are proposing in the regs. Finally, Deepa Poduval, Black & Veatch consultant, will give them a sense of the range of values that are provided to the qualifying lessees (producers) who choose to amend their leases under the regs. MR. SCOTT said that the public comment period would close on March 22, so he has to be sensitive to honoring that process in treating everyone fairly. 4:09:37 PM He said that gas is complicated because how it will be valued has to be clarified and then existing lease terms will have to be modified to eliminate initial shipper exposure associated with the cost of transportation on the mainline. An important difference in these regulations compared to the DOR regulations is that if a lessee qualifies, he may chose to amend his leases and have his gas valued under these regulations. If he doesn't like this framework, he doesn't have to have his gas valued in this way. This is not something they can impose on lessees. Similarly, they cannot impose the royalty switching provisions on lessees; that is something they have to elect. They can elect the valuation provision, the switching provision or both. CO-CHAIR WIELECHOWSKI asked him to describe a lessee who qualifies for royalty inducement. MR. SCOTT replied a lessee must commit to acquire firm transportation (FT) in the initial open season of the AGIA licensed project to have his gas valued under these regulations. The qualification language is exactly the same to get in the door between both DOR and DNR. 4:14:03 PM He said Valuation regulations (slide 4) must: minimize retroactive adjustments in royalty value, establish fair market value (FMV) based on reliable trade publications, allow actual and reasonable deductions for transportation and processing, allow reasonable share of unused capacity. So if an initial shipper acquires capacity and he doesn't have enough production to fully fill it the state would pick up a reasonable share of that empty capacity and allow deductions under the 1980 royalty settlement agreement. MR. SCOTT said crafting regulations to meet all these requirements is not as easy as they first thought. There are complications like trying to protect the state and the lessee while minimizing retroactive adjustments while first gas is 10 years in the future. So they came up with basing royalty value on reliable trade publications as opposed to looking to actual sales. Trade publications are public; you can look them up and know what your royalty value will be. However where the sales are occurring can't be traced; so there is uncertainty about exactly where gas was marketed and how it should be valued given they can't be sure what they might have received for it and what they might have received for it may come apart, importantly, from what the trade publications are. 4:16:03 PM He said that allowing reasonable and actual deductions for transportation and processing is quite a complication. One of the reasons is because it means they can't simply deem one price as the basis for determining all value by assuming all the gas will go to the Alberta (ACCO) market, for instance. The problem is that Alaska gas may never enter into the ACCO market, but may interconnect with, for example, the Alliance pipeline and move on into Chicago. Because the statute says that you get your actual and reasonable cost of transportation, the lessee gets to deduct their actual and reasonable cost of transportation to Chicago. So, you wouldn't want to value gas in Albert but allow a transportation deduction all the way to Chicago. Allowing a reasonable share of unused capacity? Define standards for what is reasonable, he said. They have done that in what they think is a fair manner, but there were a lot of things to sort through to get there. 4:16:50 PM MR. SCOTT said gas markets are inherently more complicated in terms of valuing ANS hydrocarbons than oil, which is relatively straight forward. It gets produced on the North Slope, it goes down TAPS, it's loaded on to tankers that are dedicated to the ANS trade, and they go to refineries on the West Coast. You know where the oil is going to a considerably high degree of certainty. And you know where your markets are. In the case of gas that's not true. First of all they don't know exactly what the infrastructure will end up being. They don't know what will get built. So, clearly they don't know exactly where it will go - not to mention that first gas is 10 years out. Even then, gas may directly flow from this project into Alberta, into Sumas, Washington, and go down the West Coast pipeline and bypass the ACCO market. ANS gas may bypass the Alberta market and go into Chicago. Further they have to recognize that individual molecules of ANS gas may be consumed in Oregon or New York City, because North America has an interconnected pipeline grid where molecules are comingled. So, you have to come up with standards and rules about how you're going to cut that process off for valuation while also allowing actual and reasonable costs. MR. SCOTT said that meanwhile the gas business is dynamic. Twenty-five years ago natural gas prices were regulated at the wellhead. The transportation infrastructure was regulated quite differently. The markets were dominated by large transmission pipelines that purchased the gas at the wellhead and sold it to consumers. Today it's very different, but the point is that was only 25 years ago and they are trying to develop a framework that will be robust for a very long time. 4:19:07 PM An additional complication is that the North Slope gas will vary by quality from one property to the next (slides 5 & 6). The composition of the gas at Prudhoe Bay is different than the composition of the gas at Pt. Thomson. But not only are those streams being comingled, streams from other systems, quite possibly from the British Columbia and Alberta - all of which has different compositions - will be comingled, and the composition of the gas has value. The gas that comes out of the ground will have a different value for the lessee based on its composition. So, if the lessee receives differential value, the statute directs the state to try to obtain that value as well. Finally, allocating processing costs is complicated. The statute says you get processing costs, but in this particular slide (6) you may well have multiple processing plants in a given location, and how do you allocate the costs of those different processing plants to Alaska gas which is also comingled with gas from many other sources? These are the kinds of complications they faced in putting these regulations together in a way that treats all parties fairly. MR. SCOTT said the legislature was wise when it passed AGIA that directed them to promulgate these regulations; the state does not have valuation regulations for gas outside of AGIA. He said that real money is at stake based on the particular molecular composition of the gas that comes out of the ground (slide 7). No party wants to be deprived of the opportunity to get what their due is either as a royalty lessor or as a lessee. He then turned the discussion over to Marty Rutherford. 4:22:52 PM MARTY RUTHERFORD, Deputy Commissioner, Department of Natural Resources (DNR), said she would speak to the overarching policy principles some of which are embedded in these draft royalty regulations: (slide 8) Overarching Principles: 1. Reduce lessee uncertainty 2. Maintain state's full royalty value (in statute) 3. Incorporate natural gas industry practices to the extent that doing so is consistent with (1) and (2) 4:24:21 PM She explained that the first two goals especially have a degree of tension. They want to provide as much administrative ease and clarity as they can while also ensuring that the state doesn't make any assumptions that turn out to be very wrong and cost the state substantially down the road; it has happened. (One example will be discussed later on how the 1980 field cost settlement at Prudhoe Bay will actually affect the cost of the gas to the state.) She noted that not completely locking a royalty value scheme can also benefit the lessees. The requirement of the statute is to maintain fair market value and they think the regs have done that. The effort to incorporate gas industry standards themselves stems from a desire to map the valuation scheme to the extent they can on how it will be necessary for the lessees to account and manage their gas flows. The department's goal is for them to be able to use their existing gas marketing and accounting systems to the extent possible while also complying with the AGIA royalty valuation provisions - and frankly they are hopeful that having normal industry practices embedded in the regulations will also reduce room for future disputes. 4:24:59 PM SENATOR FRENCH asked how the department measures and keeps track of all the gas streams coming into some inlet header to the new gas treatment plant (GTP). Is that taking place upstream of that facility? MS. RUTHERFORD answered yes; it is done from the unit as it enters into the GTP. 4:26:23 PM She said the overarching principle addressed in slide 9 is to reduce uncertainty by: 1. Eliminating "higher-of" lease valuation terms 2. Establishing value based on published prices 3. Minimizing or eliminate retroactive adjustments 4. Allocating volumes pro rata to increase clarity of gas value and costs of transportation and processing This does not mean that the lessees will know what they will pay in royalty 30 years from now. Trying to do that would be ridiculous because of the differences in regulation, markets and knowing that regulations change over time. But what it does mean is that in any given month the lessee and the state will know what the royalty value will be for that month and what needs to be paid. Some of the details for how that is done will follow, but achieving this principle is not trivial whatsoever. It is a substantial change from where they are today, she said, and it promises also to reduce litigation that has been a constant so far on gas issues. 9  CHAIR WIELECHOWSKI asked her to explain what "eliminate higher- of lease valuation terms" means. She explained that the current leases require lessees to pay on the highest value of three different measures. In practice that means that a lessee doesn't know what it should pay in a given month because that is a function of what other lessees receive in value as well. In other words, of three different lessees getting value for the same oil, whichever lessee gets the most money, that is the basis for the lessees paying their royalty value. It's a retroactive calculation. CO-CHAIR WIELECHOWSKI asked for an example. MS. RUTHERFORD explained for instance the three major producers are producing oil from the same unit; they go to the market. BP has an exceptionally good marketing strategy; they receive a higher value for their oil or for their gas. And in the current lease structure the state bases its royalty returns on that higher value, which means that everybody will make an estimate or maybe use their own returns as the basis for paying their royalty in a given month, and once they go back and do an accounting of it and audit the other firms, they will owe some additional monies to basically bring the into alignment with the highest amount of value received. CO-CHAIR WIELECHOWSKI asked if the proposed regs eliminate that. MS. RUTHERFORD answered yes, in fact they go beyond the minimum requirements of the statute by eliminating the "higher-of" value and they replace it with a system that allows the lessee to know by very transparent and objective measures what its royalty obligations for the current month are. Under the current lease contracts, it could be several years before all the lessees know through audit what their royalty obligation was previously and they would have retroactive payments to make. CO-CHAIR WIELECHOWSKI asked if this is being eliminating for gas only or both oil and gas. MS. RUTHERFORD replied this would be for gas. CO-CHAIR WIELECHOWSKI asked if she had any estimates of what sort of loss this will be to the state. MS. RUTHERFORD answered yes; Deepa Poduval would talk later about the values they believe are being conveyed through these regulations to lessees who choose to accept this valuation and royalty switching methodology. 4:29:18 PM CO-CHAIR WIELECHOWSKI asked if this is an option they are giving to the producers. MS. RUTHERFORD answered yes. Because the state's leases are contracts, they cannot impose this upon them and at the end of the day they can choose whether or not they like this methodology - valuation of transportation costs and switching higher-of - better than their existing contract requirements. 4:30:00 PM She said they also established the value based on public prices. The regulations propose relying only on published prices to establish a destination value. These published prices are knowable by both the lessee and the state. They have also recognized that published prices evolve over time and expect that will continue in the future years. The regulations contain a provision to insure that as the publications or their reliability change the regulations can be amended, but in no instances will there be retroactive adjustments to the prices once that is established by designated publication. CO-CHAIR WIELECHOWSKI asked if these regulations apply for the entire duration of the gas pipeline or do some of them apply only to the 10 years under AGIA. MS. RUTHERFORD replied that they apply to the gas that is committed in the initial open season - for the duration of how long that throughput occurs. CO-CHAIR WIELECHOWSKI asked again for clarification if these regulations apply to gas from the initial open season. MS. RUTHERFORD said these regulations apply for the entire duration. "As long as that gas that qualifies in the initial open season continues to flow through the AGIA pipeline then they will have the benefit of these alternative regulations, should they choose them." 4:31:56 PM SENATOR STEDMAN asked if a company answers the initial binding open season and has a 20-year commitment, is it normal for them to have extensions beyond 20 years or would this arrangement last for 20 years plus any extensions. MR. SCOTT said the regulations would apply to the initial 20- year contract period. The open season offering right now contains options for extension. So a shipper could sign up for a 20-year contract with a 5-year option to extend, but the regulations would apply only to the 20 years. If they sign up for a 25-year contract, the regulations would apply for valuation for that 25 years. Options to extend are not included within the scope of the valuation regulations. CO-CHAIR WIELECHOWSKI asked if they are still trying to encourage producers to come in at the initial open season and bid gas for the duration of the pipeline. MS. RUTHERFORD replied yes. These were the inducements that were embedded into AGIA - the tax inducement on gas and the royalty inducements. These regulations flesh out what that looks like in application. MR. SCOTT explained that it is fair to say that their burden isn't that they want people to sign up for exceptionally long contracts, but rather in exchange for making a commitment in the initial binding open season they get some benefits. Once the project is launched, then the need for the state to provide inducements for extensions is different. It basically preserves some options for the state to renegotiate whatever deal it wants to. MS. RUTHERFORD said the assumption is that the project will be capitalized based upon that initial throughput, so there won't be the same requirements for the state to provide as much value exchange at a later open season. 4:34:38 PM They tried to carry the principle of minimizing retroactive adjustments through and making revisions to the key concepts underlying royalty value. For example, if a publication changes or if an appropriate location or quality differential changes, they don't go back and recalculate royalty. The regulations have a strong emphasis on identifying forward-looking values instead of retroactive. 4:35:17 PM She said there is no way to identify the molecules that are moving through the pipeline in terms of allocating volumes. So, they have established pro-rata allocations to prevent either party, the state or the lessees, from gaming this issue and to ensure that both are treated fairly. This means that there is a recognition that North Slope qualifying gas will only be part of the total gas stream that reaches the market. The value will go in various directions, and rather than attempting to trace molecules which is impossible or worse, have the state really do what it is currently doing - determine that one company's marketing strategy is better than another's, they have landed on a policy where on a pro rata basis an individual's quantity of gas is proportionately spread across all the markets they might utilize. This is only for the purposes of royalty valuation. These rules are very clear and minimize the scope of dispute - hopefully limiting litigation going forward. SENATOR FRENCH asked how they do that if gas goes to tidewater. MS. RUTHERFORD said they are not speaking here about LNG valuation and have given themselves a bye in it within the regulations because there aren't any clear market indicators to use at this time. MR. SCOTT added that today some trade publications publish prices that give some indication, but nothing reliable that are indicative of LNG values landed in Japan. The market for LNG isn't as mature as the North American market. But that said, they didn't completely throw up their hands. If there were an LNG cargo shipped today that went to Japan they have an approach for valuation, but it doesn't honor all of the same principles. They wouldn't rely on industry trade publications, for instance. They will if they can, but it will depend on where the gas goes. If the cargo goes to Baja, they could establish value on the basis of reliable trade publications in Southern California with an appropriate location differential. If the cargo was going to Japan they would have to do something different. Provisions in the regulations address that. 4:39:10 PM SENATOR STEDMAN said the state loses flexibility after May 1, the date of the initial open season. Assuming someone comes in and fully subscribes to a project that takes it to tidewater with the intent of LNG exports to China or somewhere that could handle the capacity (Baja is not one of them), and asked what position is the state in after May 1 to deal in the regulatory environment with the flexibility restrictions. MR. SCOTT answered that statute provides for changing regulations subject to market conditions to achieving fair market value. In fact the statute actually says that the commissioner has an obligation to revisit the regulations every two years to ensure that they are achieving fair market value. So, a lessee who intended to ship their gas to China would not have the same degree of flanged up clarity in terms of how the state would approach their problem, because it's not mature yet. If it were going to China, they would probably eliminate the "higher-of" but they would base royalty on their arms length sales in China. So there would be one measure of value under the lease and it would be their arms length sales, because there aren't widely available industry trade publications. If those evolve and they were able to get there then they would have the opportunity no less than every two years to address that. 4:41:36 PM SENATOR STEDMAN asked for a 30-second blast on where they are in the regulations dealing with a large export possibility. A couple of years ago it seemed rather unlikely, but today it seems less unlikely. MS. RUTHERFORD replied that the regulations provide for either option equally. Should the project move to an LNG line into Valdez, one alternative in the AGIA licensee project proposal, then the regulations have adequate coverage to allow them to value the royalties during the two years that will begin the process of establishing a viable market to whatever locations they take the gas. And the state has the responsibility to determine whether their regulations are capturing fair market value every two years. She said the Canadian market has more data available to use for valuation, but either alternative can be accommodated through the regulations. MR. SCOTT added that a number of aspects of the regulations apply equally to both - in terms of how transportation deductions and unused capacity commitments are handled, how non- arms length costs of various plants - and either liquifaction or re-gas facilities if those are owned within the chain - are handled. The destination value piece is a little harder for LNG in terms of widely available reliable industry trade publications, but other than that piece they are "pretty well flanged up." 4:44:36 PM SENATOR HUGGINS recalled they have "watered down" the term "maximize the benefit of the resources" in AGIA by adding the term "reasonably" and it appears to him that this is one of the reasons. It is an interesting concept if constitutionally they are supposed to "maximize" but now we're "reasonably maximizing," which lowers the value. MR. SCOTT said he didn't recall language around "maximize," but there certainly is language around "reasonable share of transportation deduction." SENATOR HUGGINS commented that they debated that extensively. MS. RUTHERFORD stated that the constitution provides to maximize consistent with the public need, and what they have done is within those parameters, because they still have to obtain fair market value. Existing lease contracts provide that when one competitor does better than another the State of Alaska benefits from that improved marketing situation through its royalties. She didn't think there was a constitutional issue as long as they are still within the fair market parameters. 4:46:14 PM She said slide 11 illustrates the full value under the lease. To comply with AGIA these regulations move away from the actual sales, which is the current valuation methodology, and instead they look to published prices to establish value for distinct components of the gas stream including the residue gas and the natural gas liquids. The working assumption within the regulations is that on average a published price in a healthy well functioning market will closely approximate a lessee's received value in that market. She said they also have no way of knowing into which markets a lessee will market their gas. Given that they simply assume that on average "reasonably optimal decisions" will be made by the companies, and that is what these companies do. She said there are other complications beyond not being able to track the molecules; for instance, they don't know how long the publications will be in print or for how long they will be reliable. Also, there gas value has to be established in some markets that don't have published reliable prices and LNG is one of those. Because of these various complexities they tried to develop some mechanisms to ensure that the state doesn't lock itself in to some decisions today that may be very wrong over time. They believe that protects both the lessee and the state. 4:47:39 PM MS. RUTHERFORD pointed out that a further clarification in these regulations says there will be no negative royalty. This means that the netbacks on gas components cannot go below zero. They believe this is already the current status within their contract structure, but that is getting clarified within the regulations. It hasn't been tested on oil, but it is a point of disagreement between the state and some lessees. SENATOR STEDMAN asked her to amplify on that issue. MS. RUTHERFORD responded that basically they are saying in a calculation, should the cost of transportation should go higher than eventually where their marketing goes, the state's royalty can't go lower than zero. SENATOR STEDMAN tried to clarify further and said the severance or the production sharing arrangement would be gone, the royalty value could go to zero, and that is as far south as it would go. It can't be offset by some other direction into oil, because that's the only value left. MS. RUTHERFORD replied, importantly, it is currently arguable that if transportation costs exceeded the valuation received at the other end, the state would be placed in a negative royalty position where it would actually owe the lessees money. The department does not believe the state's oil and gas leases provide for that, but that has been a question in some people's minds. So within this set of regulations they are clarifying that zero is as low as it can go. That situation exists with oil now; but arguably under oil where it has never been clarified it could go below zero. CO-CHAIR WIELECHOWSKI noted that these regs don't address oil, and asked if the state could be in a position of losing royalty value there. Does oil need regs? MS. RUTHERFORD replied that the state doesn't have regs in place on oil and it hasn't been tested. If they got into a situation where the value of oil fell significantly, it is possible that someone might bring that argument forward and take it to the court. But they do feel the lease contract is strong enough for the state to make its case if that should come up. 4:52:05 PM MS. RUTHERFORD said incorporating gas industry practices (slide 11) in determining the cost of transportation is very difficult. For instance, the original TAPS tariff dispute raged for eight years and the question of the transportation methodology was never settled. The intent within the draft regs is to incorporate generally well established industry practices. One of these was to use the FERC methodology to determine the cost of transportation for gas pipelines. They incorporated FERC's approach in order to be consistent with how they will approach thinking about transportation and transportation costs in marketing the state's North Slope gas. As well for the main line they substantially relied on the public offering by TransCanada to establish a backstop for non-arms length transportation costs. She said they are not just relying on FERC practice, but on industry commercial practices as well - as indicated by TransCanada and ExxonMobil's proposal to the FERC. Additionally, in crafting the regulation language, Ms. Rutherford said they used the Mineral Management Service (MMS) royalty value regulations as a template. All the North Slope producers are familiar with the MMS regulations for their Lower 48 gas production. Some MMS regs were modified in order to comply with AGIA. For example, the MMS regulations are built around a gross proceeds measure of value, whereas AGIA requires the department to use widely available industry trade publications. That said, they have retained a number of approaches to try to ensure it is well understood and that it limits opportunities for dispute. 4:54:12 PM FRED HAGEMEYER, Black & Veatch Corporation consultant, said he would talk about five of the key valuation concepts: 1. Destination where gas is valued 2. Publishing value at destination 3. Backstop measure of FMV for residue gas 4. Actual and reasonable transportation and processing costs 5. Appropriate deductions for unused capacity 4:56:24 PM A lessee's gas is valued for royalty at destination, he said. In determining destination a lessee's qualified gas is generally considered to be at destination when it first: 1. enters a first destination market (defined in regulation) 2. has been sold in a arm's length transactions; or 3. has been processed to extract residue gas and gas plant product (this gas will have a lot of NGLs so there will be a lot of processing). MR. HAGEMEYER said the key around first destination markets is that they are looking for is something the state can rely on that has a lot of liquidity, an area where they believe that ANS gas is physically transported, and where it can be bought and sold, there is processing and where they can find published indices available. As an example the Alberta market, which is referenced often, is clearly a first destination market. 4:58:32 PM He said one of the things that is key throughout parts of the regulations is being able to put on the DNR website elements and information prior to the royalty reporting period so the lessee can value royalty during the month in question, and locations of the first destination markets is a key concept. They will have all the elements to value the gas even if gas goes beyond that including: · The name of the source of the published price for residue gas, gas plant products at the first destination market · Appropriate location or quality differentials to establish FMV with reference to first destination market · Reasonable gas treatment, processing, or re-gasification cost allowances. 5:00:23 PM Alternative Destination Value for residue gas (slide 15) is found using a basket of published indices to calculate a backstop fair market value to published index prices at destination markets - published ahead of time. These publications will provide the range of fair market value in that market. A number of market centers have interconnectivity to ANS gas that could go off into different areas after or before being processed. Each one would have publications that would qualify under the criteria of publication. A weighted average of the volume on the basket would be compared to the price at ACCO (for instance) and a 5-percent buffer accounts for month to month fluctuations. The basket is relied upon only when the published price at a destination market is less than 95 percent. Another transportation concept is around the non-arms length transportation cost. A unique thing about these regulations is that they have had the luxury of knowing what has been offered in the TransCanada ExxonMobil open season offering so they suggest that they provide a watermark for reasonable non-arms length transportation costs. During the process of the open season they will see if a shipper can negotiate a better rate than can be calculated from the basic terms in it now, and the state would take the lower rate. As a general principle they are going with FERC-based methodologies to calculate "reasonableness," even though other pipelines segments particularly out of the Alaska/Canada main pipeline will have cost deductions. 5:03:18 PM The last point he wanted to make about something that is a reasonable and actual cost has to do with processing costs and in this case they have used the template of what the MMS is allowing; typically those plants are not regulated. 5:04:38 PM MR. HAGEMEYER said the last major bullet in this area is around unused transportation capacity which is designed to balance the need and mitigate the producers' risk associated with taking out that capacity as well as help protect the state from unintended costs associated with that. A detailed example of how it would work was on slide 18. 5:08:05 PM MR. HAGEMEYER went to slide 19 on the royalty in kind (RIK) royalty in value (RIV) switching issue. He explained that under the lease, the state has the option of taking its share of royalty either in RIK or RIV. This can in the case of taking out firm capacity (FT) in the open season create a risk for shippers along the lines of if the state takes its RIK during a period of time when the shippers may have excess capacity and that capacity could be fairly expensive (for the shipper). But if the state were in RIK for a period of time and wanted to switch back to RIV and now the timing is fairly short (maybe 90 days) then the shipper may not have capacity to take that back in, and they would have to acquire capacity somewhere or do something else. In addition, producer marketers will put elements in place, some short term some long term, over the course of the volumes they are moving (no matter which market it may be); so there needs to be some time to adjust those volumes if the royalty portion is not there. Given that, they have tried to work through ways of mitigating that risk while protecting the state. SENATOR WAGONER said he thought if the state would take RIK it would be for a specific length of time and a specific amount by contract. MR. HAGEMERYER replied it can do that, but it is not required right now according to the lease. SENATOR WAGONER stated that it's at the state's option not the producers' then. 5:09:02 PM MR. HAGEMEYER said in switching from RIV to RIK, the regulation is set up so that the state would be obligated to seek capacity corresponding to the state's RIK share from the producers in a prearranged deal. This means the state would take the released capacity that they acquired at original contract rate and in doing that, the state risks foregoing a potential better deal that could be negotiated. The state would be taking capacity from the shipper sort of like the capacity is going with the gas. If the gas went to the state the capacity goes to the state, too; if capacity is switched from RIK to RIV that capacity goes to the producer. They felt it was reasonable for both sides to do this, and he mentioned both sides wanted it to happen. SENATOR WAGONER asked what if the producer in the meantime has filled that capacity with other gas. MR. HAGEMEYER responded that when a shipper takes capacity and that capacity is released to another party, it goes through the carrier to the third party. So now the state would have that capacity. The producer doesn't have the capacity to refill, but it doesn't mean they can't acquire other capacity for other reasons. 5:11:45 PM One of the tools to do this is having a contract rate, so whatever rate they have is what is transferred over. The state requested a waiver from FERC in November (approved by FERC in January) that essentially allows for this transfer to occur at that contract rate. The regulations increase the notice period trying to allow more time to arrange other marketing situations for that royalty gas that may be taken. If it's over 200,000 Mmbtu/day it would be 180 days notice. 5:12:38 PM DEEPA PODUVAL, Black & Veatch consultant, said she would walk the committee estimates of what quantitative values are being provided to the producers through these proposed AGIA royalty regulations (slide 21). She said one of the aims of the regulations was to provide value to the producers while protecting the state's interest. In going through the process of developing the regulations one of the exercises they did was to find how much value was being transferred in some of the key provisions; they looked at four main provisions: · Valuation - moving away from the higher-of provision · Transportation - adopting a FERC-like approach for non-arms length transportation deductions rather than the MMS-like approach, and allowing deductions for unused capacity · RIK/RIV switching - FERC waiver allows capacity transfer deal at contract rates 5:15:19 PM MS. PODUVAL said one of the challenges in quantitatively analyzing the value to the producers is the level of uncertainty about certain factors that influence the project going forward: prices, project costs, volumes that may be found, reserves and uncertainties related to RIK/RIV switching. So rather than attempting to create base line assumptions on how some of these uncertainties may evolve they made aggressive assumptions to establish an upper bound on what the value to producers could be (slide 22). In other words they looked for the highest value the producers could get, but the actual value they would get would be something lower than that depending on how the uncertainties evolved. Some of the assumptions they made were: · Methane valuation - Assumed impact of moving away from the higher-of provision is not offset by market basket concept. · Transportation deduction for non-arm's length transactions Assumed that alternative was MMS methodology. Two key provisions were related to MMS that were different in the proposed regulations. The first is that MMS does not recognize taxes as a valid way of determining cost when creating the cost of service methodology and second that the return on equity that MMS allows on pipeline is calculated taking 1.3 times the Bbb bond rating. The proposed regulations allow 12 percent. Based on recent data the MMS methodology would allow a little less than 7 percent. · Unused capacity deductions - they assumed a worst case scenario where the only gas that flows through the pipeline are from the proven reserves, essentially no yet-to-find gas is found, and so there is a significant amount of unused capacity on the pipeline and the state does not pay for any of it. Essentially the producers bear 100 percent of the cost of commitments they have made related to that capacity. 5:18:46 PM · RIKRIV switching - Assumed that the state takes its entire royalty volume in-kind for the entire 25-year period. They further assumed that the producers are unable to take any mitigating actions to offset the cost of the capacity they are now stuck with (they don't try to acquire gas from a third party to flow through that capacity). · They looked at what the value to the producers is from the 1980 royalty settlement agreement (slide 23). 5:19:57 PM She estimated the quantitative value from different provisions that could potentially be given to the producers as a result of the proposed regulations. The biggest contributor comes from the FERC waiver that mitigates the capacity risk that the producers have from the state's option of switching between RIK and RIV. It can range anywhere from zero dollars if the state never takes RIK to up to $17 billion if the state takes all of its gas in RIK and the producers are unable to offset their capacity costs in any way. The second largest component is from the 1980 royalty settlement agreement where three different components were considered: field cost allowances, GTP cost allowances and the central compression plant allowance. That amounts to about $6 billion of value for the producers. MS. PODUVAL said the unused capacity is the next biggest contributor of value to the producers. It is a range from zero if there isn't any unused capacity and yet-to-find gas is found and keeps the pipeline full to the other extreme; if no yet-to- find gas is found and there is significant amount of unused capacity on the pipeline this could be worth as much as $3 billion to the producers. Transportation deductions, the proposed cost of service methodology related to non-arms length transactions provides about $2.8 billion of value to the producers. This is relative to a benchmark where the state could have adopted an MMS-like methodology that is used for federal royalty purposes and been much less generous in what cost components are included as well as what is allowed for return on equity. The last value component is from moving away from the higher-of provisions and is a range of zero up to $1.4 billion. The low end is theoretically possible if all the producers get the same value in each market and the state wouldn't be making that higher-of comparison. In conclusion, Ms. Poduval said significant potential quantitative value is provided to the producers from the various provisions of the proposed AGIA royalty regulations and it is good to keep in mind that they would be in addition to the qualitative benefits of improving their certainty as well as clarity. 5:23:21 PM CO-CHAIR WIELECHOWSKI asked if these values were calculated over the course of the pipeline. MS. PODUVAL said it is dollars of the day over a 25-year period. 5:24:24 PM CO-CHAIR WIELECHOWSKI said this is an important slide that shows some pretty significant sweeteners being added to encourage the producers to have an open season. He calculated $8.8 billion to $21.4 billion of incentives. He thanked everyone for their work on this issue and adjourned the meeting at 5:24 p.m.