ALASKA STATE LEGISLATURE  SENATE RESOURCES STANDING COMMITTEE  March 24, 2007 2:50 p.m.   MEMBERS PRESENT Senator Charlie Huggins, Chair Senator Lyda Green Senator Lesil McGuire Senator Bill Wielechowski Senator Thomas Wagoner MEMBERS ABSENT  Senator Bert Stedman, Vice Chair Senator Gary Stevens OTHER LEGISLATORS PRESENT  Representative Ralph Samuels Representative Vic Kohring COMMITTEE CALENDAR  SENATE BILL NO. 104 "An Act relating to the Alaska Gasline Inducement Act; establishing the Alaska Gasline Inducement Act matching contribution fund; providing for an Alaska Gasline Inducement Act coordinator; making conforming amendments; and providing for an effective date." HEARD AND HELD PREVIOUS COMMITTEE ACTION  BILL: SB 104 SHORT TITLE: NATURAL GAS PIPELINE PROJECT SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 03/05/07 (S) READ THE FIRST TIME - REFERRALS 03/05/07 (S) RES, JUD, FIN 03/14/07 (S) RES AT 3:30 PM BUTROVICH 205 03/14/07 (S) Heard & Held 03/14/07 (S) MINUTE(RES) 03/16/07 (S) RES AT 3:30 PM BUTROVICH 205 03/16/07 (S) Heard & Held 03/16/07 (S) MINUTE(RES) 03/19/07 (S) RES AT 3:30 PM BUTROVICH 205 03/19/07 (S) Heard & Held 03/19/07 (S) MINUTE(RES) 03/21/07 (S) RES AT 3:30 PM SENATE FINANCE 532 03/21/07 (S) Heard & Held 03/21/07 (S) MINUTE(RES) 03/21/07 (S) RES AT 5:30 PM SENATE FINANCE 532 03/21/07 (S) Heard & Held 03/21/07 (S) MINUTE(RES) 03/22/07 (S) RES AT 4:15 PM FAHRENKAMP 203 03/22/07 (S) Heard & Held 03/22/07 (S) MINUTE(RES) 03/23/07 (S) RES AT 1:30 PM BUTROVICH 205 03/23/07 (S) Presentation: Industry Representatives 03/24/07 (S) RES AT 1:00 PM SENATE FINANCE 532 03/24/07 (S) RES AT 3:00 PM SENATE FINANCE 532 WITNESS REGISTER WENDY KING, Director State Negotiations ConocoPhillips Alaska, Inc. Anchorage AK 99510 POSITION STATEMENT: Commented on SB 104. ACTION NARRATIVE CHAIR CHARLIE HUGGINS called the Senate Resources Standing Committee meeting to order at 2:50:17 PM. Present at the call to order were Senators Wagoner, McGuire, Green, Wielechowski and Huggins. Representatives Kohring and Samuels joined the committee. SB 104-NATURAL GAS PIPELINE PROJECT  CHAIR HUGGINS announced SB 104 to be up for consideration and that the committee would first receive comments from Wendy King. [The following is a verbatim transcript of Ms. King's comments] 2:51:04 PM WENDY KING, Director of State Negotiations, ConocoPhillips Alaska, Inc.: I work for ConocoPhillips in Anchorage and I have been working on the ANS gas development project for four and a half years. I'm pleased to be here today to testify on SB 104 or the proposed AGIA bill. And I'd highlight - I think there are some handouts or some presentation materials and rather than work off the screen, we're going to work off the handout. I'll try to do my best to try to follow you through, even though there's not slide numbers on here. I'll do my best to draw your attention to the different points in the slides. Before I discuss the bill and we'll turn to that first slide labeled "Investing in Alaska Today" I want to reintroduce to the committee ConocoPhillips and what our business in Alaska looks like. ConocoPhillips is the state's largest oil and gas producer. We have had 1,200 uninterrupted LNG shipments since 1969 from the Kenai LNG plant. We are the state's largest acreage holder on the ANS and we have drilled over 60 exploration wells since 1999. We have drilled 16 wells in NPRA where we're the operator. ConocoPhillips - I get to learn these little facts about my company all the time - but one of them was that ConocoPhillips' heritage company, Phillips, was the first oil company to establish an office in Alaska. Just to move on to some general comments, I wanted to emphasize that timing on this project is important. I would agree with the administration that the timing is an important issue. Our company is committed to developing the ANS gas resources and ConocoPhillips is willing to consider creative solutions. We are eager to find a framework by which both parts of the project, both the midstream and the resource parts of the project, can be advanced. And I want to step back for a second and define that. The midstream sides of the project - and I'm going to use that term quite a bit - for me it involves what we call the gas transmission lines, the gas treatment plant, the big pipe that would go to Alberta and then what the different alternatives might be from Alberta to markets in the Lower 48. So, all components of that I would call the midstream portions of the project. 2:53:07 PM Upstream are the resource portions of the project or the assets that would be asked to be making shipping commitments to the project - so assets like the working interest owners in Prudhoe Bay or NPRA or other exploration. So, it's more from the perspective of a resource owner - a working-interest owner. That's the terminology I'll use. 2:53:26 PM The next slide in your packet is what makes the Alaska project different. And what you've got here is a graph of the North American gas pipeline projects that have happened since 1997 that are greater than $100 million. And I think from a visual perspective, the first thing eyes always go to when we look at this graph is that the cost of the Alaska gas pipeline project is just off the scale. I mean this has got the $20 billion 2001 estimate on it. But you can see, here's the Rockies Express Project, a pipeline project that is in construction right now. Its estimated cost for a 1,300 mile pipeline is $4 billion. The Alliance project which was completed in December of 2000, is a 1.3 bcf/day pipeline cost around $3.6 billion and it's an 1,800 mile pipeline. Mac Delta, I'm sure most of you have read, the MacKenzie Delta project - the cost increases that are just incurred on the MacKenzie Delta project - I believe the public estimate that was just made on that is $14 billion including the upstream development - that's U.S. dollars and that's a 1.2 bcf/day project. So just a flag - you know the Alaska gas pipeline project being a 3,600 mile pipeline with a cost estimate greater than $20 billion is just not comparative of these. It's much bigger. The scale is significantly larger. And I would also highlight that comparing - you know, you can't just take and say it's a $30 billion project or a $20 billion project, whatever the number ends up being - and say that's 10 times $2 billion projects. 2:54:47 PM The scale is just different. You can't just multiply it out. The next point I would like to make was on... SENATOR WIELECHOWSKI: Since the cost is so much for this - how many miles did you say it was? MS. KING: It's 3,600 miles from Alaska's North Slope to Chicago, which would be one of the markets in the Lower 48. SENATOR WIELECHOWSKI: Since that is - 3,600 miles - doesn't it make sense to start maybe thinking a little bit more about building a simply 800-mile line down to Valdez and shipping it by LNG? MS. KING: Senator Wielechowski, through the Chair, actually that is a question that ConocoPhillips, being the current operator and have had an existing LNG operation in Alaska for decades, it's a question we consistently look at. And we still believe that the cost - you'd still have to build a 800-mile pipeline - you'd still have to have the gasification, tankers, move it to a market and get it to it - a disadvantaged market in the context of you can only access the coast and have to bring it in. We still believe the total costs are better going with a pipeline project through Canada to the Lower 48. So, we've looked at it; we continually look at it; we think we bring a unique perspective on that. We have proprietary technology on LNG and we still believe the cost is better to go with a pipeline project to markets in the Lower 48 through Canada. 2:56:46 PM The next slide, if you turn to - and this is - you know, predicting natural gas prices - it's a risky business. And this graph is actually to just highlight a quick critical point here. What you've got on here is the forward curve that was published on December 9, 2005. That's the black line on this graph. And what's underneath it is what the actual gas prices were over the course of that year. So for me, I find this quite a staggering graph in that it kind of grounds me that we can't even predict natural gas prices within a one-year timeframe. Can you imagine trying to do that for a 30 or 40 year timeframe? And that's one of the key risks that the resource owners bear in this project - is that the volatility and the uncertainty on natural gas prices. I'd also like to highlight that ConocoPhillips wants to work with the Alaska legislature and Governor Palin on a framework that will advance a project. We agree a public transparent process is needed and we also believe a balanced deal is needed to stand the test of time. The project is just too big to have a winner/loser mentality. We've got to find a balanced deal to go forward. We believe ConocoPhillips can bring a lot of value to this project. We have financial strength; we have Arctic experience; we have Alaska experience; we operate in Alaska. We have project management skills and we have mega-project skills and we have key learnings from other pipeline projects that we're involved in. We also believe we bring a unique perspective to this in that we are an existing producer, but we are also an explorer. We have a track record of trying to advance the Alaska gas pipeline project and we have spent millions of dollars trying to do that. My primary focus today is to convey that we want to work in a constructive way with you to move forward, but more work is needed. The first time ConocoPhillips saw the proposed bill was on March 2, which was the first day it was released to the public. We have had our teams reviewing the bill and are eager to find a framework that will allow development of ANS gas resources to advance. We need to be able to work through some critical issues with the Alaska legislature and Governor Palin. We are not locked into the old proposal, but we need to find a framework that addresses the critical resource issues that are needed to support long-term shipping commitments for this project. One aspect of the proposed bill that we have noted in particular is the distinction between the midstream and the resource terms. The risk/reward balance is very different between the regulated return portions of the project, particularly when they're backed by strong firm transportation agreements. Just to remind people, firm transportation agreements are those agreements where a shipper would be asked to pay a pipeline what is called a demand charge, day in/day out. And for a project of this magnitude, it could be 20 - 25 years that people are asked to sign that shipping commitment for. And I'd point out as well - you pay for that charge regardless if you ship gas or not. The split between the midstream and that resource we think will help to illustrate the differences on risk and reward within the project. That being said, the project will only be successful if both the midstream and the resource risks are addressed. 2:59:49 PM Based on our initial review of the bill, ConocoPhillips has four key question areas that we would like to discuss with you. We have some suggestions on some of these, but we still don't have solutions for all of these. The four key areas are first - exclusivity or what we would call creating roadblocks to alternative projects; the second one is the resource terms, themselves; the third one, we'll buck it, is called the midstream bid requirements; and the fourth one is the expansion terms. And I'll go into more detail now on these four areas. 3:00:23 PM Exclusivity or roadblocks to competing projects - I'd first like to flag a key question - Why would the state want to block alternative projects instead of letting the free market work most efficiently? And I want to draw your attention to section 440 in the bill. CHAIR HUGGINS: I'm sorry, Wendy, would you say which section again? MS. KING: Yes, Chairman Huggins, section 43.90.440. This particular section reads: Except as otherwise provided in this chapter, the state grants the licensee assurances that the licensee has exclusive enjoyment of the inducements provided under this chapter. CHAIR HUGGINS: Okay, hold on just a second. Okay - page 18, line 22 - we're now prepared. MS. KING: Sorry chairman Huggins. I was reading from line 22 and I'll read that again. Except as otherwise provided in this chapter, the state grants the licensee assurances that the licensee has exclusive inducements - 'Excuse me, I can't read today - Oh, jeez, it's been a long week - I apologize - starting over again.' Except as otherwise provided in this chapter, the state grants the licensee assurances that the licensee has exclusive enjoyment of the inducements provided under this chapter. If the state extends to another person preferential royalty, tax, or monetary treatment for the purpose of facilitating the construction of a competing natural gas pipeline project in the state, and if the licensee is in compliance with the requirements of the license and with the requirements of state and federal statutes and regulations relevant to the project, the licensee is entitled to payment from the state of an amount equal to three times the total of reasonable costs that the licensee has incurred in developing the licensee's project as of that date that the state first extended preferential treatment to another person. Then I'd like to draw your attention to sections 340 in the bill and I'll try to find the pages here for you. 3:02:43 PM Actually sections [43.90.]330 and 340, I'm particularly looking at what the inducements are on pages 16 and 17 in the bill. The midstream inducements include streamline coordination for the project. Why wouldn't the state offer the benefits of streamline coordination to any project? That is how the federal process is set up. The inducements and particularly in section 340(b), line 7, indicate that the inducements - you can not put burdens - and I recognize that is a word I am using, but you can read your own words there - on a permit by any state agency would only apply to the licensed project. Does that then mean that the state would be willing to put burdens on a competing or alternative project through the permitting process? The way the bill is currently conceived, it would from a practical perspective make it incredibly difficult to permit an alternative project with the state for potentially as long as ten years. It is not clear what that the state could ever provide streamline permitting to any other project without creating litigation exposure to the original licensee. The exclusive inducements also include the benefits of a state- funded training program for Alaskans. Why would the state be willing to train Alaskans for only one project - the licensed project? Shouldn't qualified Alaskans have the opportunity to be trained and work on any project that is being advanced by mixing streamline permitting, the office of the state coordinator - AGIA coordinator, training for Alaskans and creating obstacles to work with resource owners except with regard to the licensed project with exclusive inducements of AGIA, it becomes difficult to see... CHAIR HUGGINS: Wendy, could you please give us a page and which line you're on. MS. KING: Oh, I'm skipped ahead in the bill, but I'm back on 440 and I'm kind of closing in this section here. CHAIR HUGGINS: Yes, when you do that if you would just give us a page and line number, it would help us. MS. KING: I apologize, Chairman Huggins. Section 440 again - and I'm going to draw in here... SENATOR WAGONER: Page? MS. KING: Page 18, line 22 through 31 again. I'm back to the reference to the exclusive inducements and also the treble damages clause. The exclusive inducements - they include the benefits of streamline permitting - that's listed in the bill, the office of the AGIA coordinator - the state coordinator, training for Alaskans, and creating obstacles to work with resource owners except with regard to the licensed project. It becomes difficult to see how an alternative project could be advanced anytime over the next ten years unless the licensee agrees that the project is uneconomic or if there was an arbitrator's award saying that it was uneconomic, that that was not challenged by the licensee. 3:05:51 PM I want to emphasize, ConocoPhillips is a supporter of streamlined permitting. We worked very hard on the federal legislation that was passed with the Alaska Natural Gas Pipeline Act. If the state is going to pass similar provisions, we believe they should be available to any project that is being advanced. We request that these sections be amended to make it clear that other projects can advance. So that is particularly the focus in those sections of 440 on page 18 and I'll go back on pages 16 and 17 to the inducements associated with the Alaska Gas line Inducement Act coordinator. So that's our first area of... 3:06:31 PM SENATOR McGUIRE: Wendy, on that point. So you know the theory behind these inducements if you will and the exclusivity of them is to get the project going. To incentivize people who have been similarly situated over the last three decades, two decades, depending on how you argue it and yet nothing seems to be moving forward. So would your argument be that these incentives aren't needed? Or I guess what I'm trying to - and I don't disagree by the way. I'm very concerned about the treble damages associated with that section because I think that a lot of those inducements are things we'd like to offer to anybody that's willing to develop resource development projects in Alaska. But I guess my question is, do you think these inducements are needed in the exclusivity and if not, what is the alternative? MS. KING: I do believe there are value in these inducements. I believe that streamline permitting - I believe that the state helping with the training program - Labor is clearly going to be a challenge for these projects so I do believe that there are value in these inducements. My concern stems, again, the exclusive nature of the inducements. So I do believe - and I understand your concern of wanting to motivate a gas pipeline project going forward. And I believe ConocoPhillips' record since 2000 clearly demonstrates our commitment to try to move this project forward. We are doing what we can to do that, but we see that these inducements should be out there for any project and if the state takes the chance of tying up those inducements, which would be normal - Let's just say permitting a project is a normal sovereign power the state would have. If you give - grant those exclusively, we could see ourselves - if you've chosen the wrong winner for some reason - the state's chosen the wrong winner, being delayed for a decade with those inducements being tied up to that licensee. So that's where our concern stems. I do believe there's value in some of these inducements - particularly those around streamline permitting and those around getting Alaskans ready for the jobs. We would prefer to see those apply to any project that is being advanced. And let the market choose which project goes forward. 3:08:49 PM MS. KING: The next area that I wanted to talk about is the resource package. And once again I want to draw our attention to what do I mean when I say "the resource." The resource, once again, is getting the owners, the leaseholders, explorers, whoever else that might want to show up for an open season - those that would be asked to make the shipping commitments to the project. And the issues that they face, they're unique in being asked to make that shipping commitment. As we stated last month in Senate Resources, the resource risks have always posed the greatest obstacle to a gas pipeline. The predominant resource risk that we want to continue to focus on with the state is in obtaining clarity on the state taxes and royalties that are needed in order to secure long-term shipping commitments. Addressing these issues remains a critical component to make this pipeline a reality. ConocoPhillips appreciates the recognition of the importance of resource issues for a proposed gas line project. Sections 300 - 320 in the bill. CHAIR HUGGINS: Give us your page number and line. MS. KING: I'm looking them up right now. Page 14, Chairman Huggins, page 14 is the qualifications for resource inducement. 310 is the royalty inducements. CHAIR HUGGINS: Line 7 MS. KING: Actually, in moving all the way through pages 14 -16 is the whole package of resource inducements that are in the bill. Those sections, 300, 310 and 320 - so pages 14-16 - would not be in the bill if the administration had not recognized that changes were needed on the resource side. We also appreciate the administration identified that fiscal stability is a critical resource issue by proposing the ten year stability provision. 3:11:19 PM A troubling aspect of the resource inducement package is the tie to the exclusivity of the licensed project and the treble damages clause. So I'm going back again now to section 440 in the bill. Is the state not willing to provide term inducements to any potential project that is being advanced and to any party that underpins the pipeline construction with a firm transportation commitment? What if the chosen winner makes some promises that can't be delivered on? What happens if the licensed project stumbles? Is the state willing to give up their right to change tax terms and royalty terms, which is a contractual arrangement, outside of the licensed project without creating litigation exposure with the licensee? What if the state picks the licensee but we know that the licensee can not deliver on what they say? We will not have the right to get upstream stability and provisions for any other open season on a different project for up to ten years or expose the state once again to damages. We do not want to see the project tied up in exclusive arrangements or exposed to the larger damages in order to have a backup plan. More to the specific side of the resource provisions, we remain concerned that the provisions in the bill need more work. The present bill promises to make some changes in the royalty contracts, but rather than negotiate changes to the contract, the bill would require the resource owners to accept being subject to as yet unwritten regulations and the regulations are subject to change every two years. 3:12:19 PM The bill promises a degree of protection against potential changes to the gas production tax, which is a start. However, it does not identify the protected production tax rate, and the period of relative stability is insufficient for a project of this magnitude. In addition, there is no protection against increases in other taxes that may be aimed at circumventing the protection. To give an example of that: If you had gas production tax stability, state corporate income tax could be increased to offset what you…basically the terms that you had there. So that balance of looking at the entire tax structure is something we think is important. We need to develop a complete resource package, and it's going to require creativity, open dialogue, and consensus. We believe that developing a resource- inducement package is important. In fact, [it is] the most important aspect that will advance a project to a successful open season--but more work is needed. 3:13:31 PM The next area that I want to move to is midstream requirements. My first question is: Why would the state be so proscriptive in the midstream requirements? The current version of the bill has a long list of requirements that a party must demonstrate to the administration's satisfaction before their bid would be reviewed by the public and the legislature. Any bid that did not meet all of the bid requirements would be rejected out of hand, even if it brought the best all-around solutions to the challenges facing this project. For example, a bid that met every one of the requirements, but said, "I cannot meet three fixed-date requirements, because we felt that that might not be consistent with the best project management tools and skills that are out there," the bid would be rejected as a non-conforming bid. For approximately a year, ConocoPhillips has indicated that we have alternatives on different work commitments if the right resource framework was in place, but the proscriptive nature of the requirements would not even allow us to bring that creativity to the table; it would be rejected as non-conforming bid. Another example of this is what if a company decided they did not want the state capital contribution prior to the open season? For our project, we have estimated it could cost $400 to $500 million to get to the open season. The bid requirements would require us to take $200 to $250 million of state contributions to be a qualifying bid. Should we be required to take that money from the state as part of the bid? 3:15:08 PM SENATOR WAGONER: You keep saying 'our requirements'. You talking producers as a whole, or you talking just ConocoPhillips? MS. KING: First and foremost, I am always speaking on behalf of ConocoPhillips; I'm not speaking on behalf of a producer group or big oil. I am here representing ConocoPhillips. Now with respect to the second part of that-the midstream requirements I'm talking here are the ones that are actually laid out in the proposed AGIA bill. I'll probably get the number wrong, but there's a number of requirements that are in there that you need to meet to be considered a conforming bid. And that long list of requirements is the one that I'm speaking to now, Senator Wagoner. One of the few times that a pipeline really has risk in this project is prior to that open season. I guess there's a question in my mind, if you're not confident enough that you can have a successful open season, and you require an inducement from the state to get through those relatively small costs-we're talking $500 million out of a project that could be in the magnitude of $30 billion-you have to question what role you can play in the project. What about the objectives of the customers, the shippers? How do you balance the fact that many of these requirements flow through directly to the shippers? What stops a pipeline company from promising all of these terms, knowing that they can pass them on to the shippers and have the benefits of the exclusive inducements for over a decade? What happens with an empty promise? How does the state deal with someone saying they can deliver a particular size pipeline and then eight years later saying: I can't, I didn't get the firm shipping commitments, they were inadequate, financing wasn't available, or FERC wouldn't approve the project? The current bid process encourages bidders to bid high and then beg forgiveness rather than to bid realistically. We suggest changing the current list of bid requirements to bid variables that would be consistent with the administration's goal of fair and transparent process, but would allow companies like ConocoPhillips, who have a lot of experience in these types of deals, to use our creativity. We understand the state has some must-haves. Isn't it an easier way to say to the industry, we have these demands: Alaska-hire, options for gas for Alaskans, rock-solid work commitments, and others? Please bring us, industry, the most creative solutions you can to meet those demands. The final area that I wanted to move to is the mandating expansions and rolled in rates. 3:17:56 PM Why would the state want to mandate enhancements for late shippers that could threaten the viability of the basin-opening project and impair state revenues? ConocoPhillips is the state's largest explorer, and I draw your attention to this slide here. And I think we can bring a different perspective to this issue. From this slide you can see that ConocoPhillips has a strong land position. The color in orange is lands that we hold that are ConocoPhillips operated. The ones in yellow are ConocoPhillips non-operated. We drill a number of exploration wells in Alaska every year, and we continue to explore in a region that we know is gas-prone: the NPRA. ConocoPhillips is concerned that the initial shippers, who will be asked to sign up for billions and billions of dollars in firm shipping commitments that will make the pipeline project feasible, are being asked to take on more risk under the proposed bill than under existing statutes and regulations. Why would a party sign up as an initial shipper if I could wait, secure in the knowledge that an expansion could be mandated and its tariff mitigated through rolled in rate subsidies? At some point you have to ask: Are all these promises for explorers actually driving the behaviors you want? For over four years, I have heard companies saying they need more time prior to an open season so they can drill. We have been actively trying, since 2001, to advance a gas pipeline project and get the government frameworks in place. These issues-or explorer issues-have been debated with the federal legislation-the Alaska Natural Gas Pipeline Act-and have been debated in front of FERC with orders 2005 and 2005a. And both times a balance was struck, and there's still no drilling. Why should I drill now when the state continues to push to provide guaranteed subsidized rates for those that defer drilling? ConocoPhillips continues to spend millions of dollars every year to advance a gas pipeline. We believe the single largest variable that will motivate new exploration on the slope is a gas pipeline and a successful open season. With costs going up the way they are, we are letting a million dollar issue drive the billion dollar issues. Let's keep our eye on first things first. Let's compare the risks - the next graph here - that [an] initial shipper faces versus a later shipper. And I recognize this is a subjective, qualitative-type analysis, and we might have debates about whether there should be one and a half X's here or two X's here. It's more intended to be just an indication. 3:20:22 PM I'd flag initial shippers-just going down here through the list- the initial shippers are going to be asked to sign up for shipping commitments, potentially a decade before gas is delivered to the market and with huge levels of uncertainty in the resulting toll they may have to pay. The cost environment for those upstream developments that the resources are facing, and the expenditures that you could be facing, and trying to advance those upstream developments in parallel to the largest pipeline project in North America. Let me just highlight this issue again. We're going to be trying to get our assets ready on the upstream side-trying to get Prudhoe Bay ready for gas productions; trying to develop other fields, and for us that can involve things with NPRA in parallel to the largest private construction project in the world. Our upstream developments will be competing with the pipeline project for the very goods and services that we're going to need to have the gas ready, and that is a risk that an initial shipper is going to face in having your gas ready for the day the pipeline's ready. We do acknowledge that gas reserves and deliverability-that's a risk that any shipper faces, whether you're an early shipper or a late shipper. The increased state take over a period of FT is also there for initial shippers versus late shippers, but the initial shippers are going to be asked to sign up for shipping commitments that could last for decades. A late shipper may not have to sign up for that duration of a shipping commitment. 3:22:02 PM The increased tariffs from rolled in rates on expansions--that's something that the initial shippers will face, and to a degree, a later shipper might face to, and I'm going to give an example of that later on here. The project delays that usually account to more costs; usually projects being delayed, you're spending more money and it translates to more costs. So, yes, that is something a pipeline entity carries a risk while they're in the construction phase, but when the costs are finished, they will be able to pass them through, in its whole, to the initial shippers and to the late shippers. And then the pipeline also has a risk around obtaining those shipping commitments from credit-worthy parties. Once again, will the market support that this is the best project to do? I want to just flag: the risks are very great for the initial shippers, and we think we have to be careful that we don't set up an environment where you're in a place where everybody would say: I'd rather be a late shipper. We have to get the project out of the starting gate. The fact remains [that] the magnitude of these initial shipping commitments are huge, at a toll of $3.50 for a 20-year shipping commitment, that initial shipping commitment can be in excess of $26 billion for a 1 bcf/day commitment. Now multiply that number times 4 to get to a 4 bcf/day pipeline; it's about $100 billion worth of shipping commitments that will sit behind this project when it has an open season. That value is several times the value of many of the companies that might apply under this process. I ask myself, who has the financial strength to sit behind those types of numbers if natural gas prices plummet for a period of time, or if a field has deliverability problems? I also want to emphasize that I'm surprised that access is being raised as a question. I'm actually not aware that access has been a problem for anyone to date on the North Slope. Anadarko is our partner, and Alpine has access to facilities to produce their oil in NPRA. They have access to TAPS. We know their spare capacity in TAPS, and we have demonstrated a willingness to work facilities access with parties like Pioneer. 3:23:48 PM With respect to the Alaskan Natural Gas Pipeline, the US Congress already created an unprecedented provision with mandated expansion provisions to ensure access to this pipeline. She emphasized that there's no similar provision on any other pipeline in the Lower 48 than the mandated expansion that was passed in section 105 of the Alaska Natural Gas Pipeline Act. If a shipper is willing to sign up for firm shipping commitments, which translates to pay for the expansion, and can demonstrate that that expansion won't require others to subsidize it, the FERC can order an expansion of the Alaska Natural Gas Pipeline. In addition, there's absolutely no issue with a party making a firm shipping commitment on the gas pipeline project, even if you haven't found gas. You just need to be prepared to pay the toll. Isn't the real issue here not access, but the cost of that access? I understand why the state wants to create enhancements for exploration. 3:25:03 PM As an explorer I'm happy about that. We want to see new gas volumes, we want co-venturers to explore with Unalaska's North Slope, and I think I've communicated this before, but it's pretty risky drilling exploration wells at one hundred percent dollars; we like to have partners to explore and help spread our risks. We are the state's largest explorer and we can see both sides of the equation on many of these issues regarding expansions and rolled-in rates. ConocoPhillips does not oppose the application of rolled-in rates, for some expansions. 3:25:39 PM We do have some concerns with mandating that application, that application, for all potential expansions. We are not opposing the language in FERC order 2005 and in 2005 A, that grants the presumption of rolled-in rates. I'm going to read from that order 2005: 3:26:00 PM In conclusion, to provide guidance to potential shippers in advance of the initial open season that is subject of this rule, the commission intends to harmonize both objectives: rate predictability for the initial shippers, and reductions of barriers to future exploration and production in designing rates for future expansions of any Alaska natural gas transportation project. It is consistent with our guiding principle that competition favors all of the commission's customers as well as with the objectives of the act to adopt rolled-in treatment up to the point that would cause there to be a subsidy of expansion shippers by initial shippers if any subsidy were to be found. That's on page 44 and 18 CFR part 157 order number 2005, which was February 9, 2005. Let me illustrate a few concerns with the approach we have with mandating rolled-in rates for all expansions and mandating expansions that may be commercially unreasonable. Some of the exploration volumes could be from federal or private lands and some may even be from lands that the state can't tax. I'm drawing your attention to this graph here that was in your pack. This is here just to kind of illustrate - we tend to focus a lot of our attention right here, on this little circle in blue here, where the existing infrastructure is. But in reality, these exploration volumes we're talking about are likely going to be in the Chukchi [Sea], the Beaufort [Sea], NPRA, ANWR [Arctic National Wildlife Reserve], and the foothills, so we tend to focus in on a small area and the exploration volumes are going to be out in these different regions. If you skip then to the next slide that I've got in the pack, these are from public ally available sources from different - the United States Geological Survey assessments, and I've put the dates down as to when the different assessments were made, but I'd like to draw your attention to the three biggest numbers on here: the 83, the potential, the largest potential areas; 83 tcf in NPRA, 72 tcf in the Beaufort, 210 tcf in the Chukchi - and I've worked on these, these are technically I think recoverable-type numbers. But those three biggest numbers are in areas where the state has no royalty, or no, or some of these, not even production tax. Let me explain an example of where I think, from the state's perspective, you might question whether or not mandating rolled-in rates would work. Prudhoe Bay has a toll, for example, of four bucks. There's an expansion that comes along that says the toll would go up to four-sixty, a fifteen percent increase. The state would receive less royalty in production taxes, less permanent fund contributions from Prudhoe Bay by the fact that the toll was going up. Now many people have argued saying, there could be state-wide inducements or benefits from that other [indisc.] exploration coming in here. But what if that exploration volume is from a field in the Beaufort where the state has no royalty or no production taxes from it. So you would be in a place where you're receiving less royalty and less production taxes from Prudhoe Bay, but no new revenue coming in from that field, coming from the Beaufort. And I do acknowledge there's gonna be some socio-economic benefits of having developments going on in the Beaufort, but you will not be getting a revenue stream directly from those developments. Another example of mandated rolled-in rates which could be problematic is an NPRA example. 3:29:16 PM What if we are successful in NPRA after initial open season and we think we've got a good expansion; 800 million a day, cubic feet a day, kind of expansion? And I'm actually just grabbing numbers for illustrative purposes, I'm not actually calculating. The toll, once again, let's just say the toll was four bucks. If that toll, due to this 800 million-a-day expansion, through the application of rolled-in rates, was a good expansion, you might see the toll go down for everybody to $3.80. That explorer that was making the development decision to produce or develop that field said the toll is $3.80. It looks like I should go ahead with this development. Five years later, there's another expansion where the toll would go up to five bucks because it's an expansion from the Beaufort. You made your investment decision thinking that you had a $3.80 toll, and all of a sudden now you're facing a five dollar toll. That's the type of uncertainty that even as an explorer or a late-shipper, you might be exposed to by mandating rolled-in rates. Another example would be, for example, if there is some short- haul service to Fairbanks, and short-haul means that you just said I want to take capacity out on open season just to ship my gas from the North Slope to Fairbanks, and let's just assume that that toll was fifty cents. If there was an expansion, they could be exposed to the toll going up from fifty cents to fifty- seven point five cents and all of a sudden, consumers in Fairbanks are saying, why am I having to pay more to transport the gas when there's an expansion coming in from somewhere else that's not delivering any more volumes here? So there's both, on the customer end, as well as on the shipper end, scenarios where mandating rolled-in rates may not be in the best interest of all the parties involved. All we are suggesting is let the FERC be the adjudicator on this issue. 3:31:08 PM ConocoPhillips might very well be the company in there arguing for the application of rolled in rates, and the state might want to be on the opposite side, or vice versa. Our perspective is, we just don't know what the expansions might look like, what they might come from. FERC has rebuttable presumption of rolled-in rates that's not being challenged. What we'd say is just let the FERC adjudicate those issues and all of us have the flexibility then to argue our case for whether we think the subsidy's been made at that point in time in the future. I'd also highlight that there are many tools in the state's toolbox to deal with the issue of enhancing exploration and motivating expansions, including things like royalty reductions and tax credits. The state could put a capital contribution in on an expansion at some point in the future; there's many tools in the state's toolbox to incent that exploration. What is inappropriate, though, is to require the initial shippers, the ones who have already taken exploration risks to find the existing known resource, you'll be taking on the multi-billion dollar risk that will make this pipeline possible, to subsidize those that have not yet taken those risks. We can't let unknown gas prospects that could take a decade to explore, appraise, and develop, drive the timing and development of the approximately 35 tcf of known resources, and the largest private construction project in North America. I'll conclude my remarks today by summarizing what I think are the key issues. 3:32:28 PM ConocoPhillips is ready to solve issues with the Alaska Legislature and the governor. We want to actively work with you to achieve a framework that promotes the development of the ANS gas resources and addresses the legitimate interests of all parties. The key to advancing the gas pipeline is really to address the resource issues and providing adequate security to companies so that they can make the long-term shipping commitments, is the critical issue that will result in a project. We urge you to not lose sight of this fundamental issue. The project is so difficult that we have to be on the same team and we have to recognize that compromise, like in all major decisions in life, is necessary for all parties. We have to have focus on doing what it takes to get this project moving forward. We can't lose sight - the costs are going up on the project. The recent announcement on the MacKenzie Delta project - the costs increasing confirms this, and should make us all step back and pause for a second. We need to remember the real prize: the tens of billions of dollars in new tax and royalty revenues, the countless jobs, the new economy that will be created with a new gas exploration and development industry for decades to come. To achieve this prize the risk must be realistically addressed and risk and rewards must be balanced. We've had thirty years of an oil economy; we need to look forward to a new gas economy. We need to find a creative way to make it happen. No company will work harder than ConocoPhillips to make this project a reality. I'd be happy to try to answer any of your questions. [End of Ms. King's verbatim transcript] 3:34:03 PM SENATOR WAGONER asked for a copy of Ms. King's testimony. MS. KING responded that she didn't have a copy of her testimony, but she offered to have individual conversation with anyone on the committee on the points she made. 3:35:03 PM SENATOR WAGONER said while he realized that ConocoPhillips is the explorer, and the other two major aren't, "The two biggest supplies of gas have already been explored for and we already know where they're at." He had a problem with her statement about exploration risk because "there's not a lot risk in some cases." 3:37:43 PM MS. KING responded by illustrating a risk that she saw. She worked in the United Kingdom for a while in the Southern Gas Basin that had a known resource that was producing very well. One particularly cold winter, a very unexpected event happened in the reservoir and they were unable to produce gas from that field for an entire winter. She emphasized that those types of things happen. When someone takes on a huge shipping commitment risk from an asset the size of Prudhoe Bay, if something went wrong that is a huge risk. I would not just assume because the resource is found that we have all the answers and there's not going to be risk associated with production and deliverability - even from the known resource. The other point I can't articulate on other companies' exploration strategies, but what I do believe is that the federal government is going to be paying very close attention. The FERC will be paying very close attention to insure that access is provided to those that have all volumes in the state. And as an explorer - and I've had people say 'You're an explorer producer, but you want to take an ownership position in the pipe, so it's all money going from one to the other.' Well, I would argue or at least point out to people that when we say we want to align our ownership interest in the pipe with our shipping commitment, that's based on the initial volumes. If we have exploration volumes, we very well might not be aligned on those issues. And so, once again, we could find ourselves in a different situation as an explorer. We still believe the best alternative is to be able to lay out the facts at the time the expansion is being advanced - Was a party willing to sign up for shipping commitments? Is it going to result in a subsidy? And let the FERC see the facts at that time and be the adjudicator. And we know that if we're the ones that believe that a subsidy is happening, the FERC is starting with a rebuttable presumption of rolled-in rates. So, you've got a little bit of a hurdle to get over to show that there is a subsidy. But we believe that that is the best venue to be able to deal with the specific facts at that point in time. 3:38:54 PM And then I'd, once again, go back to the point of you as a state have many vehicles at that point in the future to enhance that exploration. If a discovery is made and it's struggling economically, there are many tools in your toolbox that you can use with specific facts, then, knowing where that field is coming from. Knowing what its impact will be on the pipeline project as a whole, you can weigh the balance of that say what inducement is appropriate at that point in time in the future - to get that exploration volume into the markets in the Lower 48. 3:39:43 PM CHAIR HUGGINS said he thought an important component was her ability to communicate directly to the people who designed AGIA. He asked if she had that opportunity. MS. KING replied that she met with the administration two times in January and had a couple of informal meetings after that, but she has not had a lot of formal dialogue to date. She hastened to add that she felt that Commissioner Irwin and Commissioner Galvin were anxious to talk. 3:41:03 PM CHAIR HUGGINS said he thought it important to communicate with the ones who wrote the bill. MS. KING agreed saying the issues are complex and it's critical to have the talks. 3:42:25 PM CHAIR HUGGINS asked her to say a few more words about the open season. MS. KING said: The critical milestone that I see for this project is that open season. That's when a pipeline entity comes forward and says, 'Here's the services that we think we can provide; here's the cost we think we can provide them at.' And at that point in time, each potential customer is going to go back - each potential shipper is going to go back - and say, 'With what I know now - and there's still some questions that need to be addressed as potential shippers - I'd flag as a working interest owner in Prudhoe Bay, we are still working with the Alaska Oil and Gas Conservation Commission to find out what is the appropriate off-take rate for gas out of Prudhoe Bay. I've had a lot of people ask questions about Prudhoe Bay - is a complex - it's an excellent field. But it's a complex field in that that gas has been working hard for decades to produce more and more oil out of that field. When you start taking that gas off, there will be impacts in the reservoir doing that. That's one issue that the working interest owners in Prudhoe Bay will need to work through with the AOGCC to be ready for that open season. That's just one of the many issues that will need to be ready for that open season. But when that open season happens, that's when the customers are going to have to say, 'Look, I've weighed the risks. This is what I think the market is going to be doing. These are what I think I can deliver from my assets. This is what I think the eventual costs will be on the project and how they'll get translated back to me.' And that will be a signal of - when a customer is willing to say 'I'm willing to sign up for a 20 - 25 year shipping commitment, that the markets are supporting, that this project is ready to go forward.' It still doesn't mean that the project is guaranteed, because there still could be opportunities where the costs increase dramatically after you get going, but it indicates the market is ready to try to move the project forward. And so it is a critical milestone. 3:44:31 PM REPRESENTATIVE SAMUELS said he was going to ask her two questions that he asked Mr. Massey as well. He asked regardless of who the licensee is, if the bill passed and ConocoPhillips wanted to come to an open season and ship 1 bcf/day and the partners chose not to, or just BP came or however it worked out, is that possible to do under the operating unit agreement or "do you all have to swim together?" MS. KING replied that question is actually a complex question that will have to be handled on a case by case basis depending on the circumstances at the time. She explained: We do have long-term agreements with out fellow working interest owners and we have to - like I mentioned there are some real complex issues here. There's the impacts on oil. If one party starts to take gas off, it's going to have an impact. And so - another one is impurities. We all have discussed that Prudhoe Bay has 12 percent co2. What happens if one party wants to start putting more co2 back into the ground? So, it's a complex question and I know there have been frustrations about can't you provide a clear answer on this. But I would highlight it is just going to have to be a case by case situation. We will have to assess what the other producer wants to do, what we need to do. We're going to have to assess what the governing agreements actually say and we're going to have to assess what the governing agreements actually say and we're going to have to assess whether or not the impact on the working interest owners and the arrangements - what would be necessary to accommodate what each parties' reasonable concerns are. So, it's not a clear answer and it would require a lot of review on a case by case basis. 3:46:24 PM REPRESENTATIVE SAMUELS said one of the frustrations the drafters of AGIA had with exclusivity is without it, no one would play because you [the producers] had the gas and an automatic leg up on everybody. He asked if she had any other thoughts on work commitments so that something actually happens to move the project forward "without having to pick the winner before the race starts." 3:48:09 PM MS. KING said that ConocoPhillips believes more can be done from its perspective on work commitments. However, hard dates make them nervous, not because they don't want to go forward with the project, but because this is the largest private construction project in the North America and "having a cost blow out on the other end because you were driven by a date." She emphasized the critical issue is to have the frameworks in place that address the resource issues. She added that's why she thought moving the midstream bid requirements to bid variables would allow ConocoPhillips the flexibility to go back and bring some sharp minds together to look for creative solutions. 3:49:35 PM SENATOR WIELECHOWSKI asked if the Prudhoe Bay operating agreement has a provision that says if one producer takes a certain amount of gas, then all the others have to also. MS. KING replied that she hadn't read the Prudhoe Bay operating agreement, but that does not mean such a provision does not exist. She flagged again that those issues are considered on a case by case basis. 3:50:56 PM SENATOR WAGONER asked if ConocoPhillips would participate in an open season if AGIA were modified. MS. KING answered that she wouldn't say what would happen at some point in the future, but emphasized that the four key areas she mentioned earlier need to be worked on to try to get a gas pipeline project moving forward under AGIA. That is their first priority right now. SENATOR WAGONER asked if the actual cost of the project will not be known until it is completed no matter who offers the first open season. MS. KING answered yes, but she added that ConocoPhillips has experts and they have learned that good front-end engineering design can save billions of dollars on the backside. That's an important aspect of skills that I think we as a company can bring to the table in the construction of one of the largest private construction projects in North America - is bringing those types of skills to say, 'We need to take this pause here because if we spend a little bit more money right now, if we spend $10 million right now studying this issue, it could save us billions of dollars later.' Those important aspects are something we think we can bring to the table as a participator in a pipeline project going forward. 3:53:24 PM SENATOR WAGONER asked the status of ConocoPhillips' facility sharing agreements with Pioneer. MS. KING replied she didn't know the answer, but she knew they were working on it. SENATOR WAGONER asked her to follow up on that. 3:54:23 PM REPRESENTATIVE SAMUELS recapped that Ms. King said it could cost ConocoPhillips $400 million to get to an open season, but the administration testified it would cost $50 million to $200 million. That would work out to $25 million to $100 million for the state's matching 50 percent. He asked why there is that much of a discrepancy in getting to an open season estimate and how fast ConocoPhillips could get to an open season "if you are queen for a day." MS. KING replied with a few points. First, that ConocoPhillips' estimate in 2001/2002 was that it would take approximately $400 million to $500 million to complete an open season in its success case timeline. In May, they indicated approximately 18 months before an open season would be started. FERC requires 90 days to approve the open season plans and 90 more days to hold it. The proposed AGIA does not have requirements before an open season and she thought that meant an open season could be held after spending just $10 million and then be in the state matching section after that. She elaborated: It has no clear threshold that one open season has to be like another open season and that different people might do different pieces of work prior to an open season. Our schedule was we wanted to have four seasons of environmental field data that we need to get. We wanted to be doing that in parallel to the commercial work of getting an open season. So, when the open season was completed, we would be ready to submit our applications to the FERC and to the NEB. So, we had some parallel activities. But it is not to say that all project sponsors would necessarily hold an open season at the same timeframe. So, that could be why you're seeing some of the discrepancy in the numbers. But I will reiterate, it was the $400 million to $500 million - was the work that we had done previously to complete an open season and roughly two years from when you start - on a success case schedule. 3:57:37 PM REPRESENTATIVE SAMUELS recapped that Ms. King had just said ConocoPhillips could do a cheaper open season, but if it had already spent the $400 million, how much more money would it spend to get the certificate. He wanted a total figure. MS. KING replied that ConocoPhillips' 2001 figures would be going up. It would take some strong engineering and regulatory work to do an updated cost estimate for this project. It cost $125 million the first time; it's not a simple undertaking to update it. In 2001 they thought it would take another $500 million to get a FERC certificate - about $1 billion total. Then the construction decision would be made and that's when you start to spend the $19 plus billion associated with the pre- construction and the construction phase. 3:58:59 PM REPRESENTATIVE SAMUELS asked if someone could do an open season for less than $50 million, would they just have less information for the shippers. Would you trust the tariff a little bit less or what? MS. KING replied that one wouldn't trust the estimate. That would be a key question if someone held an open season very soon. Other than the six-month FERC requirement, it's more how one thinks is the best way to manage the project. She didn't see anything in the bill that would foreclose someone holding an open season sooner than ConocoPhillips' timeframe. "It's just that we felt that was the best way to manage the project." 4:00:15 PM REPRESENTATIVE SAMUELS asked using a relatively large project - the Rocky Mountains Express as an example - did they spend half their money getting to open season and the other half to get the certificate. MS. KING replied that she didn't have those figures, but some of her colleagues pointed out to her that the breadth percentage they were thinking was consistent with some of the other major pipeline projects. She offered to follow up on that a little more. 4:00:55 PM CHAIR HUGGINS went to page 11, lines 14 - 25, on exclusivity. He recapped what someone said to him - that the state is now managing failure. The AGIA sets a timeline of five years and if gas was $7.50 that would cost the state about $12 billion to $13 billion. He asked her for ConocoPhillips' take on that provision. MS. KING replied: This section of [43.90] 210 (b) and (c) - my read on it is pretty clear. If you've had a successful open season, and you've got your FERC certificate and you've credit support, you have to commit - let me just flag in (a) first. You have to accept the FERC application, which FERC has the right to put conditions on a certificate. So, this would be requiring somebody to accept that FERC certificate in (a). (b) then says once you've accepted that FERC certificate, that you have one year to go forward to project sanction and if you don't have credit support, you still have the exclusive inducements in this chapter for another 5 years - or another 4 years - I guess - depending on whether you're counting the one year. You still have the exclusive inducements under this chapter all the way through that time even if you haven't had credit support. Now, one question that we are still evaluating is normally, I believe, and I apologize, I did not have time to listen to the FERC's testimony this week, but my understanding is that normally FERC would say you have 1 - 2 years after you receive a certificate by which you need to go forward with construction. And it's predominantly because the environmental data that you've based your environmental analysis on, your environmental impacts, will start to get stale - if you sit on a certificate for too long. So, I don't actually know how the FERC answered those questions if they were asked in the other hearing. But what I would flag is that it seems unusual to provide such an extended period of time after a FERC certificate if the market is in support of it. So, you've gone through a period where potentially you could have had 4 or 5 years just to get to the FERC certificate and then another 4 or 5 years on top of that and so that's where I came up to the estimate of 10 years that you could have the exclusive rights under section [43.90.]440. 4:04:52 PM CHAIR HUGGINS responded that's what he thought. He was concerned about the state's exposure to having to help a company that was going bankrupt - or whatever - and if it was going to continue for the next five years it would look to the state of Alaska specifically. He asked if she disagreed with that. MS. KING agreed that the state has some exposure to parties coming back to it questioning about how to go forward. "And you will have invested a substantial amount of time and money at that point and I understand the analysis of delays." CHAIR HUGGINS mentioned he commonly hears "We [the State of Alaska] would be leveraged to an extreme degree if we wanted to continue on with that licensee" and asked if she was familiar with it. MS. KING replied that she had heard the term "leveraged" a couple of times. CHAIR HUGGINS thanked her very much for her remarks and adjourned the meeting at 4:06:32 PM.