SB 3001-OIL/GAS PROD. TAX  SB 3002-STRANDED GAS AMENDMENTS  9:18:46 AM CHAIR SEEKINS opened the hearing on SB 3001 and SB 3002. SENATOR WAGONER requested a presentation next week by the legislative consultants on issues addressed previously by the Federal Energy Regulatory Commission (FERC), including capacity and so-called basin control. CHAIR SEEKINS acknowledged that. He welcomed representatives from Anadarko Petroleum Corporation. ^Mark Hanley, Anadarko MARK HANLEY, Public Affairs Manager in Alaska, Anadarko Petroleum Corporation, introduced Karol Lyn Newman, the company's FERC counsel from Washington, D.C. He drew attention to Anadarko's handout containing: 1) a cover letter dated July 24, 2006, to Governor Frank Murkowski, copied to Commissioner Bill Corbus of the Department of Revenue (DOR) and Commissioner Mike Menge of the Department of Natural Resources (DNR), and 2) Anadarko's comments on the proposed fiscal contract for the gas pipeline. Noting Anadarko has had pipeline-access issues for a number of years and that then-U.S. Senator Frank Murkowski was helpful in passing legislation relating to FERC's open seasons and providing some protections for pipeline access, Mr. Hanley said there are a number of things the governor has done. MR. HANLEY emphasized Anadarko's desire to see this gas pipeline built as quickly as possible. While things might not be perfect from its perspective, Anadarko wants this gas line as much as anybody. Its gas-prone acreage in Alaska isn't worth anything if the gas cannot get to market. He suggested looking at comments during the public-comment period in the context of changes that could benefit everyone. He turned to page 8 of the handout, "B. The Contract Should Reflect The Design of The Project Described In The Application And The Preliminary Findings And Determination." Mr. Hanley said most explorers probably won't be ready to nominate gas from the Foothills, for instance, if an initial open season is held in the next two years. Thus the pipe design is critical for explorers to feel comfortable that they can get their gas into a pipeline. He read from page 10, a quotation from the fiscal interest findings (FIF) of the contract that stated: Building a 52-inch line is riskier and more expensive than building a smaller line, and for this reason the pipeline companies that state officials talked to said that they would build a smaller-diameter line. Not so the sponsor group. They were willing to take this 52- inch risk in order to take maximum advantage of the economies of scale associated with gas pipelines. This large-diameter pipeline not only allows a large volume of gas to be transmitted through the line while limiting fuel loss, it also allows for a relatively inexpensive and attractive large increment of expansion. In fact, the average capital cost per unit decreases for an almost 50 percent expansion of the line. This decreasing cost function means that expansions not only will be in the pipeline entity's best interest (through more tariff revenue), but will also benefit existing shippers as well as expansion shippers through lower per-unit tariffs. Apart from the FERC access regulations, or the SGDA contract provisions, the 52-inch decision is a concrete way of telling explorers that if the gas is there, the pipe capacity will be there to take it to market. MR. HANLEY said while Anadarko agrees and finds such design work comforting, nothing in the contract says it will happen. In fact, comments indicate the pipe size hasn't been decided yet. Although FERC regulations say the pipe design can be changed if there isn't enough initial capacity or ability to expand, the producers have challenged FERC's rules in court. If the challenge is successful, FERC might not have authority to require a design change if the pipe is too small for the capacity necessary for explorers. He therefore highlighted a key recommendation from Anadarko: Somewhere in the contract, require that the pipeline be designed to allow a significant amount of in-field compression expansion, which is inexpensive compared with looping. Mr. Hanley noted this essentially mimics what is in the FIF as well as the producers' applications. 9:28:53 AM ^Karol Lyn Newman, Morgan, Lewis & Bockius, Counsel to Anadarko KAROL LYN NEWMAN, Morgan, Lewis & Bockius LLP, Counsel to Anadarko Petroleum Corporation, in response to Senator Ben Stevens, observed that Mr. Hanley's remarks were directed to the design concept, rather than exactly when that determination needs to be made. Such a determination must be made before the open season because FERC regulations require that the open season itself specify the design and the expansion capability for the pipeline. SENATOR BEN STEVENS distributed proposed revisions to the commission's regulations as submitted by Anadarko and received by FERC 12/17/04. He noted Appendix C says that no open season for initial capacity on the pipeline shall be held prior to six months before the date the pipeline must close on its financing arrangements. Inquiring how financing arrangements can be put together on a proposed pipeline at specified capacity with six months remaining, he also asked: If you can't go to open season until you know the capacity, how can you get to closing on financing until you have an open season that FERC has approved? MS. NEWMAN replied that these were early comments by Anadarko, in 2004. Since then, there have been many comments to FERC and lots of activity at the agency. In addition, FERC issued final rules that say it won't dictate when the open season should take place, and indicated it will look at the pipeline design and require that the project sponsors include, in their open-season package, detailed information on the pipeline that the shippers will bid on. That isn't unusual for a pipeline open season. She specified that in its comments on the contract, Anadarko hadn't taken the position that there must be an open season at a particular time. Highlighting the importance of the pipe's size, Ms. Newman noted Mr. Hanley had spoken to that issue. She requested clarification, since there are two different points, one related to open-season timing. SENATOR BEN STEVENS agreed they go to two different points, but said the topics in Appendix C, received by FERC in 2004, are similar to comments received by the commissioner in July 2006. While the main one is a request that there be no premature open season, there is talk about capacity also. He asked: How can capacity be defined on a project until there is an open season? MS. NEWMAN suggested that speaking to the open-season point would clarify some of the confusion. She deferred to Mr. Hanley. 9:34:15 AM MR. HANLEY explained that Anadarko doesn't want the open season held any sooner than necessary to build the pipeline; it hasn't placed any timelines. There are three recommendations. First, the contract should require that the open season not be held any sooner than the Alaska Oil & Gas Conservation Commission (AOGCC) rules for determining how much gas can be taken off from Prudhoe Bay and Point Thomson. While it seems AOGCC would set the maximum amount, it also seems appropriate to wait at least until then. Second, FERC-required engineering work for the open- season process needs to be done. Third, veto authority on timing should be given to the state so the open season isn't held too early. The state is the most likely party to advocate for explorers and to look out for their interests, Mr. Hanley opined, and Anadarko doesn't want a specific time set because it doesn't have the necessary information. He turned to the design for capacity, noting this will be done by the pipeline applicants. He interpreted the quotation to say the state partially predicated this contract upon the idea that the producers would take additional risk to make that extra billion cubic feet (Bcf) of capacity available for explorers and cheap expansion increments. Mr. Hanley emphasized that if it is being sold as expandable, it should be in writing. 9:38:20 AM MS. NEWMAN added that this pipeline is a bit different from one in the Lower 48 or where the producers don't own it. Most gas to be initially committed will come from Prudhoe Bay and Point Thomson. The producers - the project sponsors - indicated in their initial comments to FERC that in order to develop the gas fields for this pipeline, all owners of a field must align on the field-development plan. After field offtake is agreed to, AOGCC has to approve it. Thus the sponsors will have agreed to the field offtake to propose to AOGCC for Prudhoe Bay and Point Thomson. By the time the pipeline entity is created and holds an open season, they'll know what they're requesting for offtake - 3 Bcf a day, for instance - and thus what can be committed for the pipeline. Otherwise, it would be risky to commit to pipeline capacity or reserves they couldn't take off the field. MS. NEWMAN explained that a "normal" pipeline - not affiliated with the producer group that's in competition with explorers - has every incentive to build the pipeline to be accommodating and to hold its open season when it can get the most shippers, within the necessary constraints under its project plan. Given that timeline, someone would go to the market and try to find anybody willing to ship on the pipeline. She cautioned that such an incentive might not exist in a producer-owned pipeline. Ms. Newman highlighted concern that this can drive the timing of the open season in a way that wouldn't occur for an independent pipeline. She noted for this pipeline, however, the reason for the open season isn't necessarily to locate all shippers. She said the producers' comments raise some concern because they talk about the open season as the means for allocating capacity, which suggests there is a finite number on the design. Pointing out that Anadarko doesn't know that number, Ms. Newman reminded members that the proposal said 4.0 to 4.5 Bcf a day, with 52- inch pipe, expandable to 6.0. She further explained that if there is a finite number, capacity will need to be allocated and there'll be incentive by the initial shippers or the Prudhoe Bay and Point Thomson producers to hold an open season when there is no need to allocate capacity. For those reasons, Anadarko would like the State of Alaska to play a role in determining when that open season is held - which Ms. Newman said they hadn't seen in the contract. SENATOR BEN STEVENS voiced appreciation, but said AOGCC commissioned a study in December 2005 and thus is already analyzing offtake from Prudhoe Bay and Point Thomson, to be completed by year-end. He recalled it will be at least 18 months before an open season begins; there is a 180-day process. He said he was trying to understand why the state needs to be involved when he believes the issues are being mitigated. 9:44:49 AM MR. HANLEY replied that the suggestion is to just ensure the open season isn't done before AOGCC issues its recommendation. If it is at the end of this year, fine. He reiterated that the state should have some say about when the open season occurs. The state can look at other factors and decide whether it is an appropriate time. The state is an owner that Anadarko views as looking out for explorers as well as existing producers; it should have the ability to determine when the open season occurs because there is some risk, in Anadarko's view, that it could diminish explorers' ability to have access to the pipeline. MS. NEWMAN clarified that although there is an opportunity for a latecomer to the open-season process - after the open season has closed, but before the pipeline is at its final design state - FERC has indicated it wants the pipeline to entertain bids from interested shippers who've now developed reserves that they could commit to the pipe. That's because FERC anticipates and has heard there will be a gap of four to five years between the close of the open season and the final design or when the pipeline is ready to be built. It isn't a sure thing. It's something the pipeline must consider, and the commission has standards it would look at if the pipeline refused. But it isn't something the pipeline is required to do. SENATOR BEN STEVENS expressed appreciation for that clarification. 9:48:13 AM CHAIR SEEKINS asked how that would be written into the contract. MR. HANLEY surmised some of the state's decisions would be in the limited liability company (LLC) that has control over a lot of this. He reiterated the need for the state, even as a minority-interest owner, to have veto authority over the timing of the initial open season for the pipeline. MS. NEWMAN added that certain issues are critical to each partner individually, in many LLC partnerships. Anadarko is concerned that the only disinterested party at the table is the state. Although couched in terms of giving the state the veto power, this could be accommodated in a number of ways that work for the LLC entity. For example, the contract could require that the LLC say the following: Any owner has the right to determine that the open season is premature. 9:50:08 AM SENATOR BEN STEVENS questioned why the state would argue for veto authority to delay the project when it wouldn't receive a benefit until the point of first revenue. MS. NEWMAN responded with an example where the proposal in the open season is only enough capacity, at full pressurization, to handle offtake from Prudhoe Bay and Point Thomson. In that case, the state might ask why it should be done then. SENATOR BEN STEVENS, after referring to recent testimony from Mr. Cupina of FERC, asked why the sponsor group would put together a package that potentially inhibits competition, when FERC has said if the project doesn't meet the requirements of the federal Act, that application will be changed by FERC. He recalled presentations that it will be built at 4.3 to 4.5 Bcf, expandable to 5.9 or 6.0. MS. NEWMAN clarified that FERC rules don't dictate a particular size or design; its rule says it will look at that as one factor in determining whether any proposal for the pipeline in any application - or any proposal for an expansion - complies with what FERC believes the Act requires as sufficient design capacity to accommodate expansion and all shippers. This is the very issue the project sponsors have taken to the U.S. Court of Appeals for the District of Columbia Circuit; they've suggested FERC doesn't have the authority to second-guess design determinations, and that case's outcome is yet to be seen. But designing it a particular way isn't a violation of rules. So there'd be no enforcement action as the result of a pipeline design that purports to be what others might consider too small. SENATOR BEN STEVENS opined that the demonstration to move the project forward as outlined in the Project Summary - under criteria set out by FERC and Congress - is pretty well laid out. Because of the size and scrutiny, he questioned why any project sponsor would knowingly take anticompetitive action that would end up in litigation and thus cause delay. He referred to presentations about building it to 4.3 Bcf, expandable to 5.9. MR. HANLEY responded, "If they build it that way, we're happy. And if they say they're going to build it that way, then commit to it." He noted FERC regulation 157.37 says this: In reviewing any application for an Alaska natural gas pipeline project, the commission will consider the extent to which it has been designed to accommodate the needs of shippers who've made conforming bids during open season, as well as the extent to which the project can accommodate low-cost expansion, and may require changes in project design necessary to promote competition and offer a reasonable opportunity for access. He surmised this ability to look at low-cost expansions is the provision referred to by Senator Ben Stevens. "It gives us comfort that we can go to FERC and have somebody look at that," he explained. Referring to the court case by the producers, Mr. Hanley indicated the producers' brief could ask that the court find 157.36 and 157.37 invalid, since that is exactly what they're trying to eliminate. MR. HANLEY told members this is why there are red flags for Anadarko about whether they're actually going to build the project they assert they'll build - taking away the ability to go to FERC and say this hasn't met the criteria. He emphasized that the producers should put their intentions in writing and not challenge FERC's authority to ensure it happens that way. 9:58:18 AM SENATOR WAGONER asked if smaller explorer-producers such as Anadarko, Chevron or Pioneer were offered ownership in the pipeline or tried to buy any part. He surmised these items wouldn't be under discussion if they'd had a seat at the table. MR. HANLEY recalled public statements five or six years ago that there might be an open season within six months. Anadarko had scrambled, researching past issues and producing a white paper after identifying access concerns. Anadarko had approached the three producers to discuss participation in the $125 million study talked about in their findings. At the time, Anadarko wasn't into pipeline ownership - which isn't what independent companies typically do - but thought it important to get a seat at the table by paying a share. Although Anadarko even offered to buy a part of the pipeline, the producers weren't interested. He reported that Anadarko then went to Washington, D.C.; talked to then-Senator Frank Murkowski, who helped with some of these new FERC language requirements; and was successful in bidding on the state's royalty-in-kind (RIK) gas to protect its interests by being able to nominate at the initial open season and have capacity. Mr. Hanley indicated that contract was never finalized. Highlighting that his company has worked for a long time to address access to this pipeline, Mr. Hanley said he didn't know whether other companies had been offered ownership interests or had approached the producers on this matter. In response to Chair Seekins, he offered to obtain the exact dates. 10:02:39 AM CHAIR SEEKINS observed that Anadarko has grown a lot since 2001. MR. HANLEY agreed it has been substantial, from perhaps a $4 billion or $5 billion market cap in 1998 to about $23 billion today. CHAIR SEEKINS asked about a purchase or merger involving Kerr- McGee. MR. HANLEY answered that it hadn't been finalized yet; he also mentioned Western Gas. In further response about North Slope holdings, he said Anadarko has about 2 million net exploration acres and is a 22 percent partner with ConocoPhillips in the Alpine field production. SENATOR BEN STEVENS offered to distribute information about the acreage holders for the North Slope. CHAIR SEEKINS noted he hears different characterizations of Anadarko with respect to size and acreage. He read from Anadarko's handout, beginning at the bottom of page 2, which stated in part: Therefore, the pipeline can be built to accommodate only the project developers' reserves, at deliverability levels that are determined by the pipeline developers. Therefore, even if there are expectations that reserves available to the pipeline by the in-service date would justify a 4 or 5 Bcf/d pipeline, the project sponsors might decide to build a 3 BCF/d pipeline. The pipeline would not be undersubscribed, but it would be undersized. He asked whether the concern is this: The producers might decide to build only the size necessary to get their currently known reserves to market, rather than what is anticipated to be available on the North Slope, not only from their own production, but also from production of another major leaseholder such as Anadarko, thereby exercising basin control. MR. HANLEY affirmed that in general. CHAIR SEEKINS asked: Would it be to their benefit to do that? MR. HANLEY answered it could be. He indicated if someone else controls access to a pipeline, assets won't be available for commercialization. CHAIR SEEKINS asked whether the only way to preclude that is to have the fiscal-terms contract or LLC say the pipeline must be capable of carrying 4.2 Bcf with expandability up to 40 percent, as heard previously. MR. HANLEY replied that it isn't the only way; it is the suggested way. "We'd just match what the statements have been of what they are going to build," he specified, noting it was a suggestion taken from both the application and the governor's statements in the FIF. CHAIR SEEKINS asked Ms. Newman why there isn't an incentive for a producer-owned pipeline to build in the capability that a privately owned pipeline would have. MS. NEWMAN replied there could be any number of reasons. This has been a concern for 30 years, starting with the U.S Department of Justice analysis of what anticompetitive issues might arise for a producer-owned pipeline from the North Slope. An independent pipeline exists to transport gas and make money from its transportation volume. To the extent it can expand its pipeline economically and capture whatever is in the marketplace, the pipeline and its shareholders make more money. CHAIR SEEKINS noted this is the same incentive the State of Alaska has in this ballgame. MS. NEWMAN acknowledged that, saying the idea is to capitalize on the asset and make the most money possible within regulatory restrictions. Because it is a monopoly, it will be regulated and a maximum amount can be earned on the FERC tariff. A producer-owned pipeline has business aspects that may create different prioritization. She gave examples, calling it a business decision. She noted people have been concerned for years that business motivations on the production side might far outweigh those on the pipeline side. Because there might not be the same incentives to do what an independent pipeline might do, there have been greater regulatory controls over this pipeline as it becomes clear that it might well be producer-owned. 10:10:41 AM SENATOR BEN STEVENS referred to Anadarko's handout, page 7, "A.3. A Premature Open Season Will Restrict Access To The Pipeline." He paraphrased a sentence, "Anadarko is currently planning to drill its first natural gas exploration wells in the Foothills Region of Alaska's North Slope this winter." He recalled an excellent presentation from Mr. Hanley this year saying one great challenge that participants on the North Slope face is the lead-time from exploration to production. He also referred to Anadarko's 10-K report and comments by Ms. Newman about priorities. Noting he was making his own assumptions, Senator Ben Stevens said of 655 wells drilled in 2005, 7 were in Alaska; of $2 billion in investment budgeted for 2006, Alaska has the largest undeveloped lease-holding acreage in the company's portfolio; and capital expenditures for 2006 in Alaska totaled $70 million, whereas $800 million was spent in the Gulf of Mexico, $450 million in Canada and so forth. SENATOR BEN STEVENS acknowledged Anadarko's right to make business decisions, but said while there is concern about access to a pipeline from a company that has the largest lease holdings of any independent company on the North Slope, there is no focus on proving those reserves. At the same time, he asserted, the company is requesting delay of the open season on a project that everyone is depending on. He said FERC has made all kinds of concessions and criteria to allow future explorers and expansion of a line when that gas is available, but it may be six or seven years before it is actually known how much the company can put in the pipeline. He said he didn't understand the rationale. MR. HANLEY replied that Anadarko won't take the full development step until comfortable that there is access to the pipe - a real potential restriction. While becoming more comfortable through the process involving FERC and the contract, Anadarko is raising issues here that would provide a greater comfort level. He reminded members that a few years ago even the producers didn't believe gas prices were high enough to build a pipeline, so there wasn't the interest. He reported that Anadarko has done significant seismic work in the Foothills and has drill-ready prospects; it has taken a certain amount of risk already and invested some money in the hope that a gas line will come to fruition. Anadarko is ready and planning with its partners to potentially drill a well this winter. However, it likely will get into the expansion phase of any pipeline because it is hard to invest money until it is known that a pipeline is going forward. After a pipeline is going forward, if the company drills its first well there still won't be the knowledge to commit until after the open season. Mr. Hanley acknowledged this is a bit of a Catch-22. MR. HANLEY characterized this as a "long-term play" in Anadarko's portfolio. Reminding Senator Ben Stevens of a computer presentation in the Senator's office about Anadarko's process in Alaska, he said Anadarko is looking for anchor-field opportunities, larger-type fields for gas or oil that tend to be farther from infrastructure, more frontier and riskier; they also take longer to develop. Noting the commercial side is often greater than the noncommercial side - the geologic risks - he noted the ability to get gas to market is a crucial issue. He emphasized the desire to see the gas line go as quickly as possible. Mr. Hanley specified that Anadarko's suggestion on the open season isn't to delay the project. Rather, it is to make sure that the open season is not held prematurely, before it's necessary for progress of the project. Nor is the company trying to suggest a time when the open season should be held or delayed. Because the state probably has more aligned interests with the explorers, Anadarko believes that giving the state some say over timing would provide more comfort for explorers. 10:18:36 AM SENATOR WAGONER provided his understanding that currently the three major producers are the only companies with proven reserves on the North Slope. Noting Anadarko and Chevron are partial owners in that, he asked whether any independents have proven gas reserves on the North Slope in any quantity. MR. HANLEY answered that he believes Chevron is a significant owner at Point Thomson, for example, and there are smaller owners in some fields, though he wasn't familiar with those. 10:20:03 AM SENATOR BEN STEVENS asked which would better raise the attractiveness of Alaska for Anadarko's portfolio: 1) opening the basin for a gas line, but not revising the oil tax; 2) the oil tax proposal before the committee, but with no pipeline; or 3) a combination of revising the oil tax and opening the basin. MR. HANLEY noted Anadarko has testified the latter would be the most advantageous; has testified in support of the governor's 20/20 [20 percent tax on oil, with a 20 percent credit] proposal and suggested it would increase investment; and has said Anadarko wants the gas pipeline built. CHAIR SEEKINS asked about the 10-K report, observing it says the results of the seven wells drilled in Alaska are held as confidential for competitive reasons. MR. HANLEY opined that in Alaska information about certain wells can be kept confidential for two years, and statutes say who can get the information; for example, the department can receive it on a confidential basis, and rules relate to its release. To his belief, certain information can be kept confidential beyond that period; the state has developed a policy for when that information is released. While suggesting most companies would prefer it never be released, for competitive reasons, Mr. Hanley offered to obtain more precise information. As for the seven wells, they're on the North Slope, largely in the National Petroleum Reserve-Alaska (NPR-A), where Anadarko partners with ConocoPhillips, which he believes is the operator for most of those. The location of the wells is public information. CHAIR SEEKINS observed the high success rate in Louisiana, Texas and Western states, for example, in contrast to Alaska. He expressed curiosity about wells shown in footnote 2. MR. HANLEY responded that they're frontier exploration wells. In the Lower 48, some are in or around existing fields; a lot of gas wells are drilled and come online quickly in fairly identified areas. Referring to the federal Securities and Exchange Commission (SEC) rules, Mr. Hanley noted that what a company is allowed to say in such reports is fairly tightly controlled; Anadarko follows the statutes and SEC rules. In Alaska, the success rate is substantially lower; Anadarko goes into more frontier-related areas with higher risk, looking for larger-type prospects than it might elsewhere. 10:25:06 AM SENATOR STEDMAN highlighted the idea that the state would be a 20 percent owner of a project like this and then not try to maximize the benefit for its people, particularly for issues like sizing the pipe for volume, basin access and trying to extend the basin life for 30-50 years or longer. He asked whether Anadarko thinks the State of Alaska doesn't have a vision of maximizing the life of Prudhoe Bay. MR. HANLEY opined that Anadarko is aligned with the state's interests, and that the state is most aligned with respect to Anadarko's interests. Agreeing the state will maximize its interests, he remarked, "I don't disagree with anything you've said." He noted the question becomes whether the state has the ability, through the contract - and particularly through the LLC agreements - to actually influence some of those decision. While the state, as a 20 percent owner, would typically have a say, it may get outvoted - which is the concern. SENATOR STEDMAN recalled FERC testimony about its own independence in deciding the size of the pipe. He also recalled questions by Senator Wagoner about having two pipes versus one, with FERC's response being that FERC would make that decision at the proper time. Senator Stedman said they didn't mention that litigation in the courts might block them from making that decision, but had said they'd make the size of the pipe applicable to the goal of opening that basin and harvesting the natural resources for the benefit of Alaskans and Americans. MS. NEWMAN surmised Robert Cupina of FERC, the head of projects, is well aware of the court appeal. She recalled his testimony that FERC would look at the size and ensure the pipeline was properly sized to allow for expansion, and that it would accommodate what FERC felt was important in terms of sizing and design. Ms. Newman said that authority of FERC has been challenged by the project sponsors. They are asking the U.S. Court of Appeals for the D.C. Circuit - in a review petition filed from the FERC rule making with respect to what rules it would follow in acting on an application for expansion or for an initial certificate - to decide FERC doesn't have that authority and power, and to vacate those aspects of its regulations. Until the court decides that case, the issue is unresolved. SENATOR STEDMAN voiced hope that Congress would step in to protect Americans' interests if something like that occurred. 10:29:30 AM SENATOR STEDMAN noted concern that there could be substantial manipulation by the industry to diminish the state's revenue share, affecting the federal government as well, since it gets roughly half the government take. He asked: If a publicly traded company aggressively manipulated expenditures to increase its income and hence falsified its 10-K report and so on, what ramifications would be faced with respect to the SEC? MR. HANLEY replied that Anadarko isn't going to break the law or try to manipulate things in that way, which would have severe ramifications. He noted companies go out of business because of manipulation and illegal activities, and people get fired. He reiterated support for the governor's original 20/20 proposal. SENATOR STEDMAN clarified that he was using the opportunity to speak to it because of having in his hands a 10-K, a report filed with SEC on corporate activity including income and expenditures. 10:34:50 AM SENATOR BEN STEVENS pointed out that the comments on Article 8.7, state-initiated expansion, on pages 16-20 of Anadarko's handout, conclude it would be best to eliminate Article 8.7 entirely. Opining that Anadarko makes a compelling case from its perspective, he requested a roundtable discussion to learn what advantages the administration sees in Article 8.7. 10:37:07 AM MR. HANLEY addressed Article 8.7. He acknowledged the state's intent to provide another avenue for expansion. However, the criteria make it more onerous than even the federal mandatory- expansion program under FERC for this pipeline; the federal program has 8 criteria, to his belief, that the state adopted in essence, adding 10 or 12 more that diminish the value. Mr. Hanley said Anadarko couldn't foresee a scenario in which it would use the state process. If it couldn't meet the federal process, it wouldn't be able to meet the state process with its additional onerous provisions. He discussed limitations. First, the state-initiated expansion proposal cannot be used until commencement of the pipeline, a limitation Anadarko doesn't believe makes sense; if a company finds enough gas and wants to propose an expansion before the pipeline actually starts operations, Mr. Hanley said normally that can be done. Another limitation is restricting the state process to every five years. A further limitation suggests that even if someone goes through the process and meets all the conditions, the certificate shall be rejected if FERC issues a certificate that has different conditions than applied for. He indicated BG Group, one of Anadarko's partners, had prepared comments including an analysis of concerns about Article 8.7; Mr. Hanley noted these comments are public, though he didn't know if they'd been submitted. He opined that it would be harder to restructure what exists with Article 8.7 and come up with something that might work than to eliminate it and then add other criteria specified in Anadarko's proposal. Although he offered to work with the state in this regard, Mr. Hanley said it was difficult to see how to salvage it; there are too many restrictions on the expansion capability, and it would be ineffective. Thus the suggestion is to remove it. SENATOR BEN STEVENS asked whether the state-initiated expansion is categorized by FERC as a voluntary expansion. MS. NEWMAN noted it's an interesting question. She gave her understanding that FERC hasn't opined what this would or wouldn't be. There are two ways to look at it: 1) Yes, it would be a voluntary expansion because it would be a proposal filed by the pipeline with FERC, as opposed to an expansion initiated by an unhappy shipper who'd tried unsuccessfully to get capacity, or 2) FERC regulations define "voluntary expansion" as an expansion made voluntarily by the pipeline entity, and it isn't known how that would be portrayed by the pipeline entity when it found itself making that filing. Thus it possibly could be either answer. CHAIR SEEKINS acknowledged that attendees seemed to wish to comment on that point. MR. HANLEY indicated Anadarko hadn't gone through each section today to explain each concern, but could do so. He referred members to the concerns described in Anadarko's comments as well as BG Group's comments, which add clarity to the concerns raised in this particular section. 10:43:33 AM SENATOR STEDMAN asked: If Anadarko, as the largest independent company, doesn't participate in the initial open season, will other independents likely participate? MR. HANLEY replied Anadarko may or may not. It depends on whether it has reserves. There will be a large monetary commitment to transport gas for a significant amount of time. He didn't know whether other independents had found a gas field from which to nominate. SENATOR BEN STEVENS asked whether it is accurate that Anadarko's recommended term for commitment has consistently been 20 years. MS. NEWMAN noted Anadarko took the position that there should be a cap of 20 years, but FERC didn't accept that proposal. SENATOR BEN STEVENS asked: When FERC does the revision and approves the tariff rate, does it set the term? MS. NEWMAN replied FERC doesn't set the term for contracts. That is done by private agreement. There will be an open season, and FERC has indicated it won't dictate the maximum term for purposes of doing a net-present-value calculation in an open season, if the possibility of capacity allocation is faced. She recalled FERC also indicated it will look at it; if FERC believes it is unduly anticompetitive, it could raise an issue and suggest that if somebody bid for 50 years, for example, that would be inappropriate. But FERC hasn't indicated there is any time limit it would set for purposes of a contract term. 10:46:28 AM ^Donald Shepler, Greenberg Traurig, Consultant to the Legislature DONALD SHEPLER, Greenberg Traurig, LLP, Consultant to the Legislature, concurred. He noted the following suggestion was made on behalf of the legislature: For purposes of bid evaluation on the open season, FERC should cap the bid period at 20 years, since FERC typically approves a net-present-valuation methodology to determine the value of the bids. As Ms. Newman had said, concern was expressed that someone might bid an excessively long period to increase the value of a bid unnecessarily in order to win capacity. While FERC rejected that proposal by the legislature as well, Mr. Shepler reported that FERC said it will observe and withhold judgment, depending on the length of contract term bids in the open season. ^Bob Loeffler, Morrison & Foerster, Counsel to the Governor BOB LOEFFLER, Morrison & Foerster LLP, Counsel to the Governor, agreed with Mr. Shepler. "We urged that position," he said, indicating it places some limit on the length of the firm transportation (FT) commitment. "We struggled with describing what the expected length of the FT would be in the fiscal interest finding," Mr. Loeffler explained, indicating it could be 10 to 20 years or longer. He noted the other party in this arena is the financial community, which looks at those commitments as part of the overall financing scheme, and which will have a large voice because it is security for the whole financing of the pipeline. Characterizing it as a tug-of-war, Mr. Loeffler said if a company bids for too long, it pays for capacity it doesn't have gas to fill; it's an extra financial liability. Thus he suggested the financial community might want as heavy an FT commitment as possible, or might want it shorter. This plays out in constructing the financing plan and in the open season. SENATOR BEN STEVENS summarized that it is to be determined, as for many questions raised here. He asked: For the open season, will the terms be a requirement? Or will each individual bidder bid for the length and term and capacity? How can the financial world put together its term sheets until the project has a FT commitment that, to his belief, would have a consistent term among all shippers, even though the volume would vary? MS. NEWMAN gave her understanding of the normal process in an open season for capacity. The pipeline frequently sets a minimum bid term. It can place its own cap, and some set it at 10 years. It also can place a minimum length of time. Evaluation of the bids is done by the pipeline entity, the project sponsor. If somebody believes bids have been evaluated improperly, a complaint can be made to FERC. SENATOR BEN STEVENS surmised the whole project would be reviewed by FERC before the issuance of the certificate. MS. NEWMAN explained that for this particular pipeline the commission will review the terms that go into the open-season packet. As to what information will be provided, she didn't know yet whether it would match identically what FERC has said the open-season package must contain or would be less specific. It will be seen at the time. After FERC reviews that, there will be an open season. Anybody can file a complaint following an open season if it is believed something was done improperly. She reported that FERC has agreed this will be fast-tracked if there is a complaint so the process isn't unduly delayed. If there are no complaints, a certificate application will be filed using the precedent agreements executed as a result of the open season itself. That becomes part of the package filed with FERC, and it is pretty much the last opportunity for people to object to what is going on in the certificate application. Ms. Newman said FERC will look again at that point. She noted as a result of the Alaska Natural Gas Pipeline Act (ANGPA), FERC promulgated rules on open seasons that differ from those for Lower 48 pipelines. She elaborated about the latter. SENATOR BEN STEVENS asked whether the following is correct: The criteria for the open season will be reviewed by FERC. If a potential bidder has a grievance, that can be filed during the open season and it will be fast-tracked and thus addressed during that period of time. MS. NEWMAN replied that the exact timing of the complaint isn't specified. Theoretically, someone could file a complaint at any point if something improper were perceived in the open season. 10:54:46 AM MR. HANLEY turned to comments on Articles 8.1, 8.2 and 8.3 of the proposed gas contract, beginning on page 20 of the handout. He indicated he'd discussed this previously in relation to the Regulatory Commission of Alaska (RCA) and the regulatory gap. He recalled that all parties want to go to FERC and seek FERC jurisdiction over these facilities, but there is a question of whether FERC will grant it. Even if FERC grants it, as heard the other day, there is a question of whether it has the authority, and there are related court cases. He explained that Anadarko is concerned that the contract limits the state's ability to request or support RCA jurisdiction to the extent it may exist. Mr. Hanley recommended that the requirement that everybody request FERC jurisdiction remain, but the other portions of these provisions be removed. Recalling that Shell's comments suggest RCA should regulate if FERC doesn't, he noted there'd been discussion since then. Anadarko therefore recommends the following: Remove sections that limit the state's authority, and then everyone go jointly to Congress to ensure FERC has authority to regulate these things. Then the question will be moot, since they'll be regulated by FERC. Mr. Hanley deferred to Ms. Newman to address Anadarko's concerns with capacity-management issues in Article 10 of the contract. The committee took an at-ease until 11:06:05 AM. MS. NEWMAN referred to pages 11-14 of the handout. Calling Article 10 lengthy and complex, she explained Anadarko's concern that it is extremely restrictive as to the state's particular rights, and may interfere with the normal process of capacity release and the availability of capacity in a secondary market for this pipeline. This may become important down the road for people without capacity who are looking for released capacity, from time to time, from those who have capacity in the line. She said it isn't at all clear that FERC rules would permit one shipper to bid for another shipper such that Shipper A shares information about its bid with Shipper B. Normally, the open- season process contemplates individual bids by individual shippers; it doesn't contemplate the shippers getting together to decide how to formulate a bid, even though they may have some common relationships. Ms. Newman opined it would require special FERC approval, if FERC were to give it at all. She raised a second issue: Article 10 seems to contemplate there will be terms and conditions of service that may be negotiated in a precedent agreement following an open season that could differ from shipper to shipper. Ms. Newman said FERC rules don't allow differences in terms and conditions of service, but only allow differences in price, other than some inconsequential terms and conditions. She made a third point: It appears the state's right to forecasts of monthly production information - which, to her belief, is in Article 10.4 - appears somehow contingent upon the state's agreeing to all of Article 10. While this may not be intended, Ms. Newman said it appears to read such that if the state didn't agree to all capacity-trading provisions of Article 10, perhaps it wouldn't receive the necessary information required with respect to its RIK gas. MS. NEWMAN said Article 10 also seems to contemplate prearranged releases of capacity at rates perhaps other than the pipeline's maximum tariff rate. This isn't permitted under FERC's capacity-release rules, which only allow a replacement contract to be executed in a prearranged capacity-release deal if the rate is at the maximum tariff rate - not the rate the initial shipper is paying. If the rate is lower, Ms. Newman said, it must be put out for bid. If higher, it must require specific FERC approval. She also said the commission tries to ensure initial capacity of a pipeline is available to all shippers, and it tries to ensure that those who obtain initial capacity don't use their control over it to extract monopoly rents from nonshippers who seek capacity in the capacity-release market. The object of that rule - the restriction on the maximum tariff rate - is to keep that in check. Thus Ms. Newman said it isn't clear that a predetermined capacity-release arrangement will pass muster under existing rules. Furthermore, as this is structured - looked at across the board among all the producers who'd be shippers, as well as the state's interest with respect to each producer's leasehold - it appears if these articles apply to every one of them and to potentially every shipper on the pipeline, there will be a real restriction in the capacity- release market. 11:11:50 AM MS. NEWMAN raised concern that Article 10 seems to contemplate shipper-to-shipper transactions without participation of the pipeline. But the capacity-release programs at FERC work through the pipeline, which is therefore in the middle of these transactions. There can be a replacement shipper, but that person then must execute a contract with the pipeline. While perhaps this is contemplated to be done after the fact, when the tariff is written, it appears to deviate from current FERC requirements and thus requires special FERC approval. She also expressed concern that it appears to restrict trading and capacity. If Anadarko were looking for additional capacity, the state couldn't decide on its own to sell its excess capacity to Anadarko, but would have to first give its capacity to BP, ConocoPhillips or ExxonMobil, which could then decide whether to release it to Anadarko. Conversely, if the state wanted extra capacity and Anadarko had some, the state couldn't go to Anadarko and buy it - even if Anadarko were willing to provide it at half price. Instead, the state would have to go through BP, ConocoPhillips or ExxonMobil and obtain the capacity through them at whatever price they negotiated. MS. NEWMAN concluded that Article 10 seems unduly restrictive and perhaps unnecessary. She acknowledged perhaps the state believes it needs some protection from a leaseholder having a better price or getting a better deal in an open season than the state could get. However, she opined that the state should be able to cure that with something akin to a "most favored nations" clause with respect to the transportation price on the pipeline - because it is the state, has royalty interests to protect and needs to get the same price for its production as the producers do. She surmised that would pass muster at FERC. 11:14:36 AM SENATOR BEN STEVENS said he finds this interesting, since Anadarko says it is aligned with the state's interests and yet, to his recollection, the capacity-management in Article 10 is Mr. Clark's pride and joy. He recalled testimony that this was designed to provide offtake in Alaska without a penalty for not meeting the capacity requirements with the group as an owner. He asked to hear from Mr. Clark, recalling he'd heard in presentations since May that Article 10 is favorable for the state and that there were many concessions from the other sponsor applicants. He turned to Mr. Cupina's testimony earlier in the week, noting Ms. Newman had been present then. Senator Ben Stevens read from page 13 of Anadarko's handout, which said in part: "In short, Article 10 attempts to remove the trading of interstate pipeline capacity on the Alaska pipeline from FERC's jurisdiction and have it governed, instead, by private contract." Offering his recollection that Mr. Cupina had said the contract cannot usurp FERC jurisdiction, Senator Ben Stevens asked: Do you have any question about FERC's ability to interpret the capacity- management program, with the statement that Mr. Cupina made? 11:17:13 AM MS. NEWMAN expressed confidence that FERC will have to look at Article 10 and the entire capacity-management program and determine whether it can allow it. Nor did she disagree that the contract cannot override FERC regulations in terms of capacity trading on this pipeline. She gave her reading as follows: It purports to try to do that by setting up a private contractual arrangement through which the parties can go to arbitration to resolve disputes, and they're precluded from raising issues with regulatory agencies. Ms. Newman clarified that it appears the contract tries to do something she believes it cannot do. 11:18:00 AM SENATOR BEN STEVENS surmised that would be based on dispute arbitration involving the LLC members, not another shipper. MS. NEWMAN concurred. The arbitration provisions only apply among the contracting parties, but still require FERC approval to even engage in the transactions in Article 10. Only FERC could have jurisdiction over whether the provisions that FERC allows in terms of the capacity-release arrangements were properly addressed. She said she doesn't believe that can be removed from the FERC arena and put into a private-dispute arena or into a private contracting arrangement without prior FERC approval. It is a regulated contract. That aspect of this contract is a regulated contract arrangement. SENATOR BEN STEVENS noted Article 10 had been presented as protecting the state's interests in the event it takes its royalty and tax gas in kind and becomes an FT participant. 11:20:39 AM CHAIR SEEKINS read from page 13 of the handout, which said: But if the State is to commit to take its gas in kind and, therefore, to purchase firm transportation capacity on the Alaska Pipeline in its own name, it cannot, by private contract, grant itself preferential terms and conditions to eliminate the business risks faced by all other shippers in committing to long-term firm capacity on the pipeline. He asked whether this says FERC won't allow it. MS. NEWMAN replied she believes FERC won't allow it, but she can't say what FERC would do. She surmised FERC wouldn't let any shipper receive preferential treatment for offsetting risk for signing up for capacity. Every shipper would like internal arrangements that allow simply moving capacity back and forth among other shippers in order to offset lows or highs in production at any point; however, that isn't how it works. Ms. Newman added, "That's what the capacity-release system is for, to have excess capacity available in the open market for anyone to bid on who might need it and not just restrict it to a single individual unless, again, it's been done at the maximum tariff rate, in which case there's no point to bid." 11:22:32 AM CHAIR SEEKINS asked whether other FERC attorneys, in looking at this, generally agree it probably wouldn't be allowed by FERC. MS. NEWMAN answered that she'd discussed this with Mr. Loeffler as well as ConocoPhillips, whose consensus, to her recollection, was a belief that these provisions are permissible because they fall within the scope of the capacity-assignment or capacity- release provisions allowing for prearranged deals. She noted her response was this: That would be true if the prearranged deals were set at the maximum tariff rate; in that case, all that would be required is posting of the transaction on the Web, for example. It wouldn't be true, however, if those transactions were at less or higher than the maximum rate. She noted she didn't recall discussing the permissibility of Shipper A bidding for Shipper B, even if the latter is the state royalty owner. Ms. Newman said she also didn't know that FERC had ever addressed that question; she opined it would have to be presented to FERC to determine permissibility. Ms. Newman surmised other counsel present would agree. CHAIR SEEKINS asked whether Ms. Newman believes the provisions of Article 10 aren't in the best interests of the state. MS. NEWMAN offered the view that the state shouldn't restrict itself in terms of how it can release capacity. While understanding the state's concern - not to be long or short on capacity - she suggested in the long run there are ways to manage it without the restrictions imposed by this article. She acknowledged she couldn't judge that for the state. 11:25:29 AM SENATOR BEN STEVENS suggested Article 10 is in the best interests of the state but not Anadarko, and thus the attempt to eliminate it. MS. NEWMAN replied she doesn't believe Article 10 or restrictions in the secondary market are beneficial to anyone but the original capacity holders; if Anadarko were an initial capacity holder, perhaps it would like this provision. However, every shipper should be free to release capacity into the market, which is part and parcel of FERC's open-access rules. "Putting restrictions on yourself, even if it seems like it might be good, might in the end not work," Ms. Newman cautioned. "But I can't judge that for the state." Returning to an earlier concern, Ms. Newman explained: As I read Article 10, the state is going to have to bid in the open season for its capacity in three pieces. And it will have to balance and manage that capacity in those discrete three pieces: the piece that comes from BP, the piece that comes from ExxonMobil and the piece that comes from ConocoPhillips - and maybe a piece that comes from somebody else. ... Being able and being flexible to use your capacity to its maximum sometimes requires that you have it all packaged together. And while I'm not an expert on how you manage and balance capacity, sometimes that is a preferable arrangement. And I don't think anybody was really clear how the state was going to use its capacity once it derived it in these three separate pieces. And so it struck me that it was very complex. And perhaps there would be an easier way to accomplish something the state wanted to accomplish without the complexities of Article 10. It was just a suggestion. SENATOR BEN STEVENS highlighted that Article 10 gives the state the option of either managing it itself - whether internally or by hiring a contract capacity manager - or having the producer of the gas, which the state now would own, manage capacity on behalf of the state. He opined that deleting Article 10 would eliminate choices that protect the state and that provide a variety of mechanisms to maximize the state's return and to allow efficiency in management. 11:29:32 AM CHAIR SEEKINS turned to the suggested change on page 14 of the handout, which read in part: Eliminate the capacity management program. Instead, the State should bid on its own capacity, and, to the extent that it is concerned that it will be disadvantaged vis-à-vis the producers which own the leases from which its royalty gas derives, it can insist on a most favored nations clause with respect to that particular producer's bid. He asked what is meant by a "most favored nations" clause. MS. NEWMAN noted it's what she'd alluded to earlier. The state has the interests of its citizens at stake, and also has laws requiring it to obtain certain value for its royalty gas. Therefore, it could request a "most favored nations" clause that would say the following: If the leaseholder obtains a transportation rate lower than the one the state obtains, and if the state's royalty gas in that instance is derived from that leaseholder's property, then the state gets the same rate for the shipment of its gas as does the producer who holds the leasehold interest. She suggested this is necessary to ensure that the differential in the transportation rate doesn't adversely impact the netback price that the state receives for its gas. Without such assurance, it won't be the same price in the end, since the leaseholder - as a larger shipper - may be able to obtain a lower rate than the state could. Ms. Newman opined that the state should be able to effectively argue for and possibly obtain from FERC such a provision; that approval is needed. She related her belief that it would resolve the pricing issue without the complications of the rest of this. MR. HANLEY indicated there were a couple of other points in the written comments that he believed to be self-explanatory. 11:32:31 AM SENATOR WILKEN recalled recent testimony about the FERC hotline. Inquiring whether Anadarko has worked under a hotline system in the U.S., he asked to what extent Anadarko believes a hotline concept should be relied upon to protect the state's interests. MR. HANLEY deferred to Ms. Newman, Anadarko's FERC counsel. MS. NEWMAN recalled earlier this week Mr. Keithley explained that the hotline is available for simpler issues. For example, a shipper may call a pipeline and ask to interconnect, and the pipeline may refuse to discuss it. The shipper then calls the hotline person, who contacts the pipeline and suggests this needs to be discussed. If it is relatively clear and no legal issue is involved, or if the FERC attorney at the hotline sees a clear answer, such issues sometimes get resolved. If something needs to be addressed by the commission, however - including contract provisions such as this - it isn't an issue the hotline even considers. She noted if the parties persist after hotline help, then a complaint must be filed and it will go to settlement mediation or even litigation. In further response, Ms. Newman opined that the hotline has existed perhaps ten years. 11:35:35 AM SENATOR BUNDE recalled discussion of a window of opportunity such that if the window closes, Alaska's gas will be stranded a long time. He requested Anadarko's perspective. MR. HANLEY offered to get an answer. Noting there are numerous reports, he remarked, "We've read them all." He said some of those suggest Alaska's gas is needed regardless, while others say liquefied natural gas (LNG) will come in. Mentioning the timing of permitting for LNG facilities to import those, he suggested the need to ask someone in Anadarko's commercial department. He also said the sooner this pipeline can go, the better. Noting Anadarko has acreage it wants to develop, Mr. Hanley stressed the urgency. He recalled discussion of how it would likely help Prudhoe Bay, the Trans-Alaska Pipeline System (TAPS) and explorers in Alaska, in order to keep momentum going. Mr. Hanley surmised it would be in the best interests of Anadarko, probably Alaska and all the producers as well. CHAIR SEEKINS thanked Mr. Hanley and Ms. Newman. He indicated the need to build a pipeline as quickly as possible; to hold the producers' feet to the fire to keep moving; and to ensure the ability of companies like Anadarko to get into an open season in order to get whatever gas they may have into the marketplace. He invited participation in a roundtable forum to address topics discussed this morning. 11:39:28 AM ^Jim Clark, Chief Negotiator, Office of the Governor JIM CLARK, Chief Negotiator, Office of the Governor, lauded the roundtable discussions for getting information to members. He asked that Mr. Loeffler address some issues as a precursor. 11:40:27 AM MR. LOEFFLER referred to Anadarko's comments, saying he wished many had been carefully conformed to what the contract actually does. While appreciating the emphasis on not delaying the project, he noted page 4 of the handout says in part, "If the Contract is executed this fall, an open season could be held before year-end 2008, which seems to be premature." He said he cannot reconcile those two positions. He indicated the comments also say FERC regulations require a lot of information relating to front-end engineering and design. Mr. Loeffler remarked, "You can't comply with those regulations unless that work is done. ... You'll be out of compliance if you try to have an open season prematurely. I don't think we need to get into that." He also said a set of regulations lays out detailed information on what is required for open seasons, including bid methodology. This takes time to do, including fieldwork and engineering. MR. LOEFFLER opined that the premature open season isn't possible. He surmised the state will be inside the LLC, talking about the open-season notice and construction of it, as well as the engineering work. The state will have a voice. Discounting the idea that the state needs veto power on this, he acknowledged that may or may not happen, depending on how the voting provisions turn out. He questioned whether it is a real- world concern and reread the quotation from page 4. He interpreted the comments to also say Anadarko isn't ready, at the earliest, until 2009 or 2010. Mr. Loeffler acknowledged Anadarko may have good reasons for itself, but said it sounds as if Anadarko wants to delay the project. Noting some people are pushing to start the project tomorrow, he remarked, "You just sort of can't have it both ways." 11:44:32 AM MR. LOEFFLER touched on Anadarko's opening comments, indicating Anadarko said the Project Summary information should be part of the contract. He noted Article 4.1 of the contract says the project consists of pipeline and related facilities consistent with the Qualified Project Plan, which is defined on page 49. He asked, "Where's the beef?" He turned to the capacity-management article, recalling discussions with Anadarko that this is a novel clause, anticipated to be submitted to FERC early, as stated in the FIF, to decide whether it is permissible. Mr. Loeffler opined it puts the state on equal footing with the producers because the state doesn't get information that Anadarko, Chevron or BP would get as a producer except by virtue of this contractual provision. He offered the view that this is needed to reduce risk to the state, to manage its capacity. Mr. Loeffler continued: The suggestion of a "most favored nation" clause would seem to imply the exact sort of discriminatory treatment that is criticized as part of the capacity- management clause. And there is a difference here. Anadarko's criticisms of the contract, save in the capacity-management clause, are really criticisms of the other three companies. In this clause, the way we read it, Anadarko is looking at it as a potential competitor to the state in the sale of its gas. And they're trying to remove what they see, I believe, as a competitive advantage. We see it as an effort to level the playing field. He reported it took enormous effort to negotiate this clause, perhaps 31 days straight last year. 11:48:25 AM MR. LOEFFLER asserted there are at least ten points in the capacity-management clause that the comments ignore; he cited Articles 10.2, 10.3 and 10.4, acknowledging he and Ms. Newman disagree here. He indicated FERC has jurisdiction and will provide an answer, and the state will have to deal with it once there is an answer. Stating the intention of going to FERC for clarity and confirmation, Mr. Loeffler opined that FERC has an ample toolkit for almost every issue raised this morning. He said while the written comments express Anadarko's apprehension that the state capacity will be bundled by the three producers to increase the value of their bid, that isn't what the contract language provides. Rather, it provides that each producer capacity holder requires capacity if the state wants - it's an option with respect to its share of associated state gas. Mr. Loeffler opined that the contract answers a lot of the criticisms. Noting FERC has an entire enforcement division, he said while the hotline clearly handles some disputes, there are many other enforcement tools, discussed by Mr. Pease previously. He turned to the "most favored nation" clause as it relates to royalty in value (RIV) and royalty in kind (RIV). Mr. Loeffler opined if the state operated in an RIV world, the "old netback world," and didn't need to market its own gas, the producers' bids would be that much larger because they'd have all their gas plus the associated state royalty gas, which would be RIV gas. That isn't the case, however. Article 10.1, capacity management, says that if asked, the producer will acquire capacity for the state in the state's own name - not a bundled name. Thus he said the criticism isn't fair with respect to the contract language. He deferred to Mr. Clark and Mr. Griffin. 11:52:26 AM MR. CLARK discussed the state's policies and the reasoning for what was done. He agreed this was a hotly contested article, because taking gas in kind raises concerns about the state's risk, concerns that are critical to mitigate. To the maximum extent, the desire was to mimic the RIV world, with three principal objectives: 1) Never be short of pipe, and always have enough capacity to get the gas to market; 2) be in essentially the same position as now with respect to the percentage of empty space on the line, and don't have excess ullage; and 3) make these adjustments on a 30-day basis, which producers don't do among themselves. He said the state also has the benefit of information coming from each producer that reveals where the gas is coming from and where the capacity is being used - information the producers don't get from one another, which will level the playing field. Mr. Clark noted, with respect to the second item, that DNR has developed a highly innovative system that, like most of this article, is new and creative in how it protects the state by mitigating the impacts of taking gas in kind. He predicted Alaskans will view this article later as putting the state as close as possible to the RIV world while achieving the benefits of gas in kind; those benefits include in-state use and reducing disputes. Mr. Clark voiced belief that those policy objectives were met through hard-fought negotiation. Acknowledging the need to have FERC look at it, he opined that it fits closely enough with FERC policies - particularly relating to Alaska - to receive approval. Lauding DNR for fantastic job on behalf of the state, Mr. Clark commended Mr. Griffin in particular. 11:57:27 AM ^Ken Griffin, Deputy Commissioner, Department of Natural Resources KEN GRIFFIN, Deputy Commissioner, Department of Natural Resources, began by saying that under the administration's concept a company must accept the terms of Article 10 in order to obtain contractual fiscal certainty. If Anadarko chose not to accept Article 10, for instance, it wouldn't be a party to the upstream uniform fiscal contract or the fiscal-certainty provisions, at least under the administration's current concept. SENATOR BEN STEVENS asked: When a shipper signs a FT commitment, is it also part of Article 10? MR. GRIFFIN answered no. He explained that the signing of the FT commitments and so forth is subject to FERC, which will ultimately accept or approve the rules under which it is done. Rather, the current discussion is at the fiscal-contract level. The three producers that intend to deliver gas to this project will have the opportunity to sign this contract, or other producers will be able to sign the uniform upstream fiscal contract, which will provide similar upstream fiscal provisions. In signing that contract, they receive the fiscal-certainty provisions, but also make certain commitments. One such commitment is being bound by the provisions of Article 10. 12:00:33 PM SENATOR BEN STEVENS posed a scenario in which an explorer comes in later through an expansion, and the shipper has a certain amount of volume of which he presumed the state would have the same 20 percent approximately. MR. GRIFFIN noted it would depend on whether it came from state acreage. SENATOR BEN STEVENS asked: When that new producer signs an FT commitment, is it piggybacking on the state volume, or is that state volume absorbed in the state's capacity agreement? MR. GRIFFIN answered in two parts. First, if a new producer comes in and doesn't sign the uniform upstream fiscal contract, the lease provisions prevail. That producer would be responsible for obtaining capacity for all the gas, including the state's share. The state would take RIV, and taxes would be paid under the tax statutes. The entire capacity commitment would be that new producer's responsibility. SENATOR BEN STEVENS suggested it is an option for the new shipper to sign the upstream agreement or maintain the status quo. MR. GRIFFIN replied he'd assume so, yes. SENATOR BEN STEVENS asked whether that is along with the capacity agreement. MR. GRIFFIN explained it is an all-or-nothing deal. To get the benefits of fiscal stability, a company must take the commitments in the contract or in the uniform upstream fiscal contract that go with it. He turned to the second situation, where a new producer comes in and signs the upstream fiscal contract; in that case, Article 10 requires the producer and the state to come up with their FT commitments, which are bids. Provisions in Article 10 that don't quite mesh with FERC's way will have to be worked out. He surmised, from FERC's standpoint, that the producer would have to show up with a bid, as would the state. From that point forward, Article 10 would take over. If production changed, there'd be balancing of the throughput and ullage between that producer and the state. The committee took an at-ease from 12:05:15 PM to 1:13:09 PM. MR. GRIFFIN emphasized that this capacity-management article is novel, to rebalance risk with the producers in order to address a novel situation in which a royalty owner is taking long-term, serious financial transportation commitments without control over the upstream. He also noted capacity issues are subject to FERC approval, and the state fully intends to bring this before FERC. The contract contemplates that the capacity issue will be under FERC regulation. If this cannot be approved by FERC, then the contract says the producers and the state will attempt to negotiate a substitute. Mr. Griffin expressed hope that there'd be enough FERC guidance in such a case to figure out how to craft a provision to accomplish this and then meet any regulatory hurdles. "We have acknowledged and accepted the FERC jurisdictional issues," he added. 1:16:04 PM MR. GRIFFIN highlighted side rails to the scope of this article: the capacity commitments sought by a producer plus those commitments sought by the state for production from that producer. If 80 percent of the commitments are the producer's and 20 percent the state's, that 100-percent capacity commitment is a side rail; there are separate side rails for each producer. Neither the producer nor the state has the opportunity to expand under Article 10; rather, they have the right and responsibility to balance the capacity commitments within that 100 percent between the two, based on the throughput coming from that producer's properties. He said there is no interaction between the producers under Article 10. There is no transfer of capacity between the producer and the state beyond what is dictated by the share of production flowing to the state and to the producer. Thus Mr. Griffin said the state has the opportunity to get all the gas produced by that producer that is owed to the state. The state can get all that gas off the North Slope as it is produced. Conversely, if the pipe isn't kept full, the state bears no more than its share of the empty pipe costs - the ullage costs - related to that producer's production. That is an absolute side rail written into Article 10. 1:18:17 PM MR. GRIFFIN offered an example in which Anadarko goes to an open season to obtain capacity for production from its share of Alpine production, 100 million a day, of which 20 percent is the state's gas under the contract. Anadarko seeks capacity for 80 million a day, and the state for 20 million a day. The provisions of Article 10 would need to dovetail with the FERC requirements; this remains to be done. The commitments are for 20 years. If Anadarko's Alpine production declines, since 90 percent of its acreage is on non-state land, it could pick up the remaining production from non-state land. Hence the state's share of the gas might be 7 percent. It's tax gas - the state has no royalty there. Thus Anadarko would be motivated to keep its 80 million a day full, for the life of that FT commitment. If production flowed completely to the non-state acreage, the remaining 13 million of empty pipe would be state capacity, and the state would bear responsibility for it. He explained that Article 10 would automatically correct for such a situation, shifting 93 percent of the empty pipe back to Anadarko because the company chose to move the production to non-state acreage. The state would still bear some of the empty pipe capacity, in the same proportion Anadarko has. But under what was proposed in Anadarko's comments, the state would bear the entire cost of that empty pipe. This is exactly the scenario the state fought to prevent with Article 10, Mr. Griffin emphasized. He posed another situation, emphasizing that, in both cases, the risk is entirely on the state unless Article 10 is in place. Thus Mr. Griffin said he was appalled that Anadarko would say its interests are aligned with the state's and that Article 10 should be removed. He stressed that this is one of the biggest factors in the contract to ensure the state's risks aren't disproportionate to those of the other producers and shippers. 1:22:35 PM MR. LOEFFLER informed members he would look at Anadarko's comments and respond as part of the FIF. Turning to state- initiated expansion, he reported that in comments from four or five independents, only Anadarko raised detailed comments about Article 8.7, whereas one made some comment and two said nothing. Mr. Loeffler suggested balancing what was heard and what wasn't heard, but he also acknowledged there are some good technical points in Anadarko's comments on state-initiated expansion that might lead to changes. He emphasized that clause's beneficial purpose was to provide a third tool in the toolkit - although it is the second tool in terms of timing, since voluntary expansion must be gone through first, which will be in the LLC. Saying Article 8.7 would be looked at, but that he wasn't ready to drop it, Mr. Loeffler posited that there might be procedural advantages - which Anadarko doesn't agree with thus far - that would result in a faster resolution than from FERC, including the dispute- resolution terms under the contract. MR. LOEFFLER turned to RCA, noting everyone who has commented agrees they want FERC to have jurisdiction. Pointing out, first, that RCA is excluded from the definition of "state," he said RCA's jurisdiction - whatever it is - continues intact. Second, there is talk in the comments that non-owner shippers are at the mercy of competitors. However, these concerns relate to Shell, with a market cap of $127 billion; Chevron, $149 billion; and Anadarko, $19 billion. These are smart, astute corporations, Mr. Loeffler told members, and they know how to use the legal and legislative processes, and how to access RCA, which has its jurisdiction intact. 1:25:47 PM MR. SHEPLER said Anadarko's comments had highlighted something he hadn't seen in Article 10, that the capacity-management provisions are the only means by which parties under the contract - including those with an upstream contract - can move capacity back and forth. He asked whether Mr. Loeffler believes that is a correct characterization and, if so, what the basis is for this being exclusive, as opposed to Anadarko, for example, being able to take a capacity release from the state or sell gas to the state for use in its capacity. MR. LOEFFLER deferred to Mr. Griffin. MR. GRIFFIN first provided a general answer, saying FERC rules are established for selling or seeking capacity, with the following sideboards: The state's share of production from an individual producer is likely to shift over time, while at the same time that producer and the state have FT commitments, with the associated financial burden. Within that 100 percent of capacity sought by the producer and by the state for the production associated with that producer, as the share of the state's production shifts - whether up or down - the financial commitments for that 100 percent capacity shift proportionately. He noted if the capacity article is in place, the state has no right to seek capacity outside its terms. The producer does, however, and must do so under FERC rules, in which case Mr. Griffin surmised the producer's gas would have state gas associated with it. The capacity article would fall back into play, and identical capacity would have to provided to the state in that proportion so that the state's gas could get off the North Slope. With respect to going out and finding capacity for a new field, however, Mr. Griffin said it would be the producer's purview to initiate, and then Article 10 would ensure the state was dealt with proportionately. 1:29:31 PM MR. GRIFFIN explained that any producer that doesn't sign on to the fiscal contract will be subject to the lease and to the tax statutes, and thus will provide royalties. That producer will have to make long-term FT commitments. But it won't want to if, every 60 days, the state can switch back and forth as to whether it takes its gas in value or in kind. The producer will need a commitment from the state for one or the other. As long as Article 10 is in place, the state has no right to seek capacity outside its terms; the gas must be taken in value. Thus Mr. Griffin said the producer must seek capacity for the full 100 percent and then take the capacity costs off, in adjusting the RIV value, as happens today. He gave the following reasons. The producer doesn't obtain fiscal certainty under the uniform upstream fiscal contract. If a producer wants certainty under that contract, it will commit to Article 10, and the state will want to take its gas in kind. If the state wants to market part of it, it needs to market all of it. Mr. Griffin reported the producers were concerned that if the state could seek capacity independently, it could tilt the playing field in the state's favor along with all the benefits under Article 10. Therefore, it was decided that under Article 10 the state has no independent right to seek capacity outside the terms of that article. MR. GRIFFIN reiterated that the basis of Article 10 is to maintain parity between the state and each producer with respect to risk and the ability to get gas off the North Slope. He emphasized that the state has the unilateral right, at any time, to terminate Article 10. Ten or fifteen years down the road the state might find that getting active independently in that arena is to the state's advantage, for example, and could do so. CHAIR SEEKINS thanked the participants and invited the producers to testify. 1:34:29 PM ^Wendy King, ConocoPhillips WENDY KING, Director of External Strategies, ANS Gas Development Team, ConocoPhillips Alaska, Inc., said when it comes to terms regarding access for explorers to the gas pipeline, ConocoPhillips offers a unique perspective and a strong track record on the forefront of North Slope exploration. While many believe BP, ConocoPhillips and ExxonMobil are commercially motivated and aligned in a similar fashion, many times during negotiations they didn't see eye-to-eye. She referred to Article 10 and Mr. Griffin's discussion of varying state equity across the North Slope. Ms. King said the producers also have varying interests in those fields, which creates complications when trying to find a balance that works for all parties. Similarly, Anadarko has a unique portfolio. MS. KING emphasized she is pleased to see alignment between Anadarko and ConocoPhillips in wanting to see the gas pipeline project advanced, and to see Anadarko's sense of urgency regarding this project. Ms. King noted Anadarko said, in its opening comments, that one of its top Alaska priorities is to have a gas line built as soon as possible, which will stimulate new gas exploration and improve oil exploration economics. However, she expressed concern that some of Anadarko's comments seem to contract the opening remarks. She informed members that ConocoPhillips, with others including Anadarko as a minority partner, has been exploring in NPR-A and the Alpine area successfully for gas as well as oil; she offered to provide copies of three press releases. Ms. King noted ConocoPhillips was mindful during negotiations that having common fiscal terms for assets like NPR-A would facilitate its ability to advance potential projects there. ConocoPhillips is a supporter and believes the upstream model contract will help create that aligned position to allow continuing to advance its activities in those regions, Ms. King told members. MS. KING also reported that ConocoPhillips sees the upstream model contract as key to motivating its exploration efforts to fill the gas pipeline, which she anticipates will require about 15 Tcf of additional gas, and more if the pipeline is expanded. If those additional volumes are found in commercial quantities, ConocoPhillips is confident that expansion and other opportunities will exist on this pipeline to get that gas to market. ConocoPhillips also believes there is a possibility - which FERC policy requires - that any interested party can bid in the open season, since it is an open-access line. Thus volumes beyond Prudhoe Bay and Point Thomson may possibly show up at the initial open season. 1:38:02 PM MS. KING turned to ConocoPhillips' role as a potential shipper, highlighting the commitment to continuing to prepare for the open season in order to make appropriate decisions - with the working-interest owners in those respective assets and with AOGCC - to have each field ready for the approved offtake and development. Not all parties to the assets are parties to the proposed fiscal contract. Thus ConocoPhillips needs to work, as a shipper, with the working-interest owners in those respective fields to get those assets ready for the open season. She highlighted Anadarko's concern that this would be a producer-affiliate-owned pipeline; that a premature open season could be proposed to shut out explorers; and that an open season before year-end 2008 would seem premature. Ms. King indicated the existing Project Summary, a public document, as well as the Qualified Project Plan, also a public document with her company's stranded-gas application, both estimate an open season won't occur until 18 months to two years from the start of project planning. Ms. King said this timing is consistent with Anadarko's estimate of year-end 2008 if the fiscal contract can possibly be executed in 2006, and she doesn't believe this is a premature open season. She said ConocoPhillips believes this project needs to be diligently pursued; adding further delays to wait for exploration success is an unnecessary burden on the project. Ms. King noted FERC Orders 2005 and 2005-A, regarding timing for that initial open season, are to ensure adequate notice is given to all prospective shippers. In addition, ConocoPhillips will update the Project Summary annually, so people will have other ways to know how the project is progressing. MS. KING emphasized that project planning and pre-permit application activities are real, both from a shipper and a pipeline company perspective; a number of pipeline company work activities will need to be pursued in those phases. The open season needs to be orchestrated for both U.S. and Canada, since there are issues such as the Alberta-to-Lower 48 offtake plan. 1:40:26 PM MS. KING explained that some of this work will be done by shippers and some by the pipeline company. The affiliate rules will be "stepping in," and the very rules ConocoPhillips and FERC have talked about will ensure the companies keep their different hats on during preparation. She expressed surprise at some references about the pipeline needing to take actions with respect to what AOGCC decides, because she said those are shipper issues - getting the shipper ready for the open season. MS. King noted the pipeline will be thinking about what it needs to do to get ready for an open season from a pipeline perspective. MS. KING asserted that delaying the open season beyond 2008 only delays the project, which isn't in the interests of ConocoPhillips or the state. Potential shippers have had years to get ready for an open season; since 2002, the project sponsors have been indicating their desire to get the necessary government frameworks in place. She said ConocoPhillips has been actively driving these efforts at state and federal levels. Delaying development of the known resource in exchange for unpredictable exploration programs seems a high risk for the state and the pipeline. Furthermore, slowing the project is inconsistent with Article 5, the work commitments, which require diligent advancement. An open season is necessary to finalize the project design and to meet those permitting requirements. She referred to previous discussion, noting one potential solution to a concern was advanced by the producers during the FERC open-season-rules process: allow a pre-open-season commitment process, which allows base shippers to commit to the project and allows an open season at a final later date. However, Ms. King recalled, the state and Anadarko argued against this proposal, which she asserted would have been in everybody's interest, with the result that FERC issued rules that would have prorated down only the original shippers, effectively eliminating this option. 1:42:30 PM MS. KING countered the idea that someone must find gas in order to show up at the initial open season. If parties' exploration efforts haven't been successful in the last few years, they can still consider showing up and taking out a FT commitment on some "risk exploration" volumes. There'd be seven to eight years to continue the exploration appraisal-and-development program before commercial operations commenced. It is a risk-based commercial decision each party can make. She addressed the comment that the contract should reflect the design of the project described in the application. Ms. King noted Article 4.1 already says this will be a large-diameter pipeline. She said the specifics of project rates cannot be committed to because there hasn't been an open season, and thus it's premature to dictate the rates for the initial open season. She turned to the design, indicating she believes there has been confusion about ConocoPhillips' ongoing petition with FERC, submitted June 2006, which challenges the commission's assertion of authority in Sections 157.36 and 157.37 to mandate - long after the open season has ended - increased capacity for an Alaska gas pipeline project or expansion, and to dictate the amount of unsubscribed capacity/unused expandability that initial project must build in. Ms. King told members, "That is specific to the petition we're pursuing right now." MS. KING read another quotation from that petition which says the commission has adopted regulations that jeopardize timely permitting and construction of an Alaska natural gas pipeline in contravention of Congress's intent in enacting ANGPA. By the time the commission acts upon an application for a certificate of public convenience and necessity, a project sponsor will have spent several years and hundreds of millions of dollars developing the optimal project design, conducting the open season and preparing the certificate application. She went on to say that design changes imposed by the commission as conditions for receipt of a certificate could either scuttle the project entirely or require that additional time and resources be spent revising the project. This could delay the project that Congress, through ANGPA, sought to expedite. "We are focused on that issue in that ongoing petition," Ms. King concluded. 1:45:13 PM MS. KING turned to the capacity-management provisions. Concurring with Mr. Griffin about the challenges faced during lengthy negotiations, she highlighted efforts to have those provisions be consistent with FERC policy and to replicate how capacity would have been handled if the state were in the RIV world. "We believe we have been successful in doing that," Ms. King told members, noting provisions also say that if FERC finds inconsistency with its policy, there will be good-faith negotiations towards an alternative. She said ConocoPhillips stands behind the provisions negotiated with the state on capacity. Many of Anadarko's criticisms relate to provisions negotiated to provide the state the option "to follow the decisions that we will make regarding our capacity management, which means the state is going to see confidential information," Ms. King added. As to whether this precludes parties from putting capacity on the open market, she said Article 10.3(b) has provisions such that if ConocoPhillips - in its relationship with the state as a shipper on the pipeline for its volumes - finds it no longer has enough gas to fill those, the company is obliged to notify the state that it will go to the market to post its capacity. Ms. King explained: When we go to the market to post that capacity, the state has the option to pursue that as well, which means we are giving them confidential information that we're about to go to the market, to give the state the option to follow in that transaction. There's a reason why we have those confidential provisions in there, but we ... do believe that those provisions do allow that capacity to get to the market if it is not being used by the gas volumes associated with the state and ConocoPhillips and our relationship. 1:47:19 PM MS. KING gave a technical perspective to emphasize a point made by Mr. Loeffler. She said it wasn't anticipated that the producer's bid would be volume-inflated by the state's bid; the contract doesn't say that. Rather, the state will provide the paperwork to the producer, which will submit the bid independent of the producer's bid. This is a change from the RIV world. With respect to the capacity provisions, she indicated there is concern that the producer would get that capacity. If ConocoPhillips discovered a new field in NPR-A, for example, obligations in here ensure the state has the ability to receive value for its gas if it needs capacity on this pipeline. MS. KING reported that a concern of ConocoPhillips had been that the state could take that 20 million a day ConocoPhillips had acquired and turn around and give it to somebody else, posting it on the market, and then come back to ConocoPhillips and request more capacity for the field the state was about to develop. ConocoPhillips could continually have to get capacity that was being spun off to others. Thus some protections are written into the capacity-management provisions. 1:48:37 PM MS. KING noted she wouldn't raise some points, to give time to her colleagues. She emphasized that ConocoPhillips supports the public-comment process outlined in the Stranded Gas Act, believing it is important for the public and the legislature to ask such questions. However, ConocoPhillips believes it has a responsibility to respond when those concerns are inconsistent with the company's understanding of FERC policy; the fiscal contract drafted May 24; and how mega-projects should work. She related ConocoPhillips' belief that making one party subsidize another's access to the pipeline is a problem. Existing shippers shouldn't have to subsidize expansion or access for others. Existing shippers could include the three project sponsors - BP, ConocoPhillips and ExxonMobil - and the state, but also Alaskan local distribution companies (LDCs) or other explorers that show up at the initial open season. ConocoPhillips also believes FERC is the appropriate adjudicator of rate treatment in defining what a subsidy is, and that a pipeline company should have the right to propose the rate treatment in its FERC filing that it deems appropriate for a particular expansion. Ms. King said provisions are in the contract so any party can protest that as a shipper. She highlighted ConocoPhillips' commitment to trying to develop Alaska's gas resources. Between 2001 and 2006, ConocoPhillips drilled 47 wells - 19 in 2001 alone, mostly on the western North Slope. It frequently partners on those wells with independents and other new entrants, and it partnered with Anadarko in 24 of those 47 wells. The company is steadily moving its exploration to the west, Ms. King noted, with two NPR-A wells in 2005. MS. KING reported that ConocoPhillips is reviewing those comments on the proposed fiscal contract for which it has received copies; she and the team will review those. ConocoPhillips is commitment to working with the producers and the state to complete the LLC, and to finding a solution that hopefully will work for all parties to the fiscal contract and will facilitate legislative approval of the contract. 1:51:13 PM SENATOR ELTON asked why there would be reluctance to add other sponsors to the project; he suggested other testifiers could address this also. He gave his understanding that Anadarko has an interest in participating in the pipeline project. He surmised spreading risk as broadly as possible makes sense; it is one argument for the state's participation. MS. KING answered that she wasn't aware of some meetings and conversations referenced earlier, although some of her colleagues have been involved longer. For any party that wants to participate in the project, it is a commercial decision to be brought to the project sponsors for discussion. 1:52:42 PM ^Bill McMahon, Commercial Manager, ExxonMobil S.A. (BILL) McMAHON JR., Commercial Manager, Alaska Gas Development, ExxonMobil Production Company, recalled the formative stages of this project in 2001, when it was decided to have only three participants; they were still trying to see if there was a commercially viable project. He said there is a practical limit to the number of parties involved. He agreed with Ms. King that once the fiscal contract is approved and the project moves forward, nothing prohibits commercial transactions that could include others in the process. 1:53:30 PM ^David Van Tuyl, BP DAVID VAN TUYL, Commercial Manager, Alaska Gas Group, BP, echoed those comments, adding that once BP is confident there is a project - for which approval of a fiscal contract is a first and essential step - BP has said it would welcome participation of others that can add value to the project and take on the necessary risks, advancing the project and associated obligations. The key is getting to that place. He turned to Anadarko's comments, on page 18, that perhaps some specifics should be mandated about the project design. Mr. Van Tuyl expressed concern that this would preempt the open season process, putting the cart before the horse. He emphasized getting the design right, a fundamental tenet of the open-season process during which customers come together and meet with the pipeline company to get the project designed appropriately. While BP anticipates building a large-diameter pipeline, likely in the 48- to 52-inch range, BP doesn't want to preempt the open-season process. Stipulating the design or diameter may actually cause damage by limiting sources for steel, for instance. Thus BP believes it should stay with the FERC process and allow that open-season process to run its course. MR. VAN TUYL drew attention to Anadarko's concerns about the AOGCC process in setting the offtake rates at fields such as Prudhoe Bay and Point Thomson, and that those needed to be authorized before the open season. Indicating BP has had a series of meetings and hearings with AOGCC about that topic, Mr. Van Tuyl said analysis of the appropriate offtake rates at those fields has been underway for over a year. He reported that the three individuals before the committee today provided testimony before AOGCC multiple times regarding the timing of the offtake-rate decision; its potential impact on the project; and how that dovetails with the open-season process. As a result, a process was established jointly with AOGCC to ensure they could complete the technical work that needed to be done within the timeframe in order to avoid impacting the project. Mr. Van Tuyl said he thinks it is a valid concern, and it is work that needs to be done, but there is already a process identified to meet those objectives and to establish those rates. He noted concern that the preliminary engineering wouldn't be completed before the open season occurs. Mr. Van Tuyl surmised the Gantt chart in BP's Project Summary might not be clear, but suggested the associated wording is. He said the preliminary engineering - front-end engineering and design (FEED) - will be completed before the open season. A design must be submitted as the basis for one's certificate application. 1:57:18 PM MR. VAN TUYL recalled Anadarko's statement about planning to drill its first gas-exploration well in the Foothills this winter. He commended this because the project needs additional exploration volumes: 35 Tcf of known resource is a great start, but more is needed to keep the pipeline full for its expected duration. However, he recalled hearing similar statements in previous years from Anadarko. In 2001, as part of the $125 million joint study, a preliminary information session was conducted for all interested potential shippers on the pipeline; at the time, Anadarko said there may not be carbon dioxide (CO) 2 associated with its gas that may be found in the Foothills, and thus had requested that the CO-removal service be unbundled in 2 the gas treatment plant (GTP) and that there be a separate compression service and CO service. 2 He indicated BP heard that concern, now reflected in Article 8.5 of the contract where it specifies the GTP will offer unbundled service. Mr. Van Tuyl explained that BP disagrees with the assertion that, because of Anadarko's decisions not to drill exploration wells, an open season in two years' time is premature. He added that BP wants to see pursuit of a gas pipeline project for Alaska as soon as possible. MR. VAN TUYL also disagreed with the suggestion on page 3 of Anadarko's comments that the producers might intentionally design a smaller system specifically to exclude explorers. Noting BP has moved to larger diameters to make the project economics work, he said it makes no sense to build an uneconomic pipeline just to exclude others. Nor is that BP's intent. In addition, FERC would ensure that didn't happen as part of the open-season process. He highlighted the need for exploration volumes for this project, whether at day one or later. 2:00:08 PM MR. VAN TUYL turned to capacity management, reiterating Mr. Griffin's point that the state has the option to operate under Article 10. The state can obtain capacity on its own from day one, operating under Article 10, or later can decide it no longer wants to operate under that article, at which time it would provide notice. The state just doesn't have the flexibility to operate under both at the same time, for the reasons discussed. He agreed that BP, ConocoPhillips and ExxonMobil hold most of the known gas resource on the North Slope; that is because those companies have made the billions of dollars of investment necessary to define and develop those resources. Mr. Van Tuyl also agreed with Mr. Loeffler that it is difficult to reconcile some of Anadarko's statements. One is that Anadarko doesn't want to delay the project and wants a gas pipeline as soon as possible, but doesn't want an open season until ready, whenever that is. Mr. Van Tuyl remarked that BP can't dictate the pace at which others choose to explore, and doesn't think Alaska should continue to wait for a gas pipeline. He concluded by saying BP wants to continue to support advancing the project as soon as this body authorizes the contract. He deferred to Mr. Keithley for FERC-related issues. 2:02:00 PM ^Brad Keithley, Jones Day, Counsel to BP BRADFORD G. KEITHLEY, Jones Day, Counsel to BP, informed members he would offer points from having worked on other projects, one being BP's Baku-Tbilisi-Ceyhan (BTC) project, from which the following was learned: Don't try to tie down a large number of detailed provisions at the outset, but let those evolve as the project occurs. In that project, the partners and governments involved weren't overly detailed at the outset about design and other requirements. They allowed the study to go forward; from the study they designed the pipeline; and from the design they determined various rules, regulations and rates that would apply, in the normal course. Referring to yesterday's testimony, he conveyed BP's pride that this highly successful project came to fruition. Noting this Alaska project is in an early stage, he cautioned that imposing restrictions now will reduce needed flexibility as the project becomes more defined. He turned to Anadarko's concern about potential mistreatment of nonaffiliates. While agreeing such concerns are serious, Mr. Keithley said FERC regulations already provide remedies for all those. There really are no independent pipelines in the Lower 48; instead, almost all have either affiliated producer companies or affiliated marketing companies. As a result, FERC has extensive rules for affiliate treatment. He referenced recent testimony about Order 2004; Order 670, which prohibits any action for the purpose of impairing, obstructing or defeating an honest and well-functioning market; and FERC's enforcement powers. Mr. Keithley said all those powers and rules come into play, providing Anadarko with an effective remedy down the road if the concerns come to fruition. He opined that Anadarko has shown it knows how to use the process. Recalling its participation in the congressional process that resulted in ANGPA, Mr. Keithley predicted participation in the FERC process. He surmised Anadarko is trying, through the contract, to preempt the FERC process and to impose its preferred remedies in advance. For reasons outlined by Mr. Loeffler and Ms. King, he said those instances - if they occur down the road - should be left to FERC enforcement, rather than contemplating such possible problems now. MR. KEITHLEY also opined that because of the state's ownership interest, this project will have more enforcement than any project ever in the Lower 48 or internationally. The state can play an important role through its ability to complain as an owner - both internally, if unfair or discriminatory interests are seen, or externally with FERC. He suggested while the hotline isn't the only FERC remedy, it will probably play a more important and useful role in connection with this project than in the Lower 48, again because of the state's ownership interest. If producer-owners try to direct the pipeline in a way that results in an unfair or discriminatory advantage, there will be an opportunity to raise those issues. Although the hotline doesn't always have all the information needed to deal with allegations of discrimination, here the state will be an internal policeman of sorts that can provide that information immediately to FERC and the hotline if an unfair advantage is perceived. This will reinforce the hotline's ability to moderate the pipeline's behavior, Mr. Keithley predicted. 2:08:52 PM MR. KEITHLEY, in response to Senator Wagoner about Lower 48 pipelines, referred to previous testimony about the preamble to FERC Order 2004. Mr. Keithley said he believes 16 pipelines are affiliated with producers, and 6 of those carry more than 60 percent of the throughput. Probably all pipelines are somehow affiliated with marketing companies, which buy gas in the field from producers and then transport it through the pipelines and sell it in competition with independent marketers. Those pipelines have the same incentives as producer-owned pipelines to bias the rules in favor of their marketing companies. Thus FERC developed this extensive set of regulations to deal with affiliate relationships. It is a rare exception that a Lower 48 pipeline is affiliated with neither a producer nor a marketing company. SENATOR WAGONER asked whether "affiliated" means they have contracts with the producers to ship. He recalled being told in the Senate Resources Standing Committee months ago that there basically are no producer-owned pipelines transporting gas. MR. KEITHLEY specified it means ownership: the pipeline owns the marketing company, the marketing company owns the pipeline or a holding company owns both. There aren't many pipelines owned by producers, but almost all are affiliated with marketing companies. He noted FERC found that pipelines affiliated with marketing companies are as likely to be biased in favor of those companies as pipelines affiliated with producers are likely to be biased in favor of the producers; thus FERC developed regulations. CHAIR SEEKINS surmised ownership is the common thread. The marketing company owns the gas it ships to market, just as the producer owns the gas it ships. MR. KEITHLEY affirmed that. He reiterated earlier points in response to Senator Stedman. 2:14:44 PM SENATOR ELTON asked: Given Governor Murkowski's comments, as well as the presumption of many that this pipeline will be a certain size - over 4.0, expandable to somewhat less than 6.0 - and the opportunity later to change the project plan as more things become known, why not have a starting presumption, with a later change in the project plan if necessary? MR. VAN TUYL replied that the contract refers to the Project Summary, which outlines the base design, referencing a large- diameter pipeline and the 2001-2002 study wherein the base design consisted of a 52-inch pipe. The reason for not stipulating in the contract that the design includes a specific diameter or turbine driver, for example, is there isn't enough information today. Technology could change. High-strength steel might be applicable, for example, enabling a design change to save money. Offtake might not be guessed correctly. Additional volumes may become available and thus be bid at an open season. The desire is to avoid mandating limitations that might result in a suboptimal system, which wouldn't be in anyone's best interests. SENATOR ELTON surmised a reference in the contract isn't as strong as having it in the contract itself. MR. VAN TUYL emphasized the Project Summary is a living document that the contract requires to change from time to time. It didn't seem efficient to impose the burden of requiring all parties to execute a written amendment whenever there is a design change. The Project Summary and the Qualified Project Plan are therefore separate from the contract, but the contract requires updating of those periodically and allows the project itself to be executed efficiently. 2:20:26 PM MR. McMAHON stated agreement with everything said so far. For Senator Wagoner he listed seven producer-owned pipelines: Maritimes-Northeast, Discovery, Green Canyon, Destin, Garden Banks, Nautilus and the new Rockies Express that is moving forward; he also mentioned the Alliance pipeline from Canada to Chicago. He returned to another matter, in order to put the appeal of the FERC order in context. Mr. McMahon explained that FERC wrote itself the unprecedented right to mandate a design change in the pipeline. This puts undue risk on the initial shippers. If FERC requires a higher-volume pipe built just in case additional volumes are found, it requires overbuilding the pipeline without additional underpinning for the extra capacity. If those volumes don't materialize, the initial shippers bear the cost. The pipeline always recovers its costs. MR. McMAHON further explained, "That's why we're fighting that unprecedented right. It's not to try to find a way to manipulate this pipeline. It is to make sure that we can design the pipeline to match the results of the open season, which we think is the prudent thing to do." He said while pipelines can build additional capacity on speculation, it isn't prudent for this risky, high-cost pipeline. The desire is to match the open-season commitments with the project design, and to build in the appropriate amount of expandability for the future. Thus the initial shippers will know what they're signing up for. CHAIR STEVENS thanked the testifiers and invited the Anadarko representatives back to the witness table. 2:22:34 PM SENATOR BEN STEVENS recalled speculation as to when a company could actually book its North Slope gas reserves. He gave his understanding that those aren't bookable until the time of project sanctioning, authorization for expenditure and issuance of a certificate of public convenience. He asked Anadarko: Do you have proven gas reserves? When would your discovered reserves be bookable? Would you have to have a FT commitment, or would it just be a transportation system to market? He requested an answer at some point for Anadarko and other explorers. He also asked: At that time, are other companies that have reserves on the North Slope allowed to book it because there is a transportation mechanism, or does the SEC require an FT commitment to be able to book it? MR. HANLEY offered to get an answer, noting he doesn't work in that area but that there are guidelines on the timing for booking reserves. MS. NEWMAN said she didn't know and wasn't an SEC lawyer. MR. HANLEY interpreted as follows: If a pipeline is built, if somebody explored and found gas, does there have to be a full- time commitment, or is it just because there's a pipeline? SENATOR BEN STEVENS said he didn't know, suggesting it is blurred. They're not bookable now because there isn't transportation capacity to market. But if that exists, can somebody then convert undeveloped resources to bookable reserves, benefiting everybody? SENATOR STEDMAN suggested perhaps asking the consultants to guesstimate the values of the producers' bookable reserves for the aforementioned. The committee took an at-ease until 2:26:46 PM. MS. NEWMAN asked: If the offtake isn't known and other factors are ambiguous, why not hold a nonbinding open season to see if there is something else out there or if it is realistic? While FERC requires specifying the pipe design, and perhaps 30 other items, for a binding open season, most pipelines hold a nonbinding open season first, to determine market interest; they may even hold a second one. They may present a scenario and inquire about interest and what people are willing to pay. People respond, and it goes back to the drawing board. She noted this pipeline has been studied for years, with a $125 million study concluding the design isn't economic. Giving some history, Ms. Newman recalled that pre-subscriptions were opposed by many and yet FERC allowed them, saying it might be suspect if the design only suited pre-subscriptions. If there isn't enough capacity when the real open season is held, therefore, FERC might require proration of the capacity signed up for in advance of everyone else. As a matter of fairness, FERC then agreed if somebody signs up under the same terms and conditions as the pre-subscription, that is prorated too. Ms. Newman noted pre-subscriptions could be signed up today. MS. NEWMAN emphasized that affiliate rules don't kick in until there is an affiliate, which doesn't happen until the project entity is formed. Thus there is no issue until then, and there is no enforcement policy at FERC for this. It will get sorted out when the open season occurs, because nothing has been violated. However, the problem arises before the rules kick in. A nonbinding open season should be held if there is a need to figure out what is going on. She asked: Why should the state object to having authority to decide it's a little early for a binding open season? Anadarko wants a pipeline, Ms. Newman explained, but doesn't want to be disadvantaged by having everything etched in stone before the open season. If the playing field is level, it isn't a problem. 2:32:12 PM MR. KEITHLEY remarked that FERC Order 2005 specifies affiliate rules will apply from the time of planning for the open season; as BP interprets it, this is from the date the project entity is formed - soon after the fiscal contract is passed. In the Lower 48, by contrast, the rules don't apply until after the pipeline is certificated by the commission. Order 2005 has an exception for the Alaska pipeline because of heightened concern about affiliate relationships. MS. NEWMAN suggested she and Mr. Keithley don't disagree, but have different perspectives. She concurred that the rules don't apply until the project entity is created. Until that happens, there is no affiliate to apply a rule to, regardless of how early the planning process is begun. MR. KEITHLEY added that the project entity being discussed is the LLC, which he predicted would be formed very soon. The committee took an at-ease from 2:34:07 PM to 2:45:06 PM. ^Gross versus Net Tax ^Dr. Pedro van Meurs, Consultant to the Governor DR. PEDRO VAN MEURS, Consultant to the Governor, discussed the fundamentals of a gross versus net tax, giving a PowerPoint presentation with an accompanying handout dated July 25, 2006. He highlighted common ground and differences between HB 3004, proposed by Representatives Berkowitz and Gara, and his own proposal made to then-Governor Knowles on April 29, 2001. He said this goes to the heart of gross versus net. Like HB 3004, his 2001 proposal completely modified the outdated economic limit factor (ELF), since the field and production formulas needed to be adjusted. It had a strongly progressive tax based on price, with much higher tax rates under high prices and zero tax when low, and it had incentives for heavy oil. The big difference from HB 3004 was significant tax credits. He explained that he'd proposed a strongly price-sensitive tax because of a good experience with clients two years earlier, when oil prices were declining - the best time to propose such a tax; one client now is highly satisfied with its oil and gas revenues, a royalty equivalent to 40 percent. However, Governor Knowles hadn't accepted his similar proposal, not feeling politically that it was the right moment for such a dramatic change; if he had, the state would be $6 billion richer today. Dr. van Meurs noted these gross taxes have a short life. Whenever it is discovered that the formula is outdated, it is costly and difficult to adjust. Revenues are lost meanwhile. 2:52:23 PM DR. VAN MEURS focused on revenues versus structure, beginning on page 5 of his presentation. He highlighted three fiscal options that create equal revenues, two based on tax credits and one based on minor or no credits. The former included a system based on statewide revenues like the proposed petroleum production tax (PPT), as well as his 2001 proposal that is based on gross revenue per field with no deductions for capital or operating costs. The latter was similar to HB 3004, primarily based on the gross structure in the fields. For two key North Slope fields that produce 50 million and 150 million barrels, revenues would be equal under those options, as shown on pages 8-9 of his presentation. He said these fields are typical of what oil companies believe will be the next generation of more difficult, more viscous, somewhat heavier oil that will be encountered on the North Slope. If he'd used fields with much lower costs, the PPT would look much better because deductions would be less. DR. VAN MEURS explained that pages 10-12 describe how he'd modified each of the three options to result in equal revenue. For the PPT variation, he'd used 20/20, adding a progressive feature based on net, starting at $35 a barrel and increasing 0.2 percent for every dollar, with a maximum rate of 50 percent; it didn't include a corporate allowance of $12 million in tax credits or a $73 million deduction as it had originally. His 2001 proposal had a flat rate of 15 percent; investment tax credits of 40 percent, applicable to all capital expenditures; a price-adjustment factor starting at $50 a barrel based on ANS divided by 50; and a maximum rate of 40 percent. He highlighted the similarity to Senator Wagoner's recent gross-tax proposal. 2:59:21 PM DR. VAN MEURS, in response to Senator Wilken with respect to the flat nominal rate of 15 percent, specified it is gross after deduction of the royalties. In addition to being in Senator Wagoner's proposal, it was in HB 3004, as he recalled. SENATOR WAGONER clarified he'd done his proposal before receiving copies from Dr. van Meurs. DR. VAN MEURS noted page 12 of his presentation shows the HB 3004 variation for comparison. He'd taken the existing nominal rates and ELF, using a minimum rate of 6.5 percent, compared with 5.0 in HB 3004; a rate reduction below $35 by 6 percent so that by $20 per barrel the rate becomes very low, whereas HB 3004 lowers it by that point to 12; a similar concept to HB 3004 for the price-adjustment factor, but using $35 a barrel as a basis, rather than $20, taking ANS and dividing by 35; an extra percentage, like HB 3004, but not as aggressive, using 3 percent more between $70 and $120 a barrel; and a maximum rate of 40 percent, similar to HB 3004. Referring to all three scenarios, Dr. van Meurs said the whole curve of revenues can be matched for a particular field. This filters out the revenue aspect, which allows concentrating on what is important: the structural differences between these proposals. He turned to pages 13-17 of his presentation, "Impact on Investors," related to the three options. Dr. van Meurs explained that for the two examples with 40 percent tax credits, the rate of return is significantly higher than for the HB 3004 variation. Page 14 discusses the $150-million-barrel case, showing a significant drop in the rate of return even with the same revenues to the state. Page 15 shows expected monetary value (EMV), a main indicator of the attractiveness of exploration, since it is the net present value at 10 percent, adjusted for the geological risk. This shows "EMV 10" is much lower without tax credits or within minor ones. The same is shown on page 16. For a bigger field, the differences are less because there is more value. 3:05:02 PM DR. VAN MEURS explained how the government's revenues can be equal and yet the rate of return and economics for the companies can be so much better under one proposal than another. Page 17 shows no reduction of PPT if investors invest $1 million under the HB 3004 variation, without tax credits. With a 40 percent tax credit - or a 20 percent deduction and 20 percent credit under the PPT - investors perceive that investment as a $600,000 expenditure because they'll receive $400,000 back from the state in tax credits. He addressed pages 18-34, "Fiscal Structure," noting page 18 shows the aforementioned is achieved by first giving investors a tax savings when investing, and then taking more tax later on. Dr. van Meurs pointed out that when giving tax credits, governments first grab more revenues and then reward reinvestment in that jurisdiction, rather than simply giving what was intended in the first place. 3:09:16 PM SENATOR BUNDE indicated he'd read this morning that the court of appeals, in the Como case, found an Ohio tax scheme that benefited a local business unconstitutional under the commerce clause. Noting that proposals here involve tax credits, he asked if those also could be found unconstitutional under that clause, and whether Dr. van Meurs was familiar with that case. DR. VAN MEURS replied he wasn't familiar with the case. He suggested it is a constitutional legal question perhaps best reserved for the lawyers. He added that the PPT proposal was reviewed in depth by the attorney general's team. He surmised the issue isn't at stake here. 3:10:33 PM SENATOR ELTON referred to page 18 and prior pages of the presentation that discuss internal rates of return. He asked: Can't that be accomplished with a gross tax and then a "clawback" provision, as discussed earlier with PPT? Doesn't that also have the net effect of encouraging investment and lowering the tax rate so there is a higher internal rate of return? DR. VAN MEURS answered yes, the "two-for-one" proposal - if that is what Senator Elton is referring to - has the same effect because it is a method of providing tax credits. What is attractive to investors in Alaska that already have production and are benefiting from the two-for-one proposal is this: They get a tax credit on top of a tax credit under the PPT proposal, which makes the rate of return even higher than the base PPT. SENATOR ELTON interpreted this to mean the internal rate of return can be increased for a company with a gross that applies a clawback. The result would be the same kind of curves shown in the earlier graphs. DR. VAN MEURS agreed. He recalled that when Governor Knowles originally requested review of the existing production tax, the political guidance was to see what could be changed in the current system, based on gross, to increase the rate of return. Dr. van Meurs had proposed there could be work on gross as long as these tax credits were included; the effect would be identical to net in terms of investment. Referring to the graphs on page 17 and previous to that, he said from an investment-encouragement standpoint, a 40 percent tax credit is what counts. Had HB 3004 included this credit on all capital expenditures, its impact on the attractiveness for investment and the incremental rate of return would have equaled the PPT proposal. CHAIR SEEKINS asked whether the difference between the PPT and the clawback is that the latter is strictly on capital expenditures (CAPEX) and not operating expenses. DR. VAN MEURS replied yes. The 20 percent tax credit in the PPT and the clawback only relate to capital expenditures. The cost deductions that exist in order to arrive at net revenues apply to both capital and operating expenditures. The difference between his earlier proposal to Governor Knowles and the proposal on the table now is this: Under the former concept, there was no deduction for operating costs. From an investment rate-of-return point of view, however, the numbers can be tweaked so it comes out the same for a particular field. 3:15:14 PM SENATOR DYSON recalled that the major thing that doesn't get taken care of with a gross production tax is deductions for "challenged" oil. He asked Dr. van Meurs to remind members why using the traditional way for challenged-oil royalty relief is suboptimal for the state. DR. VAN MEURS opined that the Alaska royalty concept - that if a field provides uneconomic under the agreed loyalty in the lease, the commissioner can be petitioned for royalty relief - is sound. It is common worldwide. Most governments realize a royalty could make a field uneconomic. Thus there is a gray area in which a government is interested in granting relief to get the development. From an investor point of view, however, it doesn't do very much. SENATOR DYSON suggested it's unpredictable. DR. VAN MEURS concurred. He said it is an essential component of a royalty framework, but isn't a fundamental concept to encourage investment. 3:18:53 PM SENATOR DYSON referred to heavy oil on the North Slope and asked: Do other jurisdictions allow asking for royalty relief in advance of making the investment, in order to get the assurance necessary? DR. VAN MEURS noted his presentation would address this later. Light oil clearly is on its way out. Many nations are considering changing their fiscal structures to accommodate heavy oil, and many jurisdictions have already done that. For example, Alberta addressed its large reserves of heavy oil by scrapping the royalty in favor of a profit-based system; although called a royalty, it is equivalent to the PPT. Governments have concluded that once they get to heavy oils, gross systems don't work well. The costs aren't known. Thus they go to a net system like Alberta's or else they predetermine a lower royalty level, as Venezuela, Columbia and Saskatchewan did. Some countries have a scale directly related to gravity. SENATOR DYSON recalled hearing about the difficulty in defining heavy oil and a mixture of heavy, light and medium oils in some formations. DR. VAN MEURS agreed, noting his presentation today would address that. There is a big difference between Alberta and the North Slope. Alberta's heavy oil is in a limited geographical area, Cold Lake; thus it was easy for the government to design a new fiscal system for that area. CHAIR SEEKINS asked how many other countries deposit 25 percent of the royalty into a permanent fund. DR. VAN MEURS replied that some nations, including Norway and Kuwait, have similar but not identical funds for future generations. CHAIR SEEKINS surmised a scheme reducing the royalty to accommodate additional costs for heavy oil would have the same effect on the permanent fund as on royalty revenue - reducing it 25 cents for every dollar. He suggested if a system could be designed to look at operating expenses as a deduction, rather than a royalty reduction, it would self-adjust as there are technological improvements or higher costs for the challenged oil, but it wouldn't shortchange the permanent fund in the end. DR. VAN MEURS agreed. He said royalties are the perfect gross- revenue concept. The PPT was designed to be highly flexible and leave royalties alone. In an extreme condition, however, with ample justification - and if there is a clear choice between no production and some - then the DNR commissioner can step in and lower the royalty. He noted a fund for future generations happens particularly in nations with limited populations that realize the need to set aside for the future when a large share of wealth derives from oil and gas. He emphasized the need to protect the royalty system, calling it the deep, long-term future of the State of Alaska. SENATOR WAGONER asked what keeps Alaska from coming up with a separate tax structure for heavy oil. 3:27:33 PM DR. VAN MEURS clarified that the problem with the North Slope is that everything is mixed together in the same geographical area. Additionally, there are shallow formations so cold that light oil becomes as viscous as heavy oil. It isn't possible to make separate arrangements based on groups of leases. Any lease could produce any mixture of light and heavy crudes, even from the same reservoirs. While a sliding scale could be constructed, as he'd done in 2001, it doesn't have the same guarantee for the state with respect to getting the maximum benefit from the resource. SENATOR WAGONER asked whether the primary cost will be capital expenses or operating expenses when heavy-oil production begins in earnest, and in what percentages. DR. VAN MEURS recalled that when he'd realized Governor Murkowski was willing to go beyond slight adjustments, he'd then offered a far better proposal, a full-scale net-revenue basis. That was the reason for developing the PPT. The reasoning goes to the heart of Senator Wagoner's question. A scale based on cash flow would be pie-in-the-sky, since nobody knows the costs of heavy oil. It is far better to say the costs aren't known. If costs are low under a net system, a lot is collected; if costs are high, less is collected. That is the concept of net. He further explained that a net system effectively deals with future uncertainty and is far more stable than a gross system, as other nations have discovered. Thus he'd made the recommendation, and the governor had agreed to go forward with a system in line with the international practice, with an eye toward investment. Dr. van Meurs expressed pride that the PPT proposal is now in front of the legislature. He turned to pages 19-20, "International Framework" and "Reinvestment or No Reinvestment." Dr. van Meurs emphasized that taking more tax and then giving something back if a company reinvests in the jurisdiction provides the same revenues, but investors are happy because they perceive it as getting 40 percent of their money back. A company that doesn't reinvest pays more tax. He reported that all governments in the Organisation for Economic Co-operation and Development (OECD) outside the U.S. that have important oil and gas production have figured this out, including Norway; Denmark; the Netherlands; the United Kingdom; Australia; and Alberta, Newfoundland and the Northwest Territories in Canada. Another 60 developing nations use a concept related to profits. Dr. van Meurs cautioned that this is the world Alaska is competing with, and in Alaska reinvestment isn't rewarded now. 3:38:49 PM DR. VAN MEURS explained why he'd strongly recommended a net system to Governor Murkowski. Pages 23-30 of his presentation show difficulties with a gross system with tax credits: 1) a relatively short shelf life for gross formulas, 2) that gross- based systems require definition of a field or unit to which the system applies and 3) the heavy-oil provisions just discussed. He addressed shelf life, noting Alaska's sound royalty-based system provides half its revenues. If another gross-based system is added, a very large amount would relate to gross. In 1989 there was great justification for the ELF formula. If gross is added to gross, however, there is concern about small marginal fields and highly profitable ones. The concern is how to make the ELF more flexible. The ELF is based on technical information, which Dr. van Meurs said changes quickly over time. DR. VAN MEURS noted after ten years, by 2001, Alaska's ELF was no longer appropriate. However, it took five more years before there was enough political momentum to change it. A lot of money was lost. After five or ten or fifteen years, gross formulas must be changed because of rapid technological changes in the oil industry. Dr. van Meurs said a net-based system is much simpler. Other nations have found if there is a net-based system and technology lowers the costs relative to assumptions, deductions go down and there is more tax. He turned to defining "field." Dr. van Meurs told members if a gross system is to be flexible from field to field, there must be a definition a field. While 20 years ago Alaska had well- defined units and fields, for the North Slope today it's no longer possible to come up with a clear definition. This is a fundamental problem with a gross-based system. He noted today's new investment opportunities are in shallow or deeper reservoirs or extensions of reservoirs or satellite fields, for example. While generating enormous amounts of new reserves, they cannot be called "new fields." However, the system is based on fields. This creates immense tension. Although it can be done, Dr. van Meurs said there will be constant struggle and lack of equilibrium among incremental investment in something that is already a unit or field and something that is a new field. Thus it is so much simpler to junk all of this and base it on something that makes far more sense - which all other nations are doing. DR. VAN MEURS discussed heavy oil. Probably the biggest problem of defining a gross-based system is what to do with heavy oil. While more leniency is needed, there is no sound economic basis for doing that. It is an immense problem because 5 billion barrels of the new oil to be produced is heavy oil. If future economics for heavy oil cannot be identified, how can a gross- based system be designed for it? A net-based system accommodates the situation: more is collected if technology progresses and costs are low, but less is collected if technology doesn't progress and costs are high. Thus Alberta is using a net-based system for its Cold Lake oil deposits, for instance, and Newfoundland and some nations are doing the same. 3:47:32 PM DR. VAN MEURS offered conclusions, pages 30-31 of his presentation. Alaska has progressed in its mature development of the North Slope, after 30 years of development. Old rules no longer apply. He urged thinking about how other nations deal with similar situations. The North Slope no longer lends itself to a gross-based system, even if there are significant tax credits, as he'd originally proposed. While it can be done, it isn't the best solution. Thus he'd recommended the PPT. He said while governments everywhere worry about the serious issue of cost control, he believes the issue is somewhat overblown in Alaska, perhaps because Alaskans aren't yet really familiar with net-based systems and feel the system will be gamed. Dr. van Meurs acknowledged things will slip through in a net-based system. He offered his experience in other countries, but conveyed his firm belief that horrible conditions elsewhere in the world don't apply in Alaska. He lauded the state for having honest individuals who do a splendid job. There already is auditing done, for example. He turned to page 33, posing a situation in which the whole industry puts in a fraudulent claims for 30 percent more costs than actually occurred. Highlighting what that would require, Dr. van Meurs said leases in Alaska are owned by different companies. Auditors would quickly discover if one company were charging double. To create 30 percent fraud, all the oil companies would have to get together and agree to produce thousands of fraudulent invoices, hoping the Department of Revenue wouldn't notice, and then they'd have to claim 30 percent more in costs. DR. VAN MEURS asked: What if they got away with it? At an average cost of $6.00 a barrel, he pointed out, 30 percent would be $1.80. They'd save 20 percent of that on cost deductions, or $0.36. On half they'd also save the 20 percent tax credit, another $0.18. Thus with massive fraud they'd save $0.54 a barrel, whereas a barrel is now worth $30.00 to $60.00. He questioned how serious a problem that would be; said that kind of fraud doesn't occur; and suggested if the occasional oil company slips something through, it will be caught by auditors. He opined that there won't be statewide, massive fraud among all the oil companies, which have to work together as working partners on their leases. 3:55:21 PM DR. VAN MEURS summarized, saying he believes the cost-control problem is overblown. To be absolutely sure, however, when the PPT law was designed he'd gone through the list of countries he termed "total basket cases" for which he'd had to design procedures, making a long list of nondeductible costs so that if there is even a minor audit they can be picked out. All these nondeductible costs are items where companies play games. Thus he'd gone to his basket-case list and applied that scenario to Alaska as if it were a basket case too - which it isn't. Dr. van Meurs noted page 34 showed the list. It read: Fiscal Structure PPT and Cost Control Nevertheless, Section 25 of the PPT bill provides for a long list of non-deductible costs, including: 1. Depreciation, depletion, amortization 2. Financing charges and cost of raising equity 3. Acquisition costs of leases 4. Cost for arbitration, litigation 5. Partnership JV, and other organizational costs 6. Any expenditures in excess of fair market value 7. Expenditures to purchase another company or business 8. Certain abandonment costs 9. Losses and damages of oil discharges. DR. VAN MEURS highlighted what is left: real costs for drilling wells and putting in a facility or gathering lines, as well as real operating costs. There is no overhead. Asserting all loopholes are closed, Dr. van Meurs opined that this PPT bill protects well against possible misuse of the net-revenue system. While there would be misuse, as human nature dictates, it wouldn't cause severe damage to Alaska. That is the experience of countries that have done this successfully for 30 years. He closed by saying he works in these other countries and is absolutely convinced this will work in Alaska as well. Dr. van Meurs expressed pleasure that the governor wanted to do more than tinker with the existing ELF system - building Alaska for the future and considering how the North Slope actually is today, using the international experience to get the maximum benefit for the state. 4:00:45 PM SENATOR HOLLIS FRENCH, Alaska State Legislature, asked how many oil-producing nations still collect on the gross. DR. VAN MEURS replied this is an important point. He'd done a survey of about 140 nations that are oil producers or potential producers. Of those, approximately 100 have some type of royalty like Alaska's. Since it is easy to collect, audit and verify, a gross-based royalty concept - taking up to 20 percent of gross in royalties - is immensely popular around the world. The vast majority do that. However, the concept of "gross on gross" is only in the U.S., as mentioned in earlier hearings. If a production tax on gross using some formula is added to a royalty, that combination doesn't exist in other nations. Thus the concept of a severance concept is uniquely American. SENATOR FRENCH asked whether nations with higher takes than Alaska take it all just with royalty. DR. VAN MEURS answered no; it is the opposite. With the exception of Venezuela, which recently increased royalties to 30 percent, as well as Texas state lands offshore, nobody charges a royalty higher than 20 percent of gross. The first cut is always modest. The range worldwide is 10 to 20 percent. Nations realize if too much is built on gross, it makes too many fields uneconomic. Thus many nations start with a royalty, as Alaska is doing - an excellent policy. A significant part of the income is based on gross. He highlighted the next step: Perhaps 120-126 of the 140 nations have corporate income tax; because Alaska is a state of the United States, it is difficult to get a large corporate income tax. Most nations put something in between royalties and corporate income tax, always a profit-based system. Dr. van Meurs explained that the economics of fields among the nations vary too much to make a simplified formula. While the foregoing encompasses the general rule, there are exceptions. Some countries have done away with royalties altogether, for example, including Norway and Great Britain, which use net completely. SENATOR FRENCH recalled that one example cited to those who advocate a net system is the leases at Kuparuk, which haven't shown a profit after decades in operation, although this is the second-largest oil field in North America. He asked why there is such trouble with those leases. DR. VAN MEURS suggested asking DNR, since he wasn't familiar with the details of each lease; in fact, those are confidential. He surmised one important factor is that oil prices only recently increased significantly; netbacks at the North Slope were very low until three years ago. If there is a profit feature after a royalty, for example, on a field-by-field system such as used for the net-profit-sharing leases, there could be a period of three to five years during which nothing is collected. 4:06:52 PM SENATOR FRENCH inquired about delayed maintenance on the North Slope. He recalled BP recently had a flow line that was choked with sand, developed a leak and will have to be replaced at a high cost; there may be many similar situations on the North Slope. He voiced concern about granting deductions for costs that accumulated over many years through neglect. This could add up to the 50 cents a barrel mentioned by Dr. van Meurs with respect to a 30 percent overrun or inflation factor - perhaps $400,000 a day for 800,000 barrels a day, or $100 million a year. He asked for Dr. van Meurs' thoughts about finding a way to not incentive such costs. DR. VAN MEURS responded that there are already two protections in the PPT bill proposal. First, losses and damages caused by oil discharges, such as occurred with BP, aren't deductible expenses. Second, an important provision is that if an asset is replaced - an old compressor, for example - the sale of the old one has to be credited against the cost. Thus the concept that certain assets would be renewed or replaced is taken care of to a degree in the bill. He added that in every oil field which becomes mature and older than 30 years, occasional equipment must be replaced. That's in the interest of the nation because it means oil production will continue safely and adequately. Dr. van Meurs said it could be an important deduction in an oil field over the coming 20-30 years. Internationally, those are considered legitimate capital costs, provided that if a replaced item can be sold or has a salvage value, that is deducted. SENATOR FRENCH questioned the value of an old flow line. He said he expects the work to be done when it is needed, rather than having it accumulate and suddenly generate a windfall with respect to taxes. DR. VAN MEURS replied that he wouldn't call it a windfall. Internationally, what Senator French mentioned are really maintenance capital expenditures. In making a forecast of the economics of an oil field, typically these are about 2 percent of the total capital expenditures spent in creating the field in the first place. If someone invested $1 billion, after 10-20 years there could be an expectation of $20 million a year in maintenance capital expenditures; that's true worldwide. Governments sometimes insist on better practices, and oil fields may have to be remodeled for environmental reasons. It could be 3 percent, or somewhat lower. 4:12:15 PM SENATOR BEN STEVENS suggested the inclusion of a gas regime would transform the North Slope from a mature stage into a developing stage for both gas and oil. DR. VAN MEURS agreed, noting what he means by "mature stage" relates to only the traditional state leases with respect to oil production. The Arctic National Wildlife Refuge (ANWR) would be a whole new ballgame, as would NPR-A to a large degree. The gas project, as explained by Roger Marks, will give North Slope oil production an entirely new lease on life, generating a whole new cycle of development, for these reasons: 1) operating costs can be shared in many fields between oil and gas, so suddenly the operating costs allocated to oil become less; 2) new gas fields will have 50 barrels a day of associated condensates, providing a whole new cycle of condensate production; and 3) in trying to find new resources to fill a gas line, it is likely that new oil fields, particularly in NPR-A, may be discovered. SENATOR BEN STEVENS commented that while some working reservoirs might be at a mature stage, in his mind the North Slope is still in the development stage, if not the discovery stage. He then asked for comments on a tax on gross for gas production internationally, and how that might be structured. He surmised the take would be high on the high side, but he recalled Dr. van Meurs had said Canada has higher taxes on the high side but no tax on the low side. DR. VAN MEURS reiterated that gas development creates a whole new cycle. The gas project, if the contract is approved, will be underpinned for the first 15 years by two large gas fields: Prudhoe Bay and Point Thomson, new fields from a gas perspective. In this particular case, since the economics of the fields are known, it was possible to identify the "7.25 percent of gross" in order to create a total package allowing the state to take approximately 20 percent of the gas in kind. He cautioned that 30 to 50 years in the future, however, if it's in a mature stage, there must be far more care with systems based on gross. There'll be the same situation as now for oil: all kinds of different small gas pools, and an Alberta-style situation wherein some pools are marginal or have low productivity. The type of stranded-gas contract submitted today wouldn't fit in such an environment; the system would need to be based more on net. For the current case, however, because the two gas fields are relatively economical, Dr. van Meurs said the state can afford to have the royalty plus "another slice on the gross" in order to create the total gas in kind. 4:19:48 PM SENATOR BEN STEVENS expressed appreciation for that distinction. He asked Dr. van Meurs whether his earlier testimony was that other regions have a tax on gross, but it varies so there is no tax when the price is low. DR. VAN MEURS affirmed that. Recalling his previous discussion before this committee, he said in principle there could be progressivity for gas as well as oil with respect to price. But while Canada has a progressive system on gas in the Mackenzie Valley, for example, it views progressivity as removing the government take if gas prices fall; that system is based on the rate of return. At very low prices, the maximum the government will collect is a 5 percent royalty - no severance tax, property taxes or additional state income tax. If prices are higher, it goes to a profit-sharing scenario. It's progressivity downward, not upward. He added that because there is so much stranded gas today around the world, economic rules are different for gas and oil. Progressivity for gas means less government take if prices are low, rather than more government take if prices are higher. There is too much competition around the world to get gas to market, which puts governments that like to market large blocks of gas in a weak bargaining position. DR. VAN MEURS closed by giving his opinion that what is currently in front of this legislature is the absolute optimal package. It has the maximum on oil, which is where the bargaining power is, since oil is running out and government takes on oil are rising. He also mentioned a sensible package on gas, saying the total results in maximum development. That is exactly what is on the table today. CHAIR SEEKINS thanked Dr. van Meurs and held SB 3001 and SB 3002 over.