Legislature(2001 - 2002)
08/15/2001 09:08 AM NGP
* first hearing in first committee of referral
= bill was previously heard/scheduled
= bill was previously heard/scheduled
ALASKA STATE LEGISLATURE JOINT COMMITTEE ON NATURAL GAS PIPELINES Fairbanks, Alaska August 15, 2001 9:08 a.m. SENATE MEMBERS PRESENT Senator John Torgerson, Chair Senator Pete Kelly Senator Donny Olson, alternate SENATE MEMBERS ABSENT Senator Rick Halford Senator Johnny Ellis OTHER MEMBERS PRESENT Senator Gary Wilken HOUSE MEMBERS PRESENT Representative Joe Green, Vice Chair Representative Scott Ogan Representative John Davies Representative Hugh Fate, Alternate Representative Reggie Joule, Alternate HOUSE MEMBERS ABSENT Representative Mike Chenault, Alternate Representative Brian Porter COMMITTEE CALENDAR NATURAL GAS PIPELINE PRESENTATIONS Congressional Update Regulatory Agencies' Update Alaska Highway Natural Gas Policy Council Update Department of Revenue - discussion of tax issues Overview by the Alaska Natural Gas to Liquids Company Alaska Gasline Port Authority Update Presentations from Producer Groups Foothills Pipe Lines Ltd. Update Joint Natural Gas Pipelines meeting - discuss scheduling Additional Public Testimony by invitation of the Chair The Honorable Ted Stevens Public Testimony WITNESS REGISTER Mr. Mike Menge Staff to Senator Frank Murkowski United States Senate 322 Hart Building Washington D.C. 20510-0202 Mr. C. J. Zane Dyer, Ellis & Joseph Washington D.C. Mr. Duncan Smith Dyer, Ellis & Joseph Washington D.C. Mr. John Katz, Director State and Federal Relations and Special Counsel to the Governor 444 N Capitol NW, Suite 336 Washington D.C. 20001-1512 Mr. Bob Loeffler, Attorney Morrison and Forrester LLP 2000 Pennsylvania Ave., S.W. Washington D.C. 20006-1888 Ms. Nan Thompson, Chairperson Regulatory Commission of Alaska 1016 W 6th Ave. Anchorage AK 99501-1963 Mr. John Katz, Director Office of Energy Projects Federal Energy Regulatory Commission 888 First St., N.E. Washington D.C. 20426 Mr. Bill Britt, Pipeline Coordinator Department of Natural Resources 411 W 4th Ave. Anchorage AK 99501-2343 Mr. Mark Myers Division of Oil and Gas Department of Natural Resources 550 W 7th Ave., Ste 800 Anchorage AK 99501 Ms. Bonnie Robson, Petroleum Investment Manager Division of Oil and Gas Department of Natural Resources 550 W 7th Ave., Ste. 800 Anchorage AK 99501-3560 Mr. Wilson Condon, Commissioner Department of Revenue PO Box 110400 Juneau AK 99811-0400 Mr. Ed Small Cambridge Energy Research Associates, Inc. (CERA) Charles Square, 20 University Road Cambridge MA 02138 Mr. Richard Peterson, CEO Alaska Natural Gas to Liquids Co. 310 K Street Anchorage AK Mr. Dave Dengle, Executive Director Alaska Gasline Port Authority 406 Cushman Street Fairbanks AK 99701 Mr. Rigdon Boykin Special Counsel to the Port Authority O'Melveny & Myers, LLP 151 East 53rd Street New York NY Mr. Robbie Schilhab Exxon Mobil Representing Alaska Gas Producers Pipeline Team 550 West 5th Avenue, Suite 500 Anchorage AK 99501 Mr. Joseph Marushack Alaska Gas Producers Pipeline Team 550 West 5th Avenue, Suite 500 Anchorage AK 99501 Mr. John R. Ellwood, Vice President Engineering and Operations Foothills Pipe Lines Ltd. 3100-707 Eighth Ave., S.W. Calgary, Alberta, Canada T2P 3W8 Ms. Ronda Thompson, Special Assistant International Trade Office Alaska Legislature 716 W 4th Ave., Ste. 660 Anchorage AK 99801 Ms. Kara Moriarty, President and CEO The Greater Fairbanks Chamber of Commerce 250 Cushman St., Suite 2-D Fairbanks AK 99701 Mr. Gordie Lewis Golden Valley Electric Association PO Box 71249 Fairbanks AK 99707-1249 Mr. Paul Metz 3510 Rosie Creek Rd. Fairbanks AK The Honorable Ted Stevens United States Senate 522 Hart Building Washington D.C. Ms. Deb Moore Northern Alaska Environmental Center Fairbanks AK Mr. Ken Freeman, Member Alaska Highway Natural Gas Policy Council (AHNGPC) Office of the Governor 550 W. 7th Ave., Suite 1700 Anchorage AK 99501 ACTION NARRATIVE TAPE 01-12, SIDE A 9:08 a.m. CHAIRMAN JOHN TORGERSON called the Joint Committee on Natural Gas Pipelines meeting to order at 9:08 a.m. and announced that Mr. Mike Menge, staff for Senator Murkowski, would comment. CONGRESSIONAL UPDATE MR. MIKE MENGE, staff to Senator Frank Murkowski, said he came to Alaska in 1979 with the U.S. Geological Survey and spent the ensuing years working on various oil, gas and coal development projects across the state, including working on the TAPS line. During Governor Hickel's latest governorship, he came to Juneau and worked four years as Director of Environmental Quality within the Alaska Department of Environmental Conservation. So, he got a chance to look at resource issues from a permitting perspective, which controls a lot of Alaskan projects. Over time it has become the dominant issue. Alaska is awash in resources, but not necessarily awash in good will or the ability to permit the development of these resources. When Senator Murkowski assumed the chairmanship of the Natural Resources Committee in D.C., he was invited to serve as professional staff dealing with public land, energy issues and Alaskan issues. When he was authorized officer for the TransAlaska pipeline he and Jerry Brossia (then with the Alaska Department of Natural Resources) created the Joint Federal State Pipeline Monitoring Office, which was created primarily to issue the right-of-way permits necessary to proceed forward with the TAGS line and also to continue monitoring the TAPS line. So, he has followed the gas development in Alaska from "the lowest rung." MR. MENGE said he would give them a brief update on activities in Washington, D.C. where the Senate is engaged in the energy package. When the Senate finishes its package, both House and Senate versions will go to a conference committee. The committee will get into the meat of the energy package starting about September 12 and expects to have an energy bill before the full Senate by the end of September. With the transition of power in the Senate, it looks like issues will be debated well through October. Other than the appropriations, the energy bill will be the principle issue. He said further: Senator Murkowski has encouraged the advocates for gas development in Alaska to bring forth energy legislation, which would be considered during the energy package. About two or three weeks ago we received that submittal from the producers group. We have also asked the TransCanada Foothills group for legislation and to this point that has not been forthcoming. Senator Torgerson shared with me proposed legislation I had not seen before. So, now is the right time for the consideration of that legislation. We have submitted the producers' legislation to various federal agencies for their review and comment and have not received that back yet. The Senator will reserve his actions until after we have had a full hearing of this information. I believe we will be scheduling a hearing in mid-September to take a look at this information shortly after we get back. The Senator has made it very clear that he prefers the Alaska line, I think for all the reasons that Senator Torgerson has been working on and elaborating, as well. We have serious concerns over the 'permittability' of the over-the-top route. We also have concerns with the potential impacts of that line. However, Senator Murkowski has not closed out his options and is prepared to listen with an open mind to all of the various proposals before we draw our conclusions. Clearly the energy in the committee right now is focused primarily on ANWR opening, but not to the exclusion of potential pipeline legislation, as well. I think we'll be doing a full-court press in doing everything we can to advance the ANWR legislation and now would be the time when that requires almost all of our energy. That is pretty much all I have to report at this point. I'd be pleased to answer any questions…" CHAIRMAN TORGERSON added that he had shared Charlie Cole's proposed legislation with Mr. Menge this morning, not anything he had written personally. REPRESENTATIVE OGAN asked him to comment on what a radio station was saying about legislation Senator Murkowski had introduced on this issue. He thought there was only draft legislation. MR. MENGE replied: I have also encountered that rumor and I can assure you that it is absolutely not true. We have received the legislation offered by the producers' group. We have disseminated that to various federal organizations for their review and comment. Senator Murkowski has not taken a position on that legislation nor has he offered that legislation and will not until after we have an opportunity to look at it in significant detail and receive the input from a lot of other organizations and entities. Thank you for the opportunity to clarify that. CHAIRMAN TORGERSON asked if he was guessing September for the hearing Senator Murkowski had been able to schedule on that legislation with Mr. Bingaman. MR. MENGE said he was guessing and there had only been preliminary discussions. He didn't think there would be any opposition from Senator Bingaman to have a hearing. CHAIRMAN TORGERSON asked him to tell Senator Murkowski that he would like to have the opportunity to testify on any legislation that may come through on this proposal. MR. MENGE said he would carry that request to the Senator. REPRESENTATIVE DAVIES said that he thought the bill provides an advantage by expediting the process for the northern route and, "We would have serious concerns with that…" MR. MENGE said he would pass on that concern. CHAIRMAN TORGERSON announced that C.J. Zane and Duncan Smith, Dyer, Ellis and Joseph, were under contract through Legislative Council to monitor the progress on the energy bill in the House, the Senate, the conference committee and the Bush Administration. He said they actually signed the contract yesterday, but they had been on the job for over a month and had set up some very important meetings between him [Chairman Torgerson] and staffers in D.C. MR. C.J. ZANE, Dyer, Ellis & Joseph, said he was Chief of Staff for Congressman Don Young for many years and is familiar with Alaskan issues. He also lobbied for Native corporations, Alyeska Pipeline and Alaskan based interests for a number of years. He said that a partner in the law firm, Mr. Duncan Smith, worked as committee staff for Congressman Young at the same time. They feel they are in a good position to help the committee stay on top of developments with Congress and the Bush Administration. The administration can do a number of energy policy things on its own that may or may not have an effect on the Alaska natural gas project. There is a lot of interest in the energy issue. The bill that just passed the House didn't seem to have anything that was disproportionately skewed to adversely affect this project. That bears watching as this effort moves forward. Other than the tax grants and incentive packages for other types of energy, the only thing in the House bill of note is the language that bars the over-the-top route. I think that several democratic senators who traditionally vote with the environmental community are going to be very key in this debate in as much as several of the national environmental groups have said they would support natural gas delivered from Alaska, but they have made it pretty clear that does not include a system that would be in the Beaufort Sea... 9:27 a.m. MR. DUNCAN SMITH, Dyer, Ellis & Joseph, added that four bills were consolidated into one. Everyone was putting forth ideas and the bill needs to be watched through to the final package. REPRESENTATIVE DAVIES asked if he concurred with the characterization of the producers' bill that it provides at least equal footing, if not an advantage, to the over-the-top route. MR. ZANE answered that he read the transcript that Charlie Cole provided yesterday and could understand why John Katz and Mr. Loeffler believe the language provides for an over-the-top route, but he wasn't sure which proposal Representative Davies was looking at. The Walker Walker & Associates language [commissioned by Charlie Cole and the Port Authority) does not advantage the over- the-top route; it would advantage the existing Foothills and Yukon Pacific line. REPRESENTATIVE DAVIES asked him to expand on language regarding the over-the-top route in the House bill. MR. ZANE said he hadn't heard any concerns with the language from the Canadians. He has heard that people were wondering if similar language could be added to a Senate bill. MR. SMITH reiterated that there are a lot of moving parts to this bill and this is one of a whole range of issues. A lot of people are still presenting their ideas and they need to be watched as a final package is put together. He agreed with Mr. Zane that analyses that had been done to date had been pretty careful, but they all conclude that you have to see what the final words say. 9:35 a.m. CHAIRMAN TORGERSON said he thought the criticism Alaska is getting from Canada is on two fronts. One is from the Northwest Territories on banning the over-the-top route; they would like to see Prudhoe Bay and the Mackenzie Delta in one line. The other front that is getting more press is the opposition to opening ANWR from our Yukon friends and others throughout Canada. He thanked them for joining the committee. Canadian Political Reactions CHAIRMAN TORGERSON asked Mr. John Katz, Director, State and Federal Relations, and Special Counsel to the Governor in Washington, D.C. for an update on Canadian political reactions to the ban imposed by the Congress on the over-the-top route, Prime Minister Chretien's comments during the G-8 summit when he appeared to be favoring one route over the other and on the producers' legislation. REGULATORY AGENCIES MR. JOHN KATZ, Director, State and Federal Relations, and Special Counsel to the Governor in Washington, D.C. said that Bob Loeffler was with him and he would testify on other matters later in the hearing. MR. KATZ said: My testimony today is the product of discussions with U.S. and Canadian officials at both the federal and, in the case of Canada, territorial and provincial levels, discussions with the private sector and various interest groups. I would like to very briefly give my perception of the current situation with respect to four or five of the most important entities and interests in Canada and then respond to four or five commonly asked questions about what's going on in Canada in relationship to the United States. The first category would certainly be the Canadian federal government. I think all of you are familiar with the so called open mike remarks of the Prime Minister of Canada, Chretien, in which he was heard to say at the G-8 summit to President Bush, 'Well, can't we basically get on with building the over-the-top route.' We have since followed up on those remarks in Canada with our Canadian consultants and also through our means. The official position of the Canadian government as we understand it remains route and project neutrality. They would prefer in the ideal circumstance that the producers and pipeliners come to them with some unity on how they would like to proceed in commercializing natural gas in the U.S. and Canadian Arctic. There have been presentations at the cabinet level of the Canadian government. I think it is fair to say there is some individual ministers who would favor the over-the- top route or who would favor a Mackenzie Valley route controlled completely by Canada. There are others who would favor the southern, the Al-Can route. I think it is also the case that the Canadian cabinet has been briefed on this issue and is aware that in the case of the over- the-top route there would be a significant permitting process that would be required involving many different regulatory processes and permits. Whereas with respect to the southern route, thanks to ANGTA of 1976 and the ensuing U.S. and Canada decisions, the decision making process would be much less complicated. But for this moment in history, I think the official position will remain neutral while individual ministers certainly have their own personal predilections. A second major force in the Canadian political situation is the position of the various provincial premiers and territorial premiers. As all of you know, Premier Kakfwi of the Northwest Territories strongly favors an over-the- top route or a Mackenzie Valley route. He is opposed to the Al-Can or the southern route. In contrast, the premier of the Yukon Territory has expressed her support for the Al-Can route. British Columbia so far in its new administration has not been quite as active, but we expect that as Premier Campbell gets more acquainted with these issues, our expectation is that he will be a strong advocate for the southern route, as well. Premier Klein of Alberta has taken the position that he does not want to see a so-called 'bullet pipeline' through his province. That is, he wants to see some additional commercial value from natural gas production and transportation and he has speculated about the use of gas liquids or expanding the petrochemical industry in Alberta. The next group to mention is the producers and the pipeliners themselves. Our information is that thus far, the North Slope gas producers and their Canadian subsidiaries and affiliates have not been that active yet, in the Canadian decision-making process. I think at least two entities have been quite active. The first is Continental Oil, which has substantial holdings in the Mackenzie Valley. Some of you might have seen the recent comments of their CEO strongly advocating the development of the gas reserves in the Mackenzie Valley and not being particularly supportive at all of the southern route or the immediate commercialization of North Slope natural gas. His view is that there are sufficient reserves in the Mackenzie Valley and he would like to see them developed sooner rather than later. 10:41 a.m. All of you are familiar with Foothills and their activities. They have recently confirmed their position that all of this was settled between the United States and Canada in the late 1970's and that they have the exclusive franchise to develop North Slope natural gas by means of the southern route. The next set of interests, which I think are very important in Canada and in the U.S. also are Canada's aboriginal people. At the outset I should mention that as most of you know that the North Slope Eskimos in Alaska have expressed strong opposition to the over-the-top route. In Canada, there isn't the same population diversity along the coast. So I'm going to focus on first the clans and tribes of the Northwest Territory. We're advised that by and large the issue there is not aboriginal land claims themselves, but rather ownership and profit from the pipeline, itself. Most of the clans started with the position that they wanted 30 percent ownership interest in the pipeline. More recently, one clan has advocated 100 percent ownership in the pipeline and so that's thrown the situation into some state of fluidity and chaos. The ownership interests there have yet to be resolved. There's been some talk about asking for intervention, perhaps from the Canadian federal government. In the south, the situation is a little bit different. Aboriginal claims have not been fully resolved, but there's only one major tribe or clan to deal with in that circumstance. We've been advised that it is unlikely there that the absence of a full settlement at this point would be an obstacle to pipeline construction. The feeling is that either there will be a comprehensive aboriginal settlement or if not, that probably a deal could be negotiated with respect to pipeline, itself. Other groups have weighed in to the fray. Canada has a very active environmental movement as we do. They have expressed opposition to the over-the-top route, but we do not detect that there is concerted opposition, yet, or perhaps a conscious joining of Canadian environmental groups with Alaska groups and with national groups. However, I think it is fair to postulate that the environmental sector, probably in both Canada and the United States will oppose an over-the-top route. Moving on quickly now to some of the questions that are on people's minds about the Canadian situation. The first question is how did the Tauzin Young amendment [that would preclude construction of over-the-top route offshore] affect the situation. Certainly, there were articles in Canada of when this occurred and some editorial comment, as well, some to the effect that the United States ought not to be able to dictate what might be best for Canada. The reaction was similar to the reaction when our own legislature passed a relatively similar amendment. The second thing I want to comment on is the two-pipeline scenario. As many of you know, some of the Alaska political leadership has advocated a two-pipeline scenario believing that the construction of the southern route followed by the Mackenzie route represents a reasonable development scenario for both countries. In recent times in Canada we've seen some media comment and some of the political leadership saying, 'Yes, a two- pipeline scenario is fine, but let's build a Mackenzie Valley pipeline first to Alberta and then we can build the Al-Can Highway and commercialize Alaska North Slope gas after that. The feeling in that scenario is that the Mackenzie Valley route involves sufficient reserves in Canada and the ability of the Canadian governmental process to control the permitting and construction. So, it would be a reversal of what some Alaska interests argued earlier. A third issue is the linkage between ANWR and the gas line. As most of you know, the official position of the Canadian government is in opposition to ANWR and Canada has been active from time to time back here in Washington in expressing its opposition to ANWR. Some interests have suggested to the Canadian political leadership that they link the gas line and ANWR and indicate that they will only support the commercialization of Alaska North Slope gas if something to their liking can be worked out on ANWR. Fortunately, we do not detect that that idea has spread its roots. There has been a little bit of speculation about it, but to our knowledge very few people in the political leadership of Canada have been willing to create that linkage. They would much prefer to evaluate each project on its own merits. Finally, just a couple of comments on the U.S.-Canadian federal relationship, generally. There was an energy summit between President Bush and Prime Minister Chretien earlier on. They talked about the possibility of creating a North American Continental Energy Task Force that would include the United States, Canada and Mexico. There has not been significant follow through there at high political levels. We are aware that a bureaucratic task force of U.S. agency people has met with their counterparts in Canada, but that process has been going on for years. To our knowledge, there haven't been significant discussions either focused specifically on the White House level or Prime Minister Chretien's level in the aftermath of the summit they held. So, at this point, our understanding is neutrality on the part of Canadian federal government and on the part of the U.S. government, the best indication of where the President and Vice President stand is the very comprehensive energy report that was issued by the Administration some time ago where they directed the Secretary of Energy and the Secretary of State to remain very much involved in the pipeline issue and in the relationship between the U.S. and Canada. With that, Mr. Chairman, I think I'll stop for questions. CHAIRMAN TORGERSON said he wrote a letter to Mr. Katz, which laid out some questions, most of which had to do with FERC issues that Mr. Loeffler would testify on. He asked if the over-the-top legislation that Congressman Young had put in damaged our relationship with our Canadian counterparts. MR. KATZ answered: I would have to say from the perspective here, there's been no permanent damage. I think the Canadian leadership is calculating all that in their own equation with respect to the gas line, but we hear loud and clear when Canada has problems with fisheries, ANWR, etc. While we speculate and know that there is some heartburn with that, it hasn't reached the same crescendo at this point. Recognizing that you will be leading a delegation to Canada, as well, I think you will get a sense for that also. When the state administration was there some time ago, the Canadian leadership did talk about the position we have taken with respect to over-the-top, but they were willing to move on to discuss the pros and cons of the various projects generally. CHAIRMAN TORGERSON asked Mr. Katz to comment on the producers' legislation. At a meeting with the Governor's Conference in Juneau, Charlie Cole asked him questions. The committee received that transcript yesterday. He asked Mr. Katz why he thought the producers' legislation favors a particular route over another and whether it actually pulls provisions from the 1977 ANGTA and puts them into the Natural Gas Act. MR. KATZ replied: Thank you for giving me the opportunity to comment and I very much appreciated the comments that my friend and colleague, C.J. Zane, said a couple of minutes ago. I think we made three or four observations about the producers' legislation and I'll very briefly summarize them here. For one thing, I think the legislation puts a significant amount of control in the producers, themselves. The entities that control the natural gas under their amendments have tremendous authority through the regulatory process and in deciding generally what projects to pursue. That comes out of the definition of shipper in there and the fact that the producers control the gas. Under the formulation in the producers' legislation, the decision by FERC is made basically on so-called market placed grounds - that is, they don't have the authority under the legislation to adjudicate between competing applications. They look at each application in terms of three criteria. The first is rates and charges and the second is control of the gas and third is meetings, environmental and certain other standards. If they make positive determinations on those grounds, they must approve the application. The application will be filed for the most part by the entities that control the gas. Then quickly there are three other things I would say about it. The legislation in our judgment does not preempt ANGTA 1976. That remains existing law, but the producers' legislation would give the producers the option of proceeding under their expedited process and under the Natural Gas Act even with respect to the southern route. So, the question arises, does Foothills or the pipeline companies [END OF TAPE]. TAPE 01-12, SIDE B MR. KATZ continued: ...With respect to the southern route, how would ANGTA of 1976 relate to this expedited process whereby Congress under the producers' legislation would be creating another process, which in theory could be applied to the southern route, as well. Secondly, the producers' amendments would allow the application of the expedited process to any other application for a route and project including the over- the-top route. So, while they're proceeding under existing law, which would involve a very difficult regulatory process, the producers' amendments would allow for an expedited process, less rigorous than existing law would provide to some extent for a southern route. So, it doesn't prefer a southern route, but it treats the southern route for the purpose of the expedited process, the same as ANGTA did with respect to the '70s southern route. It does, of course, modernize some of the expedited processes. They are not precisely the same as the processes in ANGTA. They reflect the thinking in 2001 and then finally, we observed that there hasn't been the same environmental review, which preceded the expedited process for the southern route. So, you would applying the expedited process with respect to the northern route to a data base that has not been as fully developed as the one for ANGTA. So, I think in those different respects there are some similarities and some differences between ANGTA and the producers' proposed amendments. CHAIRMAN TORGERSON thanked him and said that Mr. Menge updated them on congressional actions that may happen and of a hearing in mid- September. He said the committee would have its regular meeting at the end of September in Kenai, but he hoped to have another meeting in Anchorage strictly on this legislation for that hearing. He asked if he or the Governor had responded directly to the producers about their legislation, yet. MR. KATZ responded: No sir. We are still in the process of analyzing the producers' amendments on their own in relationship to ANGTA and to the views of the political leadership in Alaska and the Natural Gas Council. The Governor has actually constituted a smaller group of us to complete that analysis in relatively short order and be prepared to advise him. That would all be the predicate to participate constructively in the process that Mike Menge described earlier. CHAIRMAN TORGERSON asked if he had a timeline for responding to the producers. MR. KATZ replied that they don't have a timeline yet for responding to the producers or to the Senate Energy Committee. They are aware of the timelines of the Committee and that they won't be altered for anyone, having imperatives from Senate leadership. "We are probably well embarked on our internal process, not finished yet, but we know the deadlines that are out there in terms of the situation back here and we must be in a position to meet those deadlines." CHAIRMAN TORGERSON asked if he had seen Mr. Cole's proposal [Walker Walker & Associates]. MR. KATZ said he hadn't had a chance to read it. CHAIRMAN TORGERSON said he wanted his comments on it. He said at the last meeting many heard him criticize the administration for not working very closely with this committee. He said they had made some "leaps and bounds" in trying to get along together, but Mr. Katz went overboard in Washington, D.C. "Of any issue we should be united on when we go before the Energy Committee, it's probably this proposed legislation...." MR. KATZ responded: On the basis of everything I know I think the policy objectives of the state administration and the governor with respect to these various routes and projects are quite similar and I pledge to you the same level of cooperation from here as we ferret through this together. Back in Washington, there are very few of us and a lot of them. CHAIRMAN TORGERSON said he wanted to continue with Mr. Katz and that the Federal Energy Regulatory Commission had responded in writing to the questions he sent them. 11:03 a.m. REPRESENTATIVE DAVIES said he was also wondering if he had seen the Walker Walker & Associates proposal and that he would be interested in his comments on those as well as the producers' amendments. He said he appreciated Mr. Katz's service to the State of Alaska over the years. MR. KATZ thanked him very much and said he would let Mr. Loeffler answer that question. Update on FERC Issues MR. BOB LOEFFLER, Morrison & Forrester, an Atlantic law firm, said he has represented the state's pipeline issues since about 1974. He cut his teeth on the first version of the Alaska gas pipeline. He had sent a nine-page letter to Senator Torgerson addressing the committee's questions. He asked if that was received. CHAIRMAN TORGERSON said that they received it and had it on the back table along with FERC's response to his questions. FERC's response is 50-pages, but 40-pages are the chairman's letter of January 18 in response to Mr. Bingaman's questions. FERC responded with a two-page letter to Senator Torgerson's questions. It basically says that, 'A number of the questions raise important policy matters that the Commission should only address at such time as it is presented with applications requesting particular approvals. Interested parties should also have the opportunity to provide the Commission with opposing points.' They're not answering any of the questions is the short story.... MR. LOEFFLER said he would try to summarize his positions stated in the letter: I'll make one comment on FERC. The staff report - and it is only a staff report - was issued in January on the last day of the last Democratic Chairman of the FERC. In Washington, we're now on our second Republican Chairman of FERC since January. Several commissioners have been replaced and we don't have guidance from the commissioners themselves - staff turns over, general counsel will turn over. So, while the January document is a very useful document in laying out the pros and cons of various positions, it is by no means the last word and, in many respects, as the recent letter notes, they haven't even reached conclusions. I hope I'm a little better, but with the caveat that a lot will depend on the exact shape of the application that comes before us. My first point, and I think it's good to bear this in mind, is that what FERC does and doesn't do for oil pipelines and gas pipelines are vastly different. In oil pipelines, FERC regulates only their tariffs and FERC does not give oil pipelines permission to go into business or permission to exit. In gas pipelines, the Congress gave the FERC comprehensive jurisdiction over interstate gas pipelines and that means that FERC has to approve a new pipeline, the facilities for a new pipeline, the environmental conditions that go with it, as well as the tariffs. Similarly, a gas pipeline does not go out of business without FERC permission. It's much more hands-on intense regulation than you find in the oil pipeline area. Number two, FERC has been doing gas pipelines since 1938. It is its daily business along with interstate electricity issues. They really have taken that oil pipeline regulation reluctantly. What that really means in practice is they have developed a lot more law on interstate gas pipelines, but of course, nearly all of it has been developed in the Lower 48 context. Number three, there is a special statute that everyone refers to, the '76 ANGTA statute, and that created a process that was designed to get a gas pipeline in service by 1983. It's important to remember that that statute is still on the books. Indeed, although there were recommendations towards the end of the 1980s to repeal it, Congress chose to repeal only two minor aspects of it, which reinforces the argument that it is still extant law, in some respect. The state has some special rights under that statute that it should make sure are preserved in any new legislation and we're quite attuned to that issue. Let's talk for a minute about the very important issue of access instate to royalty gas, laterals instate, who regulates the main interstate gas pipeline and who would regulate laterals. I will start with the case before us, which is the interstate gas pipeline, not an LNG project. I will talk a little about LNG later - but an interstate gas pipeline, which we believe should go along the southern route. Number one, the rights to charge for interstate service, I think everyone believes will be set by the FERC. I think at that point, it's important to note that based on what happened in the 1970s and the division of jurisdiction between Canada and the U.S. federal government, there will be pipeline tariffs set by segments. So, that there will be a pipeline tariff for the Alaska segment, one for the Canadian segments and one for Lower 48 segments. I know there is concern that instate transportation could be burdened with costs downstream out of Alaska. Under this division of tariffs, that should not happen. Even inside Alaska, the last go- round, we litigated for a result that would have Alaska traffic pay only for the miles and volumes used as a fraction of the total miles and volumes used in Alaska and I think there's a very, very strong case that that is the only fair result and meets the committee's concern about Alaska gas traffic instate carrying only a reasonable charge for its usage of the pipeline. Number two, the Alaska Natural Transportation Act in Section 13(B) gives the state the right to ship gas on an interstate ANGTA project and to take the gas off within Alaska, provided the royalty contract has that provision and the FERC is ordered to issue all the authorizations necessary to bring about that shipment and withdrawal and its jurisdiction is limited to reviewing the fairness of the rates charged for that shipment. Now that is a feature of Section 13(B), not a feature of the Natural Gas Act and I think it important for all our concerns that those rights be preserved forever with respect to an Alaska gas project. There's a question, of course, in how the FERC would look at a lateral serving Fairbanks or serving other instate needs. Generally the FERC asked the question, on a lateral, whether it is part of the integrated system - that owns it, [is] it regulated by a state commission and issues like that. Certainly if the lateral were owned by a separate company from the main pipeline, I think there would be a very strong case that the FERC would disclaim jurisdiction and leave it to the Regulatory Commission of Alaska. Even if you get to the other test, which is integration with the main system, I think there's a very strong case also that a lateral serving Fairbanks, for example, is not part of the integrated interstate system but they do apply factual tests there and it's not absolutely clear. In terms of the question of who would decide where a tap would be on the interstate system for a lateral, I believe that would be the FERC but I would point out that Section 13, to my way of thinking, would require them to establish a lateral or the tap for a lateral for royalty gas and I would expect that the FERC, recognizing the need, would be sensitive to creating laterals or lateral taps inside Alaska. There is some very, very old law that allows taps to be placed on interstate gas pipelines for the benefit of landowners through whose land the pipeline passes and the idea was farmers who would grant rights-of-way and they could have gas for their farming operations. I haven't seen that law cited for about 25 years but it's another basis for recognizing the equity of allowing instate use. That is the - quickly - the picture. I know that the chair of the RCA is going to testify about the jurisdiction of her agency and how they would set tariffs. I would point out one aspect of pricing. In the first go around in the 1970s, the U.S. government regulated the wellhead price of natural gas. That jurisdiction was withdrawn from the Congress. Back then a lot of people felt that it acted to restrain Alaska and others from receiving fair value for North Slope gas but that jurisdiction has been withdrawn. The federal government does not regulate the wellhead price of natural gas. On the other hand, it's common for state commissions, including the RCA, to regulate the price for at least distribution of natural gas and the RCA may have some jurisdiction over instate prices of natural gas. I'm sure the chair will address that. Now, there are questions about could the sponsors of a project block taps for instate use laterals and the like. Well, the short answer is you have to look at both the Natural Gas Act and ANGTA because, as I mentioned, the state has some pretty powerful rights under ANGTA but, in any event, the FERC, unless its jurisdiction is modified by Congress, has the power to require taps for instate use even if the owners of a project would oppose it. Of course it would look at why they're opposing it but they would not control the game unless the jurisdiction of a commission is modified. On an LNG project, or an all-Alaska project, we look to sort of a different point for federal jurisdiction and a different kind of federal jurisdiction. I reviewed the Yukon Pacific applications to the federal government in the 1980s and later for authorization to export and at that time the projects were very clearly premised on exports outside the U.S. not coming back into the U.S. and that gives the federal government a somewhat different kind of jurisdiction under Section 3 of the Natural Gas Act. And, what that means in practice is that the Department of Energy authorizes the export on certain terms and conditions and the FERC deals with the export facilities, which [indisc.] the facilities at the point of export, say Valdez, and on everything behind it all the way to the Slope and so, in a sense, the pipeline part of the purely export LNG facility is not regulated in any comparable sense to an over-the-land route by the federal government and any of its agencies. If, however, the LNG comes back into the United States, then you have the more traditional type of regulation. And now, a footnote on that - two footnotes. One footnote is Congress, in 1992, passed a provision which no one understands involving LNG exports and imports which limits, perhaps, the jurisdiction of the federal government. It tells the federal government to just issue the authorizations for import and export projects. [Indisc.] this month, sponsors of a project in the southern United States filed an application with the FERC telling them why don't you disclaim all jurisdiction over facilities at the point of import or export and it's not been ruled on by the FERC but they cite this 1992 statute. Number two - footnote number two - if the gas went out of Alaska and came back in California, we would have a rerun of the old El Paso LNG project and then we'd be dealing with Section 3 and Section 7 - our standard FERC jurisdiction. If, however, the LNG project went from Alaska to Mexico and then perhaps went to different ownership in Mexico and then came into the U.S., it's not clear what would happen there. At least the U.S. government would have authority under Section 3, subject to this new statute passed in '92, and I can't find a precedent for that. I'll think more about it but I think I know the LNG cases. I couldn't find a close precedent for that. Common carrier status - oil pipeline TAPS is a common carrier. Gas pipelines are not common carriers. The FERC, in the late 1980s, went to open access principles, which are intended to prevent the owners of a pipeline from favoring affiliated merchant enterprises, which sell gas that will be shipped on the line. They don't want interstate gas pipelines tying up capacity to favor the other half - their production affiliates. There's a lot of law in that, one spin out of this general open access concept is that the FERC expects new gas projects to have an open season in which they entertain applications for shippers to sign up for a period of time and they use those sign ups to help sell the project to the financial community and also it shows the need for the project. But there is no common carrier status of gas pipelines, which does raise fairly the issue of owners of the pipeline entering into arrangements, which could tie up access to the pipeline for a long time. Now the open season idea, which is more a policy than a requirement. If you search through the requirements for new pipelines, you cannot find today a requirement for open season but the FERC has said in specific cases that they expect open seasons for new facilities. But, anyway, the policy is intended to deal with issues about tying up capacity to the detriment of future shippers or competitors. We did a quick run last night and we found 700 different rulings on this from the FERC, so it is not a simple area. Any project the size of the Alaska gas pipeline is going to get Department of Justice and FERC scrutiny. Nevertheless, I think there are valid concerns about how the open season will operate. Because I'm running fast on my time, let me take that up very quickly. If the sponsors of the project are not yet a natural gas company, the FERC does not yet have jurisdiction so you could conceive of a situation where sponsors of a project under a new corporate name would have an open season and they would set the rules as they wish and then the capacity would be tied up. If they were already jurisdictional by the FERC, people would complain immediately about unfair provisions. In the situation where they're not yet jurisdictional by the FERC, anyone would know that these issues are going to come back before the FERC at a later date and they ought to act to comply with a fair and nondiscriminatory provision of FERC rulings in their open season but there might be a remedy at the instant, as opposed to later, on that. That's an issue deserving of close scrutiny. On the other hand, if their future shippers will want capacity reserved for them or want to make sure the FERC will be attuned to them, I think in the regulatory process there's precedent at the FERC that capacity not be tied up for future shippers and that it be fairly priced for future shippers. Let me address for a minute the upstream access questions beyond the open season issues and there are a couple of points worth making. Now when Congress, and I believe it was President Reagan, signed in - but when Congress passed waivers of law submitted by the President, the conditioning plant was included within the pipeline system under ANGTA. A couple points there. Number one, conditioning plants would not normally be included. Now there's a benefit to their inclusion, which is you get the expedited permitting and judicial review and there was a benefit then that doesn't exist anymore - a second benefit, which was for pricing purposes when the federal government then priced natural gas, you could get an add- on for the conditioning costs. Of course, that's gone by the wayside. It is not clear what the right result should be for a new gas pipeline. There may be more than one conditioning plant, for example. There may be issues under the state lease and even an RCA jurisdiction over conditioning plants and, insofar as I know, the administration does not have a position yet on whether the conditioning plant should stay as part of the main transportation system or should - the pipeline should start at the exit of the conditioning plant. Some of the issues that are identified in your letter about access to, for example, the conditioning plant by new users in the future, remind me of a number of issues that the state and the commissioner of natural resources is, in particular, trying to address in the context of the BP/ARCO merger where there were issues about access to field facilities and there were some provisions, I recall, dealing with that. Having raced through everything I think I will stop for a minute. I think I'm right on the dime, in terms of time, and ask if there are any questions. CHAIRMAN TORGERSON asked Mr. Loeffler if he covered the question of whether the NGA or ANGTA prevails. MR. LOEFFLER said he did not, but he covered it a little bit in writing. He stated the answer is that no one knows. They are both on the books and the only way that question can be definitively resolved is through legislation or ultimately, a Supreme Court ruling. He noted that he commented, in his memo, that while the ANGTA statute is on the books, at the time it was passed, no one thought it would be dealt with more than 20 years later. He pointed out, with both the presidential decision and the treaty, that the Northwest Project was expected to be in service in 1983. It is operative because it is on the books. He suggested the best one could do to answer that question is to look at the January 18 FERC staff report, which weighs out the pros and cons. CHAIRMAN TORGERSON stated that he believes it was the 1982 amendment that allowed the producers to have part ownership in a pipeline, but they had to prove that their participation did not violate anti-trust laws. He asked Mr. Loeffler to comment on that. MR. LOEFFLER said he has several comments and provided the following history. When the president's decision was in draft form, the then commissioner of the Alaska Department of Revenue objected to the banning of the producers on various grounds but, essentially, on economic grounds. At that time, it was thought the producers' financial support, more than debt guarantees, was necessary to build the project. Sure enough, three or four years later, when the financial needs for the project were so great, they came around to that and the waiver of law was passed. He recalled the waiver of law said the Department of Justice had to rule that the producer participation would not establish a condition inconsistent with the anti-trust laws. That was a standard used by the Nuclear Energy Regulatory Commission and never fleshed out. At that time, they were looking for 30 percent producer participation in the equity of the project and in debt guarantees. The gas pipelines were financially weak compared to the producers. The concern of the producers at the time was that their 30 percent, plus cost overruns, could become a higher percentage. Mr. Loeffler said he thinks there are valid concerns about ensuring that a project is built, which will require the backing of people with the financial wherewithal. Mr. Loeffler said he also believes the state has a counter concern that those who own the pipeline do not lock it up against independent producers and future shippers. He expects the state, FERC and Department of Justice to take a very close look at the open access requirements. CHAIRMAN TORGERSON asked who would make the anti-trust decision. MR. LOEFFLER replied it is a double standard. The FERC looks at anti-trust issues but does not apply the anti-trust laws so anti- trust concerns are one of the elements of the public interest determination that the FERC makes. Separate from that, the Department of Justice will look at that question and has its own ways of enforcement. CHAIRMAN TORGERSON referred to page 26 of the transcript of the meeting in Juneau [August 2, Alaska Highway Natural Gas Policy Council], and asked if the committee could get copies of Phillips' proposed amendments to the federal fiscal regime. MR. KATZ said he would prefer that Phillips explain its own proposal but said it is fair to say that Phillips' current thinking is divided into two parts: one is accelerated depreciation for construction costs. Accelerated depreciation is an issue that has been framed in some of the pending national energy bills in Washington, D.C. so he believes that will be discussed as a generic nationwide issue. Second, Phillips has requested a provision that deals with a floor on price and remedies that might apply if the price of natural gas goes below a certain level. He pointed out, in the context of the pending federal legislation, there had been proposals to deal with a production tax credit. One proposal introduced by some democratic members would tie it specifically to the southern route. Phillips' proposal is route-neutral. He offered to contact Phillips in Washington, D.C., relay the Chairman's request, and allow Phillips to establish a direct relationship with the committee. CHAIRMAN TORGERSON thanked Mr. Katz and noted a representative from Phillips would be presenting to the committee that afternoon. MR. KATZ informed the committee that the [U.S.] Senate Energy Committee has jurisdiction over all of the issues he discussed except the tax regime, which is under the purview of the Finance Committee. That will undergo a separate process and it is not yet clear how that will relate to the federal energy legislation under consideration by the Senate Energy Committee. He added that of the many tax proposals floating around, some do involve the development of transportation of natural gas so he expects those issues to get a fair hearing as well. CHAIRMAN TORGERSON noted that he plans to request of the producers, Foothills, the administration and of the committee's legal advisors that each provide sectional analyses of that section. That information will be distributed to committee members in advance of the next meeting so that the subject can be discussed then. TAPE 01-13, SIDE A REPRESENTATIVE DAVIES stated that at the committee's last meeting he was pretty dissatisfied with the responses of FERC officials relative to the open season question. It seemed they were willing to accept a market-driven imperative for open seasons that would happen later than the initial open season. He noted Mr. Loeffler indicated that open season decisions, with respect to FERC, were set more by policy than law and that FERC has made over 700 rulings. He asked if the rulings were about open seasons at the initiation of a pipeline or on point for continued access. He also asked whether Alaska should consider codifying some of the open season principles in the upcoming law. MR. LOEFFLER stated that there are rulings for new pipelines, for expansion of existing pipelines, and rulings in the life of a pipeline as capacity becomes available for the first time regarding how capacity should be allocated between users and new users. So, essentially, there are definitely rulings that deal with "later on" in the life of a pipeline. He said the question of whether Alaska needs a particular expression of non-discriminatory access or fair access for all shippers is an active "hotplate" of consideration, including the question of whether that expression should be placed in legislation. REPRESENTATIVE DAVIES said that he is interested in being kept abreast of that discussion because his impression is that the FERC players are not very concerned about that. MR. LOEFFLER said that as is often the case in Washington, D.C., they may need a little education and to be sensitized to the particular concerns on an Alaska gas pipeline, which is part of his job. CHAIRMAN TORGERSON commented that a lot of the open season questions came from some of the smaller producers that are active in Alaska. He hopes they will have an opportunity to review Mr. Loeffler's or Mr. Chenoweth's legal opinions and make recommendations for congressional action prior to the next committee meeting. REPRESENTATIVE FATE remarked that he noticed the producers, in their proposed bill, say in Section 3 that they would establish a federal pipeline director position. He asked Mr. Loeffler if he sees any problem with that relative to the state regulatory business. MR. KATZ said he does not know yet. He explained that everyone sees the need to coordinate the activities of the various federal agencies and ANGTA of 1976 provided for a federal pipeline inspector and a very large staff that was designed to provide coordination and communication among agencies. That administrative authority now resides in the Secretary of Energy, himself, because the office of the pipeline inspector no longer exists. He indicated there are three possible alternatives now on the table. One is to do what the producers suggest, which is to create a position in the White House subject to Senate confirmation. The second is to revitalize in some form the office of the pipeline inspector. The third would be an alternative implemented by administrative action. He informed the committee that currently, a bureaucratic task force of federal officials meets periodically to discuss pipeline issues but that task force has not moved very far. He said he believes that everyone who is familiar with the federal process feels the need for coordination in order to accelerate pipeline consideration. Exactly what form that will take is still unclear. REPRESENTATIVE FATE said it sounds like this position would be more permanent and would be applicable to other pipelines. MR. KATZ replied: It certainly could be. I think that the producers probably intended that it apply specifically to the commercialization of North Slope natural gas but there are some general provisions in some of the pending national energy bills that refer to a need to coordinate generically and nationwide with respect to these kinds of projects. One bill, for example, provides for a formal memorandum of understanding process so it might well be that as the Congress looks at this, if they decide that it's a good idea in one circumstance, they might seek to apply it more generically. REPRESENTATIVE OGAN noted that at the last hearing, FERC officials said they regulate from the wellhead on down if gas is shipped to the Lower 48. He asked Mr. Loeffler if a statutory scheme could be designed where the wellhead is moved farther down the line statutorily, to delineate state and FERC regulation at that point. MR. LOEFFLER explained that the Natural Gas Act was adopted following a Supreme Court ruling that suggested that production and gathering were inherent subjects for state regulation and that interstate commerce, in a sense, began with the transportation of natural gas out-of-state. Regarding whether FERC jurisdiction has been carved back voluntarily or otherwise, to appoint further into the process, the closest analogy one can come to is the Gulf of Mexico regarding the distinction between production and gathering and transportation. Second, Congress only has the power to define where federal jurisdiction begins. He can see some constitutional problems regarding figuring out what is interstate commerce and what is not. Congress could move the FERC jurisdiction point farther south but he doesn't know whether that will solve all of the problems that the smaller and independent producers see because of the question about access to the conditioning plant, before the gas gets to the pipeline. He said it may not be subject to regulation by anyone and moving the point of jurisdiction south really doesn't address the first issue. He noted that is one issue in his opinion that he said he will have to think more about. REPRESENTATIVE OGAN asked Mr. Loeffler for the name of the Supreme Court case. MR. LOEFFLER agreed to provide it to the committee at a later date. There being no more questions, CHAIRMAN TORGERSON thanked both Mr. Katz and Mr. Loeffler. The committee then took a short recess. 11:06 a.m. Update from Regulatory Agencies CHAIRMAN TORGERSON called the committee back to order. He informed participants that he submitted the same list of questions to Mr. Loeffler, FERC, and others and copies of their responses were available at the back of the room. He asked Ms. Nan Thompson, to address the committee. MR. NAN THOMPSON, Chairwoman of the Regulatory Commission of Alaska, informed committee members that the purpose of her testimony is to answer questions posed to her in a letter from the committee dated July 23. She offered to later submit those answers in writing. MS. THOMPSON noted the committee's letter expressed frustration about the answers it received during the last hearing. She pointed out that the committee asked great questions, but those questions do not necessarily have black and white answers. She stated that if her answer is not solid, it is not because she is trying to be ambiguous, she is being honest. She believes it is important for committee members to understand the "lay of the land"; where things are clear and unclear so that members can make the best policy decisions. MS. THOMPSON'S testimony is as follows. The first section of the letter asked questions about jurisdiction. It was entitled Background and I'm going to use this opportunity to throw in a couple of prefatory comments myself, which is, the letter seemed to - seemed like at the last hearing there was some awareness dawning that oil pipelines are really regulated under a very different legal regime than gas pipelines therefore the state's experience with TAPS, our large interstate oil pipeline where we concurrently regulate with FERC, isn't necessarily the way this line's going to be regulated. I think it's also important to understand that all of the federal law on gas pipelines was developed in the Lower 48 and it was based on policies that may not apply here. This is really the first interstate gas pipeline that's come from this state and we're different. We're an island. A lot of the legislation that's been developed on a federal level in the Lower 48 is based on facts that are very different here. For example, the current regulatory scheme that allows contract carriage, or open access as they call it now, is based on an environment where there should be an option, not on one where there's only one pipeline that leaves the state. In the Lower 48, a producer may have several alternative routes to market so it doesn't necessarily matter that the product gets on a specific line. But, nonetheless, the federal regulatory regime, the policies supporting, recognizes the importance of preventing pipelines from being used as a tool to discriminate against shippers so I would urge caution about how the current federal law on gas lines may or may not be applied here and I think, what I heard briefly when I joined this group a little earlier this morning, was discussion about changes in federal legislation. I think that, in order to develop clarity in this situation, is the way to go. I wouldn't assume that it can't be changed because in order to affect the same policies that the Lower 48 law does here, it may have to be different up here because of our geographic location amongst other things. It's also important to understand - and you probably are well aware of this by now - that which federal law applies to this pipeline and how it applies isn't clear. ANGTA was passed in the late '70s, and it gave from a regulatory perspective, it gave remarkable powers to the President to pick the route. But the pipeline that legislation anticipated wasn't built and the deadlines in the Act have passed so only the courts or the Congress can sort out what it really means and how it applies to this particular situation. The significance of that is ambiguity in law creates a potential for litigation. It creates a potential for posturing and delay so any of the parties who have varying interests in one route or the other can hire a stable of lawyers and spend years trying to clarify the ambiguities, or at least threaten to. The alternative to that is a route that would work through the federal legislative process to clarify some of the ambiguities in the law. The only other background comment I have is about the track record that FERC and the RCA have. We have concurrently regulated TAPS over its years and we have a track record of cooperating to do that. I don't have any reason to believe that that cooperation isn't going to still continue. We have a - our relationship with that agency has changed as the head of the agency has changed, but I'm confident that the group that's there now is going to be sensitive to the state's concerns and is going to work well with my regulatory agency. It is not a turf battle between FERC and my agency. We have different concerns. My agency is worried about instate access and instate rates, and FERC is concerned principally with the interstate shipment and responsible for making sure that nothing we do within the state interferes with interstate commerce but I think, within those parameters, we can work well together on this problem. The first question was about state access for instate demand and it was: What would the FERC and the RCA's jurisdiction be over a pipeline along the Alcan route? The RCA - my agency has jurisdiction under the Alaska Pipeline Act, a state law, to regulate intrastate oil and gas pipelines and state law also says that we have jurisdiction over interstate pipelines to the extent that we're not preempted. On the federal side, I know you've heard from Mr. Loeffler and others this morning about the Natural Gas Act. FERC has jurisdiction over all interstate pipelines and under the Commingling Doctrine, if there's one molecule of gas that's transported interstate commerce it's an interstate pipeline. So, at first blush, the Al-Can route, carrying gas to Chicago, would be regulated by FERC but there's ANGTA and its impact, again, is not entirely clear. Section 13(B) is the one provision of ANGTA that I think is most important to focus on here. That gives the state the right to ship its royalty gas - to use its royalty gas - within the state of Alaska. It gives the state the right to go to FERC and say we want to take our share and use it in Alaska and it requires FERC to accommodate that. The language - it's one of those paragraph long sentences that drive me nuts - but I think it could be interpreted either way. I would argue that it gives the state the responsibility for setting rates for that intrastate shipment subject to review by FERC. But, again, that's one of the ambiguities that would be nice to clear up in order to avoid some type of litigation over that issue. I think [Section] 13(B) of ANGTA has another important provision when you're considering instate access and that authorized that - 13(A) - I'm sorry - that prohibits the operator of the gas line and if it's also a producer, from discriminating against others who want to have access to the line. So Section 13 of ANGTA, as it now exists, is very important for delineating state's rights and protecting state's interests in using gas instate. I urge you, if you review any of the drafts now circulating for changes to ANGTA, to look carefully and see what they say in terms of provisions comparable to the current Section 13. The one thing that's important to note is that ANGTA now requires an instate delivery point just for the state's royalty gas. So, if the state - if there's other producers who want their gas to be used instate, they would have to be protected by another means or perhaps through this legislation. And I imagine what would be required of the state, in order to exercise this privilege under ANGTA, would be some demonstration of ability to use, or plans to use, its gas instate. I think under those circumstances it would be very difficult for FERC to deny an access, even on a FERC regulated pipeline within the state. The next question was about generally - a series of questions - about regulation of instate tariffs and prices. Under the Natural Gas Act, FERC would set rate for instate delivery points on a pipeline from the North Slope to Chicago. Again, under ANGTA, the answer may be different. It's arguable under that law the RCA's responsibility is subject to FERC's review for reasonableness, if the gas taken at those instate delivery points is state royalty gas. When we set pipeline rates, we operate under the Alaska Pipeline Act, again, and we're required to set just and reasonable rates. Our case history says that means rates based on cost. So, there isn't one tariff methodology that we consistently approve. There's a number of them and what actually happens most of the time is the producers and the other interested parties negotiate a settlement and they come to us for review of that settlement. They resolve issues like how quickly the pipeline will be depreciated; how DR&R funds will be accumulated; how the rates change according to different take-off points. We review those when we come in, again, to insure that they're just and reasonable, that the interests of future shippers, as well as current, are protected and the public interests are protected. But, we look principally at the cost of delivering service, Just like any other utility regulation, they're only allowed to charge their customers what it really costs them to deliver the service so I can't tell you that there's one pipeline methodology that we use but it's generally cost-based and the history on pipelines in this state is a series of settlements negotiated between producers and shippers that we've reviewed and approved as appropriate. What we do when we get them, if we have questions, we have a hearing, we ask, require further filings, sometimes negotiate other modifications but generally they've all been approved that way. Regulation of an all-Alaska pipeline - there was a series of questions under this that talked about a hypothetical pipeline to Valdez and shipments to Mexico and back or to California via Mexico. Basically, FERC would have jurisdiction over a pipeline to Valdez if that carried export gas. The federal government regulates export pipelines. There are different agencies that are involved. I think Mr. Loeffler probably hinted on that a little but it doesn't matter - it's the federal government, it's not us. Our jurisdiction is influenced by a couple of different factors. If there's a pipeline that begins and ends in the state, that's an intrastate shipment, that's within our jurisdiction. Other factors that are important are: what gas is taken off? Under ANGTA, it matters. Our jurisdiction is influenced by whether or not it's the state's royalty gas taken off. I think also what type of processing or handling is done to the gas that changes its character might influence our jurisdiction. Last, and this is a difficult one to articulate, but where the decision is made to ship the gas out of state. I'll give you a hypothetical to try and explain what I'm thinking of. I've been asked a lot about, well what about if - and I think I heard Representative Ogan talk about it, moving the wellhead down. The hub concept - in order for us to have jurisdiction over the pipeline to the hub, assuming that all the very, very complex economic and processing issues are resolved, there isn't really any direct analogy currently. The letter talked about the Gulf of Mexico case but this is really the reverse. In the Gulf of Mexico, the feeder lines, or gathering lines, they go into a central facility and go out. In this case it would be one line coming out and then splitting out theoretically so, if there was a pipeline from the North Slope that went to a center - and I'll say Fairbanks because that's where I'm sitting today - and in Fairbanks there was some kind of trading center and gas went either through an LNG line to Valdez for export or was sold to a local petrochemical facility for processing or sold to a local utility to generate electricity or shipped on a pipeline route through Canada to the Lower 48, then I think we'd be in a situation where there would be a better reason to argue that at least that first segment of the pipeline could be regulated intrastate. Again, it depends on how the project is set up and designed. That's not inconceivable but there isn't, like in response to many other questions you asked, there isn't really a clear path on that. The next section talked about regulation over hubs. I think I explained why the Gulf of Mexico example isn't really analogous because it's an opposite. The question also talked about spur lines. It's true that any line that went off of a main pipeline that transported product to somewhere else in the state, to a utility or to a processing plant from an off take point, would be regulated by the RCA. This is another area where it would be helpful to have clarification over the federal law if that's what the policy makers decide is the objective, to have where our jurisdiction begins and ends and whether or not - I'm not sure it's a good idea to have us regulate the rates down from Fairbanks but if it is, that's an area where some clarification of federal law defining what a hub or a training center or where the jurisdiction begins and ends, would be helpful. Regulation as common carrier - that was the next series of questions. The letter asked if I knew of any gas pipelines that FERC now regulates as common carriers. I don't but remember, again, that the Lower 48 pipeline regulatory scheme was based on a different market structure. You've got a network of pipelines going all over the place. In a world where shippers have other options, the concept of common carriers that's so important to us, isn't as important. This is going to be a bottleneck facility, at least for the foreseeable future therefore I think there's very strong public policy reasons why common carriage, or some other scheme, it doesn't matter if you call it common carriage or open access, some scheme to ensure that there's non- discriminatory access to the line by producers, any producer that has product to ship is important. And that's something that could be best resolved through federal legislation. The danger of a contract carriage pipeline is that it would allow the producers, or some subgroup of them, to control whose gas got to market. From my perspective, that's unacceptable for a couple of reasons. The state as a royalty gas owner is going to want to get its own gas to market and may be left out of that scheme. Also, as the owner of lands from which the gas resource is developed, I'm sure we'd want to encourage development of our gas resources. ANGTA, again, Section 13(A) talks about - prohibits discrimination against shippers that don't own an interest in the pipeline and that type of model - if there's going to be modifications to that law, bringing that principle forward I think would be very important. It's also worthy to note, when we talk about state regulations to influence who gets their product on the line, what some other states have done. In Texas, they've used some of their right-of-way access procedures to require pipelines to be common carriers. I know that provision is in some of the state leases. I have no idea whether it's in any of the leases on any of the proposed routes folks are talking about, but that's another option for the state ensuring that all producers have access to the line. Another option to think about is the one similar, perhaps, to what the legislature crafted a few years ago on HB 290. I know some of you were around for that effort. There, it was an export gas pipeline at issue. What happened in the end was a balance. The problem was the pipeline owners needed firm commitments in order to obtain financing for the pipeline and there were users in-state who were not able at that point in time to make the long term commitments. So, what the legislature did was carved out, or designated, a section of the line that would be regulated as a common carrier and gave the RCA responsibility when the pipeline project began to come on line for defining how big that slice was going to be and regulating that one piece of the pipeline so that in-state users would have access. That pipeline was never built but that's another - and that concept is untested but that's another option, perhaps worthy of consideration if we're thinking about how the interests of in-state users could be protected. I don't know of any other precedent for that type of scheme on a national level. Again, TAPS was - and how we regulate TAPS concurrently with FERC, was the original model for that. The thought there was that - again, our role on TAPS is to protect the interests of in-state shippers so they pay fair rates even though there's much more pipeline beyond where they take off. The next series of questions was about regulation under the Natural Gas Act, or ANGTA, and it asked about FERC applications. FERC is really the appropriate agency to comment on how it's going to handle applications. They have a statutory obligation to process applications and I understand that their response today was until the application was filed they're not able to say a lot. As frustrating as that may be, that makes sense from a regulatory perspective. What they're going to be faced with is sorting out whatever legal challenges are filed to whatever application they get. The answers are different depending on the particular application. But I'd suggest that if the goal is a smooth process at FERC, that the best model is for all of the interested parties to sort out their differences and go together to FERC with an application. That's the model we've seen in our pipeline cases and I know FERC does the same thing, or experiences the same thing. It's when the parties are able to negotiate, all the interested parties, again if they're not all at the table it's FERC's role to make sure that their interests are protected, but the best model is for folks sorting out their differences before they get there. On upstream access, I'm not well versed on the first and open season process but many of the concerns about that process expressed in the letter are whether the producer owned pipeline [is] valid. My agency's goals and priorities are in-state access at a reasonable cost and that's based on my knowledge and experience with what it costs to generate power in the state and how it might be very helpful to have some of this gas to reduce that cost. I would caution that the cost of constructing a pipeline is really what's recovered in the transportation rate so that if you're evaluating alternative routes or alternative options, whatever minimizes construction costs is really important. I think I saw a statement in the press by producers to that effect and I would agree that minimizing costs is important, although I may look at costs a little differently. The incentives that they have to keep construction costs low are different than an independent pipeline company might have or another owner and that issue is significant when you're talking about keeping tariff rates low enough that in-state users can have reasonable access. I think the state, in summary, has legitimate interests in the connection with this pipeline that will be heard and appreciated at FERC. We have interests in ensuring state access and use of our gas in-state. We have interest in getting our gas to market, if that's what we choose, and a strong interest in pipeline safety. And, any pipeline permitting process that doesn't take those interests into account is not likely in the end to be successful. That's the end of my answers to the questions posed in the letter. I'd be happy to entertain more questions. I saw some scribbling up there so I suspect I'm going to get .... CHAIRMAN TORGERSON asked Ms. Thompson if she could suggest any legislation the committee might consider to make the RCA's job easier. MS. THOMPSON replied not on the state level because her focus now is to clarify the federal law, which would benefit all parties if this project is to move forward. CHAIRMAN TORGERSON asked Ms. Thompson if she has had a chance to review the producers' draft legislation. MS. THOMPSON said she briefly looked at it but has not analyzed or studied it. She offered to provide specific comments if the committee so desired. CHAIRMAN TORGERSON indicated the committee would be interested in her comments. He informed her that the committee plans to meet in September for the sole purpose of discussing the producers' draft legislation. He also said he would provide Ms. Thompson with a copy of the proposed legislation provided to the committee by Charlie Cole. He commented that it looks like some fix is necessary on the federal level and that the committee should provide suggestions for changes to the federal law and her expertise would be welcome. REPRESENTATIVE DAVIES asked Ms. Thompson to expand on her comments about the need for clarification of the federal law in a memo to the committee. MS. THOMPSON agreed to do so. REPRESENTATIVE DAVIES noted that Ms. Thompson stated that an export pipeline would be federally regulated but he thought Mr. Loeffler said that FERC would regulate the export facility. He asked for clarification. MS. THOMPSON said she did not hear Mr. Loeffler's comments but it is her understanding that an export pipeline would be regulated by FERC or the U.S. Department of Energy. She repeated that [HB] 290 pertained to a case in which some of the gas would be used in-state so the rates for that portion of the gas would be set by RCA, but the RCA would have nothing to do with setting transportation rates for gas sent out-of-state. 11:33 a.m. CHAIRMAN TORGERSON recalled something he read that said if the port authority concept went forward or if the pipeline was state owned, it would not come under FERC jurisdiction. He asked Ms. Thompson to comment on that. MS. THOMPSON said she honestly does not understand that concept well enough to comment. TAPE 01-13, SIDE B CHAIRMAN TORGERSON noted that he posed a series of questions to that group to answer at their presentation that afternoon. SENATOR KELLY stated that at the last meeting, the committee talked and heard about FERC jurisdiction if a single molecule of gas was exported or transported to the Lower 48 and it was his understanding that RCA would not be involved if that were the case. He asked Ms. Thompson if her opinion differs since she said that gas for use instate would fall under the regulation of the RCA. He asked if she meant from a hub transported to a community in Alaska or for royalty gas - under what circumstances RCA would be involved. MS. THOMPSON said the committee walked away with the right answer under the Natural Gas Act but the question is: What does ANGTA mean and what impact does that piece of legislation have on the answer? The one molecule concept falls under the Commingling Doctrine, which falls under the Natural Gas Act. That came about because creative state regulators and creative pipeline companies were building pipelines to avoid certain state boundaries so federal regulations were imposed because it didn't make any sense. Alaska has different factual circumstances. She believes it is arguable, although it is not clear, under ANGTA, that the state would have a role in setting the rates under which its gas is transported in- state. If, under ANGTA, Section 13, the state exercises the right to take its royalty gas in-state, then the language of that bill could be construed to give states the right to set the rate to that off-take point for state gas. She repeated that applies only to royalty gas. SENATOR KELLY asked if Ms. Thompson was speaking only to setting transportation rates to the off-take point. MS. THOMPSON said that is correct; she was only speaking about transportation. SENATOR KELLY asked if "to the off-take point" means to the point where the end purchaser purchases it or to a hub where it is then transported from the big pipeline to the communities of the state. MS. THOMPSON replied: To the point where it leaves the pipeline and the end user - I guess there's a number of different scenarios. If it goes, for example, if there's a spur line that goes out of Fairbanks down to the Kenai area, then we would regulate the spur line clearly because that's an intrastate pipeline. We may, under ANGTA, regulate the rates that folks who were the end users in Kenai pay for the portion of transportation between the North Slope and wherever the spur line starts off the big line. That's the ambiguity, whether or not ANGTA means that we have some say in what they pay for their share of shipment on the big line. CHAIRMAN TORGERSON asked if that answer differs depending on whether the application is filed under the Natural Gas Act or under ANGTA. MS. THOMPSON asked Chairman Torgerson if he is speaking about the application that has already been filed when he referred to the ANGTA application. CHAIRMAN TORGERSON said yes. He noted the 1977 law clearly provided for access in-state. MS. THOMPSON agreed. CHAIRMAN TORGERSON stated, "NGA doesn't, except for what we heard earlier, is for some farmers, so we're going to make folks in Delta happy maybe, if it crosses their property but, you know, what about everybody else?" MS. THOMPSON responded that not having looked back at the original application, she is uncomfortable providing a definitive answer. She said if Chairman Torgerson is asking whether the RCA has any control over the in-state rates under either piece of legislation and whether it makes a difference whether it was the original application or another one, she guessed the answer is probably no. She noted this is an area that should be clarified if federal legislation is passed - that the state has the right to set rates for gas that's taken off and used in the state and the federal government can do everything else. CHAIRMAN TORGERSON asked Ms. Thompson if she has, "any recommendations that would stop us from chasing our tail and get to some real answers?" MS. THOMPSON said she shares the Chair's frustration about having to absorb a lot of information. She stated in an ideal world, she would like to see a unified state position that the state could take to the table to negotiate with the entities that will build the line. That would enable RCA to better protect the in-state users. She said she doesn't think anyone has the answer yet, but anything the committee can do to encourage a unified position would be helpful to the RCA. CHAIRMAN TORGERSON thanked Ms. Thompson and asked representatives from FERC to testify. He noted that he distributed the 40-page letter to the committee from Mr. Chamblee [dated August 14, 2001] and the short letter that said FERC did not want to answer any questions until it received an application. MR. JOHN KATZ, Director of the Office of Energy Projects, FERC, informed the Chairman that he noted the concern expressed in his letter regarding the responses provided by FERC officials at the last meeting - that the responses were given in the context of the NGA and not to ANGTA. He explained that FERC officials were trying to answer the questions as they understood them but no one at FERC has an expressed preference or negative sense about whether an application could or should be filed under ANGTA versus under the NGA. Those statutes coexist and it will be up to the applicants to decide what they want to file under. The bottom line is nothing that FERC officials said was intended to cast aspersion on ANGTA or to express a preference. Second, while FERC officials want to be as forthcoming and helpful as possible, it is hard to answer all questions in detail before an application is filed because so much depends on other factors. FERC will first need to know what is being proposed and who is asking for what authority, etcetera. Finally, the questions are also difficult to answer because FERC is an independent regulatory agency with five commissioners who vote on matters of law and policy so staff can provide the standing of the commission's policy and what the commission has done in the past, but staff cannot predict what the commission will do. He said he totally agrees with Chair Nan Thompson that an Alaska gas pipeline proposal is a matter of first impression here and that the ANGTA certificate, which never became a final certificate may pose policy and legal issues that the FERC has not dealt with because of the unique circumstances in Alaska. He said staff does not want to mislead anyone by suggesting that FERC might reach a particular decision. MR. KATZ said that Nan Thompson's answers to the committee tracked the best answers he could give the committee. He said he agrees that Section 13 of ANGTA does contain a provision regarding the transportation of royalty gas and the NGA does not address that. That doesn't mean such a thing couldn't occur under the NGA. In regard to the rates that would be charged for such a service, Chair Thompson spoke on that point. He clarified that Section 13(B) says the State of Alaska is authorized to ship its royalty gas. The end of that section says the commission [FERC] shall issue whatever authorization necessary, "subject to review by the commission only of the justice and reasonableness of the rate charge for such transportation." He repeated that this is hypothetical because no gas has ever been transported pursuant to ANGTA but a plain reading of that section suggests that the FERC would at least need to look at the proposed rates for Alaska royalty gas transportation. He was not sure whether those rates would initially be set by the RCA and then reviewed by the FERC. CHAIRMAN TORGERSON commented that they have been talking about the 1977 act and that, in reality, nothing has materialized as a result of passage of that act. He asked how to account for the pre-build in Alberta and British Columbia in relation to that act or whether it shouldn't be recognized. He stated it seems that portions of the requirements in the law that was passed were accomplished in the pre-build. MR. KATZ said the Chairman is absolutely right and that those two legs of the pipeline were indeed built under ANGTA but no Alaska portion has been constructed. CHAIRMAN TORGERSON said it is very frustrating to committee members to realize that one of the major stumbling blocks it is faced with today is whether or not NGA or ANGTA prevails over an application. He said he finds it almost intolerable that the committee cannot get a decision from anyone. He stated that this issue smells like a court fight and that hundreds of attorneys on both sides will represent Foothills and producers if one side doesn't like what is going on. He said he realizes that FERC's position is to let them negotiate and hopefully work it out, which he wishes they would do, but he feels it is a matter of law and a decision on it needs to be before the FERC so that the matter can be settled. He asked if there is a way the State of Alaska can put this question before the FERC and get a ruling on which law prevails. MR. KATZ said, "I can tell you we are right behind in terms of wishing we had answers to all those questions." He noted in the report FERC sent to Congress, staff stated that ANGTA did not preclude consideration of another proposal under the NGA. ANGTA says the FERC has to do various things and that once it has completed the process of a President's decision and Congress's approval of that decision, the FERC may reject other applications under the NGA, which staff has interpreted to mean that FERC could choose to consider them or not consider them, depending on whether the application is in the public interest. He informed committee members that in terms of getting an answer from FERC, people do file requests for declaratory orders, otherwise the state could request a general counsel's opinion. He said the problem with a general counsel's opinion is that he is not sure the answer will be worth much more than the paper it is printed on because any party could litigate. He did not think another party could litigate a declaratory order because that would just be an opinion that would not affect anyone's right to liability until the FERC acted upon it. He maintained that the issue will probably go to court unless Congress speaks on and clarifies it. CHAIRMAN TORGERSON thanked Mr. Katz and Randy Methura (ph) for their information. MR. KATZ said FERC staff tries to work with whatever agencies and legislatures are involved and hopes to do that as this project moves down the road. REPRESENTATIVE OGAN noted that he believes the statement that the easiest way to resolve this issue is to get Congress to speak is an oxymoron. CHAIRMAN TORGERSON asked Mr. Katz to clarify what is going on within FERC regarding staff and Chair changes. MR. KATZ said that Chairman Hebert has announced that he will resign as of the end of the month and Kevin Madden (ph), general counsel, has also resigned. The President announced yesterday that Pat Woods, who was Chairman of the Texas Commission, and is currently FERC Commissioner, will be the new FERC chairman as of September 1. The vacant seat will presumably be filled with a Republican. CHAIRMAN TORGERSON asked if anyone else, besides the lead counsel, has left the FERC. MR. KATZ said no. He stated that Chairman-designate Wood has an excellent background in energy regulation and has a strong interest in gas issues. CHAIRMAN TORGERSON asked Mr. Katz if he will be the next general counsel. MR. KATZ said that he can promise he will not be. CHAIRMAN TORGERSON asked if the Chairman makes that appointment. MR. KATZ said it is. He noted the Chairman has someone in mind. CHAIRMAN TORGERSON asked Mr. Katz if he has looked at the producers' legislation. MR. KATZ said that staff supports anything that clarifies under what authority FERC should consider pipeline proposals and agrees with the thrust of the parts of the legislation that implies the need for coordination of federal efforts. But, staff has not yet done a detailed review of the legislation. CHAIRMAN TORGERSON asked for a copy of the staff's remarks when they are available. MR. KATZ agreed. CHAIRMAN TORGERSON thanked Mr. Katz and announced the committee would take a lunch break until 1:00 p.m. TAPE 01-14, Side A DEPARTMENT OF NATURAL RESOURCES CHAIRMAN TORGERSON called the meeting back to order at 1:04 p.m. He invited Mr. Bill Britt to testify. He asked Mr. Britt if he believes the state can have, in its right-of-way leases, provisions to protect access to communities or other projects the state might want to do. MR. BILL BRITT, Gas Pipeline Coordinator within the Department of Natural Resources (DNR), said he hesitates to answer specific questions without consulting with counsel because there are limitations to the power, but he believes the Right-of-way Leasing Act is one of the most powerful tools the state has to affect policy relative to the question and it is not frequently recognized as such. He stated that when the legislature chose to preempt the over-the-top route, the Right-of-way Leasing Act was the tool the legislature used to do so. DNR can affect very consequential policy through right-of-way leases; that realm is contractual law as opposed to police powers. However, the state does run up against federal preemption issues within certain areas so it depends on the specific question and what the state wishes to affect. He said he would like to find out how and what the State of Texas has done in this arena. CHAIRMAN TORGERSON said he understands someone will be discussing that issue with the Alaska Highway Natural Gas Pipeline Council on September 17 so they may learn more at that time. He commented that there has been a lot of talk about the hub concept and that there is a feeling that hubs are created legislatively. The committee has not been able to find any such animal. It appears the Commonwealth did something to create a hub and that may be the only example. He asked if perhaps access to Fairbanks could be put in a right-of-way and effectively that may become the hub. MR. BRITT said there are two ways to go. The statute itself contains mandatory covenants that every right-of-way lease must include. In addition, DNR negotiates the lease with the owners of the pipelines, and that includes stipulations and provisions that vary from pipeline to pipeline. If DNR can figure out how to put, in plain language, what the state wishes to have happen, it would be relatively easy to find out whether that can be accomplished through statute, which is where the mandatory covenants live, or through the negotiated lease. CHAIRMAN TORGERSON asked Mr. Britt to comment on the producers' legislation and the port authority's legislation. MR. BRITT noted that he only saw the port authority's proposed legislation for the first time this afternoon but, regarding the producers' legislation, the administration is preparing comments on that legislation. His comments to the administration were that: the definition of Alaskan gas was limited to North Slope gas and he was unsure what affect that would have on future exploration; that the return of the office of the federal inspector would be beneficial; and the preemption to FERC was required to say yes to applications if three tests were met - those tests seemed slanted in favor of the producers. CHAIRMAN TORGERSON asked Mr. Britt if one of the goals of the federal group of agencies that has been meeting is the creation of a "super-agency" to look after rights-of-way. MR. BRITT said their mission is unclear at this time. He was told in a briefing that they are strictly limited to analyzing federal approval processes, determining where the bottlenecks are and making recommendations in a report to be completed in the late fall. CHAIRMAN TORGERSON commented that forming a super organization is consistent with the President's energy policy if the President's goal is to move mega-projects forward. He thought that the President said he would establish such an office in his policy statement. MR. BRITT said he thinks it is a good idea and that is what his office is at the state level. Agencies operating on their own frequently operate on various schedules and at cross purposes. If everyone is under one roof, the process goes more smoothly. REPRESENTATIVE FATE asked Mr. Britt if his office has received enough money from the Division of Legislative Budget and Audit (LBA) to coordinate and implement some of the activities required of his office. MR. BRITT replied the general funds his office received from LBA were sufficient for him to sign two reimbursement memoranda of understanding (MOUs) with Foothills and the producers. That seed money is all his office really needed to begin going forward at a pace determined appropriate in conjunction with the project proponents. He has been hiring staff. REPRESENTATIVE FATE asked if the process was fairly smooth. MR. BRITT said it happened very quickly. After LBA gave Chairman Therriault the power to enter into the agreements, a letter was sent to Commissioner Pourchot the following day. That same day, the agreements with Foothills and the producers were signed. He believes working with Chairman Therriault will be very easy. CHAIRMAN TORGERSON asked Mr. Britt what interaction he is having with the Canadian regulatory authorities. He asked if they are forming a joint office also. MR. BRITT said his interaction with Canadian authorities has been extremely limited up until now. He has been concentrating on the federal agencies so the Canadians will be next. CHAIRMAN TORGERSON asked if we should care. MR. BRITT said he believes so, simply because ultimately how quickly something is approved and the expense associated with that approval occurs on both sides of the border. He thinks everyone will be better served if the authorities in both countries work together. He said he also believes it is easier to influence the approvals of others if the state interacts with and has a coordinated process with those agencies. CHAIRMAN TORGERSON asked Mr. Britt if he anticipates a Canadian member on Alaska's Joint Pipeline Committee and vice versa. MR. BRITT said he thinks that is entirely possible. He expects the state and Canada to be wrestling with many of the same engineering questions and land status and title questions so it makes sense to learn from each other. CHAIRMAN TORGERSON asked Mr. Britt if Jack Griffin is his legal advisor. MR. BRITT said he deals with the folks who work for Mr. Griffin. CHAIRMAN TORGERSON asked Mr. Britt to ask for a legal opinion on the right-of-way issue and provide the committee with the response. MR. BRITT agreed to do so. CHAIRMAN TORGERSON thanked Mr. Britt and asked Representative Ogan to proceed with his questions of Mr. Myers. REPRESENTATIVE OGAN asked Mr. Myers: Mr. Myers - I want to have a little discussion about possible interaction between the producers on what could possibly be deal killers, or at least slow down the gas going to market and maybe have an effect on the routes selected. Kevin Meyer has been on record in the past - and I'm going to kind of paraphrase it, but basically saying that this alignment agreement removes some of the impediments to a major gas sale but - maybe we could talk a little bit about some of the past things that have caused problems, like the MI and NGL dispute. You've got the gas cap owners and BP at odds over that and could you kind of tell us your knowledge of what happened with that situation? MR. MARK MYERS, Director of the Division of Oil and Gas in the Department of Natural Resources, introduced Bonnie Robson, petroleum investment manager and informed the committee that Ms. Robson represented the state as an assistant attorney general on some of the legal issues so he would defer to her on the fine legal points. MR. MYERS stated the North Slope oil field is a very rough playground. The commercial issues involve large dollars and the companies are very much competitors in many ways even though they have a unified interest so that competition is manifested in a large number of areas. There are cases, not uncommonly, where the commercial interests of one company are advantaged over another company and those commercial interests are different than the state's. There are cases when those commercial interests are aligned. Those alignments are usually gotten to through a series of very tough negotiations. Some of the issues are so large that the negotiations are often protracted and have a very strong legal and commercial aspect to them. Regarding the MI-NGL "wars," MR. MYERS said that prior to the alignment agreement, BP had a majority interest in the oil rim, whereas ARCO and Exxon had a larger position in the gas cap. In the case where natural gas liquids were being produced, stripped out of the gas, there were two major uses for them: one was to create miscible injectant (MI) to reinject into the fields to enhance oil recovery; the second was to create a natural gas liquid and ship it down the pipeline with the oil. Once the oil line had sufficient capacity in it, there were some engineering safety concerns that were answered: yes it's appropriate to ship a certain amount of natural gas liquids down the pipeline. The bottom line was that the natural gas liquids were dominantly out of the gas rim acreage that had majority ownership by Exxon and ARCO and therefore they were at a commercial advantage to see those liquids go down the pipeline. The state was in a similar position with its royalty interest. BP felt it was more advantageous to have the MI used for reinjection to recover more of its oil rim oil. So, essentially, there was a commercial dispute in terms of value. That commercial dispute led to BP building separate facilities, which were never used. That dispute moved into the public sector, with several agencies on several fronts, including the [Alaska Oil and Gas] Conservation Commission and the Division of Oil and Gas. Hearings were held and ultimately a settlement was reached and the facilities were not used. It was an example of a commercial dispute getting in the way of the highest and best use of facilities on the North Slope. MR. MYERS said, regarding the Gas Balancing Act, the division would expect the Gas Balancing Act would be needed if a large gas sale were to occur. It would take 100 percent ownership agreement in the field for that Gas Balancing Act, which means a minority owner could block it. Therefore, even though there is alignment among majority owners, major negotiations would need to occur with the minority interests regarding the Gas Balancing Act and the methodology developed and used by the producers. Mr. Myers said to single that case out as unique is not really accurate, he can think of a half dozen other mechanisms that could be used if one owner wanted to block development. MR. MYERS continued: We heard earlier testimony by the AOGCC on the issues of oil production in terms of lost oil production with gas. Obviously, to mitigate that you're going to want to modify the reinjection profiles of the field - either change the gas compositional mix to vary the composition as you lower pressure for additional recovery, increase water flood or a combination of that and other mechanisms. So, that involves significant investment capital. So, you would need all parties agreement. In addition, the AOGCC, through their Title 31, would have to approve it and look at the conservation of the resource and physical waste. DNR through their unitization would have to approve that there's no economic waste and do the balancing between lost gas and oil. But in that process, if you have a major owner there that doesn't want to pay their share, they can kill the project. Or if you had a major producer that did not want to sell their gas, they could argue successfully, potentially, that they need to be compensated for that lost oil. Therefore, we need to extract this extra value out of this negotiation. So, there would be protracted legal negotiations there. Another issue is the gas in probably a 4 BCF case isn't Prudhoe Bay alone. It has to be Point Thompson gas. So now, you've got another separate unit, which will have a separate unit operating agreement where that balancing has to occur. In addition, you have other parties like Chevron and while they have a small percentage in Prudhoe Bay, certainly less than 2 percent, they have about a 25 percent or so interest in Point Thompson. So, again there are parties not even involved in this current realignment that while their position is small in Prudhoe is very large elsewhere in gas sales. So, anywhere without agreement from these parties, there are numerous ways this project can be blocked. Another issue would be the conditioning plant. If it is a unit facility within Prudhoe, it has different implications than if it was part of the pipeline structure in terms of ownership, regulation and potential rates of return for it. So, there's another issue where if someone doesn't want to put the hundreds of millions of dollars they would have to into that facility, it would be very difficult to build. REPRESENTATIVE OGAN asked about a scenario in which Exxon has significant holdings in the Mackenzie Delta area and the board decides not to play unless the route goes over the top, whether it could kill the whole deal. MR. MYERS answered that wouldn't be an unrealistic scenario, although the state has some right to have expectations of the implied covenant to market. If there's a reasonable mechanism to get that gas, we could force the issue through that, but it would be a difficult fight. Another issue is that these are not primarily gas fields; they are primarily liquids fields with significant amounts of gas. So, you have to look at producing the liquids as well as producing the gas and there are multiple ways of doing that. Some of them involve much more capital investment. At 35 TCF on the Slope, Exxon is the owner of the majority of the gas reserves. MR. MYERS continued: It would be very difficult to see the volumes that you would need in this type of process independent of them - if you need a 20 or 30-year supply of gas, to justify the financing. And even if you could solve all the commercial issues and they don't want to sell, that's over a third of that gas. That's a significant amount and would have a major impact on the project…. Basically, I believe the producers will try to reach an alignment of their positions and that's one of the issues of why we're not hearing a whole lot. They will have to reach that internal alignment. Another issue along the line is how much capacity does each company get. I'm sure that's a very hot subject of negotiation. It's probably ongoing. Does a company that has more proven reserves bill a higher percentage of the project or do they in a practical sense get a higher nomination versus someone that's willing to take the risk that they're going to discover more. Someone like Phillips that has a smaller percentage, a 5 percent interest in Point Thompson, has a very different economic scenario than does a company like Exxon that has over 30 percent. There are a lot of internal negotiations and alignments that have to be reached before they reach consensus on the size of the project and what their preferred route is. REPRESENTATIVE OGAN asked if the lack of alignment on Exxon's part slowing any development. MR. MYERS answered: I think we can look at the oil examples of the alignment even in Prudhoe, but lack of alignment - and this is not pointed particularly at Exxon, but at the aligned parties, versus Chevron's interest in some of the satellite oil development - it has been an impediment in the past to rapid development of these satellites. That's again why Chevron's commercial interest in Prudhoe Bay was only less than 2 percent. Their ownership in specific smaller satellites might be much higher than that. It might be 25, 30 or 50 percent. So, the impact on a particular project is much larger in their overall interest. The same thing could occur in situations with gas. That lack of alignment created a problem and we had to hold a hearing on the application to produce. We had to make a decision on what was appropriate participating area. We did not have consensus among the parties. So, we had to act to basically broker the dispute. I think the good news is that we reached a reasonable decision, at least reasonable by our standards and development is going forward. But not without real fits and starts and issues involving how much production is the minority owner allocated and how much do they pay to use existing facilities. Some of those decisions, even though we've reached a resolution, aren't fully decided, yet. We often postpone. We say, 'We'll do a temporary mechanism. You guys internally fix it, come back to us in two years. In the meantime, we'll use this mechanism.' That is a very common way. In the oil field often the disputes are based on commercial uncertainties, uncertainties about how much oil or gas underlays a particular lease, its commercialities, price, etc. Those are often solved by a temporary mechanism that has to be fixed later. So, you agree to the methodology, but you don't necessarily agree to the actual number. That number is back calculated. There are numerous ways to solve these disputes at least to the point where you can go forward with development without fully solving them. I think the alignment is an example of one of those in some aspects because it fixed the problem with the majority owners, but it really hasn't fixed it with the minority. I hope that answers your question. REPRESENTATIVE OGAN indicated that it did and asked what his experience has been with gag orders. He had the impression they were not releasing anything on the gas pipeline unless all three agree. MR. MYERS answered that he wanted to refer some of the legal aspects of it to Ms. Robson. He said: There is an agreement involving the allocation of the leases that is not yet part of the unit or the unit operating agreement. Because of that, it's confidential and we can't talk about it. We're hoping to get clarity on that. If it becomes part of the unit operating agreement, we would be able to talk about it. MS. BONNIE ROBSON, Petroleum Investment Manager, DNR, responded: Basically, the Prudhoe Bay Alignment Agreement was executed in the wake of the BP/ARCO/Phillips acquisition merger and transaction. It was received by the state Attorney General's Office as a confidential document protected through the FTC proceedings. We believe it does address a number of issues typically found in a unit operating agreement and that it doesn't in fact amend some of the terms of the Prudhoe Bay Operating Agreement. So, we have prepared a draft letter and forwarded it to the Attorney General's Office for review in which we will ask the producers and specifically the Prudhoe Bay unit operator, BP, to file that as an amendment to the Prudhoe Bay Unit Operating Agreement and then provide copies to the public. Again, it's not certain that we will be able to do that. Our request has to receive legal review and it may be contested by the producers. MR. MYERS added: I think I'd address it a little more philosophically in terms of I think: a) The companies are reluctant often to share their commercial disputes or their dirty laundry in a public forum and you can't fault them for that. So, that's part of it. Another part of it is, I think, a unified front to agencies like ours that negotiates royalty or deals with tax structure has value to them. It has strength and value in terms of the risk of divide and conquer and other scenarios. I think those issues have lead to an approach we've seen recently from the AOGCC and from us that it has often been very difficult to get information that in past years has been relatively free flowing to agencies that are able to deal with confidential data. So, we've seen an overall effect of less information flowing directly to the state. I will say in past years the lack of alignment and the commercial disputes which we have had to resolve, and often we have a royalty interest if we have varying royalty rates, for example on a lease. The different technical interpretation by the different companies helps us review our own internal interpretation and look at other optional interpretations. So, it's been a value. A unified interpretation that's a compromise that fits all the commercial needs often isn't the approach we would really like to see. We'd like to see the best unbiased interpretation of the data. Again, that's one of the reasons we have technical folks that do forensic type geosciences engineering and geophysics - is to actually determine where our commercial interests are harmed or where we believe the interpretation has more uncertainty or less uncertainty and that affects the bottom line. That is one of the aspects of when you see a combined approach and interpretation. We've lost the benefit of that which, again, I would argue is another argument for the state to strengthen their ability to do those types of technical interpretation. It's also a function of a unified front in that we can expect in these cases to get a variation of interpretation. I do want to stress these are variations in interpretation of data with uncertainty. It's not mischaracterizations of the data. It's taking a more liberal or less liberal interpretation of that data. DEPARTMENT OF REVENUE CHAIRMAN TORGERSON thanked him for answering their questions and announced that Commissioner Wilson Condon, Department of Revenue, would comment next. COMMISSIONER CONDON introduced Mr. Ed Small, Cambridge Energy Research Consultants (CERA), to give them a market update. MR. ED SMALL, CERA, updated the committee: There has been some significant changes in the past month. The combination of continued demand softness and the supply growth that we're seeing has caused us to revise our pricing outlook downward and downward fairly substantially. We believe, though, that this more of a short term situation than an enduring phenomenon and as I go through the why, hopefully that'll give you an indication of where we think we're going in the long term as well. The current situation is one where the Lower 48 supply is up. It was up about 500 MCF/D last year. We're expecting it to be up about 800 MCF/D this year. Depending on how low prices go, to be up between 600 - 800 MCF/D again next year. Canadian supply is going to be up about 850 MCF/D this year. So, in total we're in that 1.75 BCF/D increase for 2001. What that is causing is out of the 2.5 BCF/D of residual fuel oil that had come on and switched off gas during the winter, there's currently only about .5 - 1 BCF/D that is still on residual fuel oil. We expect that to be gone by the end of the year. In other words all of that demand that had switched to residual fuel oil will likely be gone and be back on gas by the end of this year. What that does is it eliminates the price floor that we have seen over the past four to six months. When prices came down to a point where residual fuel oil was cheaper, that caused the gas to basically stay at that level or people would switch back to fuel oil. So, we see that floor being gone probably in the fourth quarter of this year. At the same time that we're seeing some growth in supply, we are seeing continued demand softness. Power demand in the West has been off 10 percent this summer. It has been up to flat nationwide in the Lower 48 with the recent heat wave, but prior to the last few weeks nationwide power demand had been off. The demand softness is primarily in the industrial sector, though, power being one of the things I just mentioned, but industrial demand is the biggest factor. How much of that is economy driven is still hard to tell. I think I mentioned that last time I chatted, but we have revised our GDP outlook lower for the balance of this year and in 2002 we expect to see some recovery the second half of 2002. At this point in time, we are looking for a GDP growth of 1.1 percent in 2001 and 1.4 percent in 2002 with the majority of that being in the second half. What that does say is we do expect to see that industrial demand come back next year. In 2002 we expect to see industrial demand increase by 1 to 1.2 BCF/D over 2001 levels, but again most of that will occur in the second half of the year. Currently, ammonia is still down, the manufacturing sectors are still hard hit, steel is still off, etc. In 2002 we also expect to see roughly 300 BCF/D of power growth. So the combination of the industrial and power should give a demand growth of about 1.5 BCF/D next year. That suggests that by the end of next year, we'll begin to see the kind of supply/demand tightness we experienced in the second quarter of this year. What's happening now also is impacted by storage. In spite of last week where storage was basically flat, we still expect storage to reach anywhere from 3 to 3.2 TCF by November 1 of this year. Keep in mind that full is 3.3 TCF. So storage is going to be in very good condition going into the upcoming winter. In 2002 absent a cold winter, we expect the supply situation to be such that storage will be closer to that 3.3 level going into the winter of '02 and '03. So, those are some of the factors we expect to cause the price softness. To give you a sense of what price softness we're talking about, when I chatted with you last we had indicated a Henry Hub price of $4.41 for 2001. We've now lowered that to $4.24. We had an outlook for 2002 of $3.53 on average. We have lowered that to $2.80 Henry Hub. But as I had indicated, there is going to be an impact of this lower price. That impact is going to be both on the supply side and on the demand side. We're already starting to see indications on the supply side via lower rig counts. They are starting to show some softening. We're starting to see indications that rigs may be leaving the Gulf of Mexico. So, if we see the price we are calling for the balance of this year, it will likely have an impact on drilling. That with about a six month to one year lag means a lowering of the supply growth, not necessarily going away, but not as strong as it would have been had we seen the kind of drilling levels we have seen for the first half of this year. So the lower prices will have an impact by lowering the supply response. It also will have an impact in addition to the economic growth we expect next year. Lower prices should help bring some of that demand back - ammonia, steel and some manufacturing. Where this leads is to the likelihood of 2003 prices going back into that low $3 level, probably between $3.10 and $3.25. So, the outlook that I have suggested going out through '05 we still believe is the path we will be on from '03 through '05 of prices in the low $3, around $3.25 range. As an indication of that, that's kind of the level that we expect to see prices by the end of next year even though the annual average will be below $3. So, that is the update since we last spoke. CHAIRMAN TORGERSON asked if he had any information on the proposed receiving plants around the U.S. for LNG. MR. SMALL replied: The only change I think is that there probably has been one addition to the ones I had indicated before. I think the answer there is the proponents of those projects are going to be wrestling with the dilemma of the short term price softness. I think unless they have a belief that prices are going to be stronger in the longer term, it would be difficult to proceed in the short term. But the prices have not been soft enough long enough for any of the proponents to say 'No, we're not going ahead.' So, basically, there's no change on that front. CHAIRMAN TORGERSON asked who will get scared off first on the lower prices, LNG or pipeline? MR. SMALL replied: That is a very good question. It is one of those situations of who blinks first. Part of the answer I think is going to be in which companies have the stronger price forecast going forward. If they believe as we do that in '03 you'll see some strengthening again, those people would likely go ahead. If people believe that we're going to see softness continuing, those will be the people that blink and back off. Who goes first is really hard to tell. The other factor is obviously the magnitude of the costs involved. The higher the risk, the higher the cost. I think those people may have a tendency to blink first. CHAIRMAN TORGERSON thanked him for joining them and directed the discussion to Commissioner Condon. DEPARTMENT OF REVENUE COMMISSIONER WILSON CONDON said: Since we started at the end with item 5 and CERA's update, maybe we can just go backwards and touch on item 4 next and then conclude with item 3. In item 4 you ask for a discussion, some analysis, some conjecture about netback values and how the notion of netback is used to determine values for severance tax and royalty purposes. I'll talk some about the use of netback valuation for the severance tax and Bonnie Robson will address the same set of considerations for royalty. The first thing that you asked was how crude oil severance tax values are currently established. And that really involves basically a two-step process. The first step is valuing the oil in the destination market where it's disposed of. When we talk about destination market or crude oil that's sold by the producer to a third party, we're talking about the place where that sale takes place. If the crude oil is not sold as crude oil by the producer, but instead is transported to that producer's refinery and refined, we're talking about the location of the producer's refinery. Today for purposes of taxation there are three important destination markets. One of those is the West Coast in the Lower 48 and that really is the refining area in the Puget Sound and in the Bay area in Southern California. As well, Alaska North Slope crude is disposed of at tide water in Alaska and that's treated as a separate destination market for valuation purposes and finally, there is some production sold at Pump Station 1 on the North Slope. In earlier times, when the production level was considerably higher than it was today, there were dispositions on the U.S. Gulf Coast, on the U.S. East Coast, in the Caribbean area, in the U.S. Virgin Islands, and in the mid-continent in the refineries that exist in the Northern Midwest. Each of those was treated as a separate destination market when Alaskan oil was transported there and either sold there or refined there by a producer. Then in the '90s for a substantial period of time Alaskan North Slope crude was transported to the Far East and sold there to refiners in Japan, Taiwan, South Korea, and the Peoples Republic of China. The Far East was also treated as a separate destination market, in terms of how oil is valued in those destination markets for that is sold to third parties. The valuation measure that has been implemented in our production tax is to use the higher of two measures of value and those two measures are what the producer actually sells the oil for a measure of the current market value in that market, a term that goes under the label in the tax business here, of prevailing value. With respect to crude oil a producer takes to its own refiner, the value measure there is what I call prevailing value, which is what we hope is an objective measure of value in that market. Having determined destination values, we jump to the second step in the process, which is to subtract from the applicable destination value in the disposition market each taxpayer's actual transportation charges from the point of incidence on the North Slope where the tax applies to the destination market where we have calculated this value. Thence for the netback, you take the destination value and subtract the transportation charge to arrive at a netback value. That's how values are determined for severance tax calculations. Over the years we've had to face a number of issues. Some of those issues will be resurrected when we talk about gas taxation. So, I ought to run through those briefly. First major issue that we've wrestled with for the better part of 25 years is how to determine this thing called prevailing value. When we're telling tax payers they have to pay taxes on the basis of this value, we have picked a measure that they can know and appreciate when it comes time to pay their taxes. Today we believe we do have a system where a taxpayer can and should know what they should be paying their taxes on. The measure we use for determining this thing called prevailing value is the spot price that's published by the third party reporting services. That is the measure we use for determining prevailing value both at the West Coast, which is where that price applies, and we use it to calculate a prevailing value at South Alaska and at Pump Station 1. Spot prices for Alaskan North Slope crude have been published by third party reporters since the 1983-4 timeframe. They actually weren't recognized specifically in the regulations that apply to the severance tax until 1994. Before 1994, this measure, prevailing value, was based on the price that would be derived from three sales contracts selected by the department in each of the destination markets. That determination was made by the department at the time it conducted its audits and had an opportunity to collect some or all of the contracts from all of the producers. What this meant, of course, was that producers did not know which contracts were going to be used. They probably for the most part [END OF TAPE]. TAPE 01-14, SIDE B COMMISSIONER CONDON continued: …what other producers' contracts looked like precisely. So, we did have a situation where sometimes many, many years went by before we told the producers precisely what the prevailing value we expected them to pay taxes on would be. Presumably they did know what they actually sold their production for. So, today we believe we have a transparent knowable valuation procedure so that taxpayers can know what their tax obligation is. We have to be concerned, not that this hearing is focused on oil issues, but the spot price that we believe is reliable today, given the declining production rates. Changing marketing patterns may not be reliable indefinitely. That's something we have to be concerned about as time marches on. The second issue we've had to face is which deliveries match which production months. If you stop and think about that for a minute, you realize that oil comes out of the ground on the North Slope; it moves down the TransAlaska Pipeline; it may sit in the terminal for a while in Valdez; it's loaded on to tankers. Today those tankers take it to West Coast refining locations, sometimes including the Cook Inlet, have gone to the Far East and for a long period of time went to locations on the East Coast of the United States and it took in those instances six weeks or longer for oil to get to market after it was produced on the North Slope. If you're going to be matching values and determining a higher of some objective measure of market value and proceeds at destination and then matching that back to a production month on the North Slope, you obviously have to figure out which deliveries go with which production month to implement the tax value. That's been a complicated problem that we've wrestled with over the years. We think we have a good solution now for oil and no doubt the problem that we'll have to wrestle with on the gas front will be different than what we've had to wrestle with on the oil front. Similarly, where you're using different value measures, you also have to make sure that you've matched the right measures in destination market and this gets a little more complicated than I want to get into today, but in the oil business, when you hear a spot price quoted today, that spot price is for deliveries that will occur next month. Where you have prices quoted in the press, we talk about the August spot price, but the August spot price really applies to September deliveries. Again, that requires that if you're going to have a measure where you're looking at some objective measure of value and comparing it to actual proceeds, and you're making reference to spot prices and you have volatile prices, as we do, to get a fair match requires some care and ingenuity. Again, it's a problem which we think we've solved correctly, but it is not a problem which we arrived at a solution for easily. The next problem is determining transportation charges and for that in the oil area, it's really meant determining what a fair return on the capital investment made in the tanker fleet ought to be and then coupled with that is the question of how you take a bundle of charges that just occur over time and allocate them on a month by month basis so that you have a definite figure that you can subtract for value every month. You've got to adopt a set of conventions that are knowable by the taxpayer so they can take their transportation charges and allocate them the way you expect them to allocate them to determine a value. That has been another administrative problem that we've had to solve with respect to the netback valuation of Alaskan North Slope crude oil production. Going forward, how do we see the value determination for North Slope gas production including the various liquid components in the gas. As we sit here today and think ahead to what ought to happen, we have identified three principals that we stick to today. One of them is that we believe we ought to continue with the notion of higher of. We get at least market value and if somebody makes a particularly good deal, we get the benefit of that deal. We want to make sure that however we value gas, that we capture the economic value of the NGL components and we want to come up with a procedure where it's possible for the taxpayers to know the right value on which they're supposed to be computing their taxes at the time they file their returns or shortly thereafter. If they can't know it in the month immediately following production, which is when their taxes are due, that they are able to get the information in some manner so that they can figure out what it is that they were supposed to have paid. With respect to the problem areas that we're obviously going to have to address in pursuing those principles, we're going to have to determine a good objective measure of market value to determine prevailing value. As we look at the world today there are some possibilities out there, but as I'll discuss at the end, I think it's premature to do anything other than examine those possibilities. The province of Alberta has come up with a very ingenious way of deriving what they call an Alberta reference price. That's certainly a candidate for a measure of prevailing value, but it's entirely possible that transportation system that carries North Slope gas to market would in effect bypass Alberta and carry gas directly to the mid northern United States in which case the market peculiarities that are faced by Alberta production might be bypassed by Alaska gas. So, we don't know whether that would really be a good measure. Obviously, in the gas business we need to make sure we correctly identify what we contend the actual proceeds of transactions are, if there are incidental charges where consideration changes hands in terms of the gas transacting. Should some of those be included in the value is something we'll have to work through when we see what the business looks like. We're still going to be faced with the same issues, although the solutions will probably be different for matching dispositions to production months. There may as well be issues relating to allocating costs of particular production months. Can we solve these problems today in terms of adopting a set of regulations and putting it to bed? Our past experience certainly would suggest no. We're talking about deliveries that are going to commence if we're fortunate 8-10 years from now. We're hoping for something sooner. But, if you think about the oil business, North Slope production started in 1977 and back up to 1967 and say what changed in the world from '67 to '77. In '67 U.S. crude oil values were the province of the Texas Railroad Commission; OPEC existed, but hadn't flexed its muscles; the notion of spot prices simply didn't exist; that's not how oil was priced. If you look at what the world looked like when TAPS commenced, you had OPEC in the driver's seat trying to establish an official price which they hoped to defend; we were marketing oil on the Gulf Coast and in the Caribbean and on the East Coast. We wouldn't have guessed that would happen as we looked ahead from 1967 to 1977. There were some spot transactions that were occurring in 1977, but there was no transparent spot market. Then, if you fast forward ahead another 10 years to 1987, OPEC has given up this notion of an official price and is simply trying to control prices by controlling the volume they produced. The NYMEX futures market had come into existence and there was a reasonably transparent spot market and certainly spot services were publishing prices. In 1987, there was not an agreement or a consensus that spot prices were the best and fairest measure of value. That was the state's position, but the producers in 1987 argued strenuously against that position. But, you move ahead 10 years to 1997, we're shipping ANS to Asia; there's a general agreement that reported spot prices are an accurate measure of market value. That notion is recognized in our regulations. And not to belabor this point too much, but if you go back 10 years ago and look at the gas business, again the changes over the last 10 years have been dramatic. That was just the beginning of a transparent spot price regimen nationwide. The NYMEX futures prices had just been established; the regional trading hubs that exist throughout the continent today were in their infancy in terms of the kind of transacting we see there today; and who those majors were at those trading hubs were a completely different kind of company than is active at those spots today. The point I really want to make here is that to be able to put together a workable netback pricing scheme, we're going to have to see how the realities of the marketplace evolve before we nail down exactly how we're going to do what we're supposed to do. CHAIRMAN TORGERSON asked if that is a chicken-egg deal. "Wouldn't you assume the producers would like to have taxing stability before investment versus what you're saying - Let's wait and see what happens and then set a taxing structure in place?" COMMISSIONER CONDON answered: Ideally, they would want us to be able to tell them exactly what to do 10 years in advance. I'm offering the proposition that that's just something that's impossible to achieve. We're certainly happy to work with them. We have been talking to them about how we go about solving this problem. It's my sense that they really don't understand the nuances of what we need to do any better than we do. They understand that these are problems that need to be solved, but they're not sure what their own business is going to look like - whether they're going to enter the Alberta market or not, whether they're going to have a bullet pipeline - I could go on and on. CHAIRMANT TORGERSON said: "We may have to work on guidelines that are flexible to some degree." COMMISSIONER CONDON agreed and added: "We have a set of principles that I have said we wanted to pursue and that is to have a way so that the producers can know what the tax right value is when they file their returns. REPRESENTATIVE DAVIES said that Commissioner Condon had indicated that there were also prices at tidewater and at Pump 1 and asked if they were the netback of the transportation costs from the spot market price. COMMISSIONER CONDON indicated that was right. REPRESENTATIVE DAVIES asked if there was anything the state learned from that in terms of pricing gas at Fairbanks. COMMISSIONER CONDON replied no and that it is likely to be an algebraic equation and: It would be my guess that it could be much easier than what we have on the oil front, because it very well may be that the transportation system for gas is completely covered by regulated tariffs that have been approved by a regulatory commission and business is built around those tariffs. That's not the situation we have with respect to the tinkering part of ANS oil moving to market. REPRESENTATIVE DAVIES responded: But we still have, even if you know the tariff perfectly, you still have the price determination and where that point applies and what distance you would apply from the market back to the sale at point, let's say, Fairbanks. COMMISSIONER CONDON replied: We don't know today what kind of tariff arrangement - whether it will simply be a MCF per mile tariff or some other arrangement. We don't know whether the market values we'll be selling gas into will be markets where everyone pretty much agrees on what the values in those markets are. It would be my guess that that would be the case, because as time has unfolded over the last 40 years, pricing has become for both oil and gas more and more transparent. So, I don't believe over the next 10 years pricing will become less transparent, but obviously anything is possible. He said he would let Ms. Bonnie Robson discuss the royalty issues. MS. BONNIE ROBSON said she would briefly discuss royalty issues and address some differences between royalty and tax and build on some points made by Commissioner Condon: I believe the first question you asked is how does the netback methodology work for both royalty and tax purposes. It works for royalty purposes much as it does for tax purposes. There are several exceptions. The first is that when it comes to destination value, I believe Commissioner Condon described two measures of destination value - one being actual proceeds and the second being a proxy for market value that is called prevailing price. For tax purposes the higher of those two measures is used. For royalty purposes it depends on the individual lease form at play. All of the lease forms provide at least three operative measures of destination value. The first is a producer's actual proceeds for the sale of gas. The second is the average of other producers' in the field proceeds for gas and the third is market value for gas. Again, the state is entitled to the highest of those measures of value. There are other measures that are either not operative such as posted prices in the field or measures that apply in certain newer lease forms such as minimum value. The second way in which royalty and tax netback methodology is different is that taxes are typically implemented through statutes and regulations and may be changed by the state changing their statutes and regulations with public comment, but not necessarily public agreement. Royalties on the other hand are a function of contractual arrangements with the lessees and so we do not necessarily have the opportunity to correct any errors or problems made at a prior point in time. That is we must live with the lease forms now in existence and if we were to enter into agreements with the producers now on valuation methodology, we would have to live with those throughout time. I believe another question that you raised was what specific problems do you see with regard to the implementation of a royalty valuation methodology. I think the primary problem is that the producers have approached the administration and asked the Department of Natural Resources to enter into negotiations and in fact complete those negotiations this calendar year on a royalty valuation methodology and on whether the state will take its royalty share in kind or in value. Quite frankly, we have advised the producers that we do not believe we have sufficient information at this point in time to even commence those negotiations. We feel that the situation is somewhat different from the oil situation in that yes, we do have royalty oil settlement agreements, but those were reached in 1991 after approximately 14 years of litigation and an opportunity to review a decade's worth of contracts for the sale of the state's royalty oil. We are now being asked to enter essentially a settlement agreement on the valuation of gas without having seen any gas sales and certainly no gas sales contracts. So, there are basically four areas where we are short of information. · One is we do not know what the actual destination for this gas will be. · Two, we do not know how this gas will be marketed. · Three, we do not know what the actual transportation costs will be. · Four, we do not know how the world will change between now and the actual time of gas sales. I'll just comment briefly on each of those four points. In terms of us not knowing what the actual destination will be; of course, one element of the netback methodology is destination value. It's quite possible that this gas will go to multiple locations in the Lower 48 via Canada and specifically Alberta. There is in fact a trading hub in Alberta. North Slope gas may be traded in Alberta, but certainly that is not its ultimate destination, at least to the dry gas. Maybe it will be as to the liquids. We do have a concern that our gas not be valued in Alberta, because that is a market in which supply we think will always exceed demand and that is a formula for a low price. We think it should instead be valued, even if first traded or sold in Alberta, in its actual market or destination, which we expect to be the Lower 48 where demand will equal and possibly exceed supply, which is the formula for either a fair or high price. We do not know how the gas will, in fact, be marketed. As I mentioned, we have not seen gas marketing contracts for the Lower 48 states. We have in fact advised the producers that as a starting point we would like to see some of their actual gas sales contracts for the Lower 48 states. We would like to see, for example, as a starting point, their 10 largest gas sales contracts for a representative month; their 10 smallest contracts; 10 contracts that they believe are representative of the spectrum of their actual transactions; 10 contracts if not included in the above for field sales; also if not included in the above, 10 contracts for sales at hubs. We'd like to see 10 processing contracts; and we'd like to see 10 straddle plant contracts. We would also like additional information on how they market gas. Again, we think this information is a starting point on some of the information we believe necessary to intelligently enter an agreement on valuation. I mentioned third, I think, that we do not know what actual transportation costs will be and one area in which we are particularly deficit is that we expect by the time natural gas flows to market the estimation of recoverable resources will increase above its 35 TCF and this matters for a determination of the useful life of the pipeline and the conditioning plant. Right now, if we have a 4 BCF/D pipeline, we would expect that the known reserves of 35 TCF would move to market in 23 years and the producers may in fact argue for a useful life of 23 years or less. In fact, we would expect that the facilities and pipeline would have a longer physical life than that and we would expect with additional activity in the Foothills area, in NPRA, possibly with gas hydrates and elsewhere on the North Slope, that number would increase and increase substantially, therefore, supporting a longer useful life. The fourth point is that the world will change in ways we cannot predict. It makes us extremely hesitant to now enter an agreement, particularly if there's not any ability to revise the terms of that agreement. We have in the oil settlement agreements, and I think we should have in any gas valuation agreement, a provision that allows the reopening of those agreements to account for changes in market conditions in the future. With that, I know time is tight and I would be happy to answer questions you have now or at a later point in time on any royalty issues. CHAIRMAN TORGERSON asked how the producers had responded to her request for agreements. MS. ROBSON replied that she had just provided the list to the producers one week ago today. The department had not received a formal response from the producers. "They have asked for the list in email form so they could distribute it more extensively." CHAIRMAN TORGERSON said the producers had asked them to assist in tax stability type questions and to work with her and the administration to expedite some of this. He said the legislature would need a lot of the same information if they were going to help. "For those that are listening, they best share data to everybody." REPRESENTATIVE DAVIES said: On the reopeners, you had indicated that one of the substantial differences between tax and royalty was the contractual nature of a royalty. When you first characterized that, it was pretty fixed. But then you indicated at the end that we do have some reopeners in the oil situation. Is that something we need to be looking at in terms of providing better flexibility to meet uncertain future conditions than we have in the past? MS. ROBSON replied: I think it's very much in the state's interest to provide for a reopener. The lease forms, themselves, do not specifically address a reopener. However, they do call for at a minimum payment on the basis of market value. So, as market conditions change, accommodations can be made. The problem becomes as we enter an agreement that market value will be measured by for instance the spot price at a particular hub, that may not in fact be indicative of market value in the future. And so, we need a mechanism to get back to market value if we enter any new agreement now. REPRESENTATIVE DAVIES asked if that was in terms of any royalty arrangements, something we have to watch pretty carefully? MS. ROBSON answered: "Absolutely!" COMMISSIONER CONDON said: On item 3 you asked us some questions about modifications to the taxes portion of the fiscal system and your letter states that you assume we have looked at property tax, accelerated depreciation versus regressive systems. Let me briefly review what we have done. With respect to the state fiscal system and how it would impact the economics of a gas commercialization project, we certainly looked in detail during the 1995 - 1998 period with respect to an LNG project as a part of that being HB 393 enactment and our employment of Dr. Van Meurs' report he did and the recommendations he made. At the conclusion to that process we ended up with an analytical model developed by our staff working with him that was appropriate to an LNG project. It was a model that we reviewed with representatives of the producers both prior to and subsequent to some of their participation in the LNG sponsor group. We also reviewed the model with staff folks from Yukon Pacific. Following the LNG project activity, there was a brief period of time when GTLs were pressing to be the lead candidate for North Slope commercialization project and we actually spent a fair amount of time with the folks. First, we modified the model to make it useful for a GLT project. Then, the staff analysts from Exxon were generous enough to spend a fair amount of time with us critiquing our model and we ended up with a model that it's my sense, although I never spoke to them directly, thought fairly represented what we needed to be looking at if that was the direction North Slope gas commercialization was headed. Now, of course, we have the proposal for a pipeline from the North Slope to mid North America. We have not yet calibrated that model and you've certainly had an opportunity to play with it and see what it does. We need to sit down with the producers and their study team to make sure that the way we've calibrated the model makes sense. We have not been able to do that yet. We have, however, looked at some elements that you posit we must have looked at. In terms of using the model and others, we have not. We have looked at what would happen if you did not impose the 20-mill property tax during the construction period and over a wide range of project costs that makes about a two-tenths of a percent difference in the rate of return of a project. What that really is going to mean in terms of whether it matters, we need to have much more definite information about what project costs are likely to be and where the projects are going to go. What we have done is really a rough look- see. I don't think getting a rough look-see is a particularly valuable result. Obviously, such a change would leave local governments without a revenue source, which they're not going to feel particularly keen about, because the time when such a project is likely to most affect the provision of public services is going to be while the project is being constructed. Similarly, it would deny some revenue to the state government. Such a change in the state's fiscal system would have minimal effect on the federal government and it would improve the rate of return for the project. With respect to accelerated depreciation, that's a possibility. Exactly what affect it's going to have on the project and whether it really helps the project depends on who owns the project. If the project were all owned by third party providers and not by producers, the accelerated depreciation probably wouldn't affect them very much, if they could pass their costs on directly to the producers. It might, however, increase the value of the gas at the wellhead by reducing the tariff. With respect to the question of progressive versus regressive systems, that's an issue, which we've talked about in generalities and have no specific analyses that we have done. We have talked to Dr. Van Meurs about helping us. He's not going to be available until we've reached the winter months and in terms of having the kind of information we need to have to even begin to do this analysis, I'd be surprised if we have it much before then. So, we're not ready to recommend changes that you should consider adopting. We need information and at least this point in time it would be our strong recommendation that we continue to rely on the consultant who helped us as we looked at the LNG project and who is already familiar with the ins and outs of our fiscal system. That's the end of my presentation, Mr. Chair. CHAIRMAN TORGERSON asked about Mr. Katz' testimony on page 26 saying, "It's not secret that one of the three producers, Phillips, has proposed amendments to the federal fiscal regime, i.e. the tax regime. Exxon and BP are not implicated in that proposal." He asked if Commissioner Condon if he was familiar with that proposal. COMMISSIONER CONDON said he was familiar with it and has talked to Phillips about it. They wanted to have the honor of making it available to the committee. He didn't have any comments on it at this time. CHIARMAN TORGESON said it was his understanding that they were trying to get downside protection if the price was to bottom out and asked if a regressive tax system that reflected the price, like Dr. Van Meurs told us we ought to do ever since he came on board years ago, wouldn't that also offer them some downside protection? COMMISSIONER CONDON replied that it would offer them some downside protection, but it would be quite small compared to what they would like to achieve in their proposed legislation. CHAIRMAN TORGERSON asked if he thought they would be amenable to looking at a progressive tax system. COMMISSIONER CONDON replied that he didn't know. CHAIRMAN TORGERSON thanked the Commissioner and Ms. Robson for their presentations and announced that next they would have Mr. Richard Peterson give his presentation. ALASKA NATURAL GAS TO LIQUIDS COMPANY MR. RICHARD PETERSON, CEO, Natural Gas to Liquids Co., addressed their gas to liquids proposal, how GTLs can help a gas pipeline project and a little about misconceptions of GTLs and Petroleum Alternative Liquid (PAL). Our proposal initially was to build a 50,000 barrel per day (BP/D) world scale GTL plant that would use approximately .5 BCF of natural gas and batch that product down the oil pipeline. We were going to work with the state and third parties, primarily not the majors, to obtain the gas for this particular project. We are also going to work with Moss Gas and Alaskan companies, primarily for their expertise in the GTL field. We want to use existing proven technology so we could get lower costs on financing and we want to batch the syncrude down the oil pipeline. We want to be able to market this product on the West Coast where it would get the most exposure for environmental concerns and market the naptha, which would be about 20 percent of the product in the mid East. That is basically our proposal. We still believe today that it's an alternative to other projects. It's also something that could work very well with a gas pipeline. I would like to say for the record that I'm not here to oppose the pipeline; I'm not here to support the pipeline. The pipeline will have to make itself on whatever the market is going to determine the value for the natural gas. What I wanted to talk about, then, is what are the benefits we see of a GTL plant. We see quite a few benefits GTLs can have for a gas pipeline, but I want to focus on one thing only. If you look at the CO2 extraction plant that you're planning to build and the NGL plant, if you combine them into one facility on the North Slope and you're able to use the batching facilities for GTLs, you can batch those NGLs down to Valdez. So, you can locate the entire structure in Alaska. We think it would be a much more economic way to do it. The other thing we see is with the batching you can take any NGL and run it down to Valdez where you can process it and market it for other materials. The other thing we looked at is if you operate a dense phase gas pipeline, every single take off point that you're talking about in Alaska, you're going to have to put treating there to remove those liquids. If you operate a single phase pipeline, you're going to have more capacity and you're going to have less cost and more ability to take gas off at the various locations down the system. I think it's fair to say that a single phase pipeline will have greater capacity using the same diameter for natural gas than if you ran it on dense phase. Probably the last thing that we say is if you put this facility on the North Slope, a hundred percent of the cost of the NGL processing facility, which I've heard is $2 - $3 billion, is in Alaska. All the processing jobs are in Alaska. So, it's a major benefit for Alaska and Alaskans. I want to briefly talk about what I call misconceptions on the GTL side. Is the process proven? Is natural gas the only fuel? Do we need some sort of super federal support to make it work? Are GTLs economic? The first thing I want to say is that if you look at GTL plants world wide, which have been announced, roughly Shell has announced seven plants world wide, [indisc.] has two more. There's over 600 BP/D of new GTL plants being announced in addition to the 300,000 barrels of GTL plants already on line. GTLs are not some sort of technology that has yet to prove itself. It is a well proven technology. It's a matter of how you market [END OF TAPE]… TAPE 01-15, SIDE A MR. PETERSON continued: …in Cook Inlet or not. If we're running out of gas, coal gasification makes sense. Especially with a combined cycle of electric generation facility. If we're not running out of gas, GTLs will work there. The other point I want to address was the federal financial support. Many people have said that a program as we proposed is uneconomic and needs massive federal support. What we've said is if you're going to build a 50,000 BP/D GTL plant, you need roughly about 1 MB/D of batching capacity to eliminate any sort of cross contamination problems you have. That will support 800, 900, or 1,000 1 MB/D GTL plants. The first 50,000 BP/D plant cannot afford to pay for that. It would be akin to saying you build a gas pipeline to the Lower 48 and only put a .5 BCF of gas in it. So, what we proposed to the federal government was to come up with a different way to pay for that infrastructure to allow batching to occur and they recover their money at a later date. We actually looked at three different proposals with them and one is the federal motor fuels tax credit, which we don't particularly want to use, but it's one way to get it. If you take the example of gasohol, the ethanol gets 54 cents a gallon. It's been going on for 21 years and could possibly go on for another nine. The other way was to look at an environmental credit, which seems to be the way a lot of senators and congressmen that we've talked to on the federal level like to go. The third way that Senator Stevens suggested in one of our meetings was the possibility of a government pilot program where they pay for the infrastructure and they recover it as more GTL plants are built. The next issue I want to talk about briefly was - and here's where I think the problem with GTLs arises. When you talk about GTLs, we talk about FT, or Fisher/Trop, synthetic diesel and California has raised this point for the last couple of years with us. Nobody focuses on the Fisher/Trop synthetic part; they focus on the word diesel. As a result, when they look at that, they think diesel - petroleum products - and their mind is then fixed in this kind of a format. We found even with the majors, it's very difficult for them to think of anything else other than petroleum based product when you say diesel. So, we like to say, 'Is it diesel or is it a petroleum alternative liquid (PAL)?' The reason we do that is because we like to say, 'My PAL is clean and odorless. It is biodegradable and non-toxic. It has no sulfur, no aromatics. These are some of the environmental qualities synthetic fuel has. If you can get your mind off diesel, you can think about it different ways. Probably the biggest consideration is that this FT fluid is a natural gas based product. In our country we have two basic ways to tax motor fuels. One is a petroleum-based product and one is a natural gas based product. CNG, LNG is taxed at a natural gas base. Diesel gasoline is taxed as a petroleum base. Where we say this is important, if you go back into the motor fuels tax on diesel, the federal tax is 24.3 cents per gallon and in California it's 18 cents a gallon on diesel. If you look at the motor fuels tax on CNG, LNG, etc., the federal tax is 4.3 cents per gallon and in California the tax is roughly 7 cents per gallon. It's actually a range that goes up and down. So, if you look at those numbers, you say that if you think synthetic diesel from a GTL process is a natural gas based product, the current federal tax is $13 per barrel less. This means $13 per barrel higher netback to the gas supplier. There's a lot of other types of programs out there that if you get away from petroleum products and starting thinking about this as a natural gas product, it improves the economics of GTLs tremendously. You also have tests running in California right now for NOX reduction, which ranges between 12 - 15 cents a gallon. You have the ability to put in CNG avoidance premium. CNG requires massive capital upfront investment. To do it where it's PAL synthetic diesel does not require that. So, you use the same existing infrastructure. So, we like to say if you consider GTLs as a natural gas based product, you're going to have a situation with far more value than you have given it in the past. It needs consideration. But, the primary purpose for me being here is to talk about GTLs from Alaska. It's a pristine fuel from a pristine environment, but GTLs can help improve the economics of a gas pipeline. We believe that by going ahead with the GTL option on a small scale, putting in the batching facilities, you can put the NGL processing facility with the CO2 extraction facility on the North Slope and keep all of that work here…keep the value; batch that down to Valdez and maybe do something else with it at that location. 2:44 CHAIRMAN TORGERSON said he read something saying the federal government recognizes GTL as an alternative fuel and the tax proposals that are pending in congress have a 25 cent tax credit for GTLs or alternative fuels. MR. PETERSON responded: No, I wouldn't say that. The alternative fuels tax definition that was put in at the help of Congressman Young and Senator Stevens places GTLs into that status of alternative fuel. By being an alternative fuel, you make yourself available for clean cities programs and it just so happens that every single other alternative fuel has some sort of a tax subsidy etc. What we're saying is that GTLs are gas based. If you tax them based on a gas base only in the motor fuels market, in some states you have a 31-cent advantage for a higher netback (higher or lower in some states). MR. PETERSON commented if the boat that sank in Prince William Sound had been using PAL, this would have not been an issue. "PAL has been approved by the EPA as non-toxic, biodegradable, can be dumped into the ocean and you don't have to worry about cleaning it up. 2:50 ALASKA GASLINE PORT AUTHORITY CHAIRMAN TORGERSON announced a three-minute break before going to the Port Authority for the rest of their presentation [CONTINUED FROM THE LAST MEETING]. He said that Fairbanks is a part of the Port Authority concept, having placed that issue before the voters. The North Slope Borough and Valdez are also active members. MR. DAVE DENGLE, Interim Executive Director, Port Authority, said Mr. Rigdon Boykin, Special Counsel for the Port Authority, Mr. Burt Kodel, a board member, and Mr. Dave Cobb, Secretary were also present. He said that Charlie Cole was called away on a special assignment by the Governor and he would take up where Mr. Cole left off discussing some of the benefits of the Port Authority financing and tax exemption status and answering the committee's questions. MR. RIGDON BOYKIN, Special Counsel to the Port Authority, said: The first slide goes into the base case assumptions we used in our financial model. This is a model a great amount of detail of which we gave to you at the last hearing in Anchorage. I have selected a few slides from that to illustrate the base case used and what the results from that base case were. You may recall that the Port Authority model is based on a combination project of both the Foothills project and basically the YPC project, because we get a tremendous amount of economies of scale by combining both projects into one project along the common 550-mile corridor down to Delta Junction. Consequently, we're ending up putting 6 BCF into the pipeline. In order to do that, you need to process 8.7 BCF on the North Slope. We have assumed for the purpose of this model that the Port Authority would own and construct that conditioning plant on the North Slope. That may be quite a difference from some of the other models or theories that you've seen. From that 8.7 BCF, we will extract 2 BCF of CO2 and other elements. That will be returned to the producers for use as miscible injectant. We will actually buy, consequently, a little over 6.7 BCF of gas and we will pay for that gas a split payment, 30 cents base price and 45 cents, which will be an additional subordinated payment for the feed gas for a total price of 75 cents per million BTUs. We will produce 15 million tons of LNG. That will basically be three trains of five million tons each. Those trains will come on line at six-month intervals. I think the initial train will come on line 49 months after the start of construction. We have assumed a price for the LNG of $2.5 per million BTUs at Valdez. If that were shipped to Japan and the shipping were 60 cents, which we believe it would be at or less, that would equate to a delivered price in Japan of $3.10. We have assumed a $3 per million BTU Chicago price. Based in the assumption is $1.20 per million BTU assumed tariff for the Alaska border to Alberta to Chicago section of the line. As I mentioned earlier about 6 BCF will enter the line; approximately 2.7 BCF will go into the LNG plant in Valdez; and a little over 3 BCF will go down to Canada. This will be a dense phase, high-pressure line. That means we'll be carrying propane and butane down the line in a gaseous form. I cannot overstate the benefit of these liquids and the value of those liquids to the line in terms of amortizing the cost of all of these facilities. Eighty-one thousand barrels of NGLs will be extracted on the North Slope; 119,000 barrels of LPGs will be extracted in Valdez; 141,000 barrels of LPGs will be extracted from the gas that's going down to Canada. That will be extracted either in Calgary, our assumption is, or in Chicago if it ends up going down the Alliance Line to Chicago. We have assumed an LPG price of $12.50 per barrel and an NGL price of $16.50. We believe all of these numbers are relatively conservative. The benefits to the producers: basically they get $811 million from the gas sale at the base payment of 30 cents. They get another $1.2 billion from the subordinated gas payment of 45 cents per million BTUs for a total amount of just over $2 billion per year. The benefits to the state and municipalities of Alaska: $371 million per year in royalty and severance tax; $81 million per year in royalty and severance tax on the NGLs; $148 million per year if they're paying corporate income tax. (I don't know whether they're taxpayer or not due to consolidation, etc.). One hundred and fourteen million will be the payment in lieu of taxes to the municipalities along the route; that equates to approximately a 10 mill tax as opposed to the current 20 mill regime for the oil line. The project was designed to throw off $370 million per year, which would go $220 million to the state and $148 million to the municipalities; $111 million of that would be in the form of direct money based on a per capita allocation. The other $37 million would be used to lower energy costs for communities that could not readily access gas along the corridor. Because we're only paying 75 cents for the gas from the producers in this example and because we need a very healthy debt service coverage ratio, in this case it ends up being over two times debt service, we have a lot of excess cash that's generated by this project. Basically, it generates $1,750,000 of excess cash; of that $1.2 billion goes to the producers (that's the 45 cents subordinated payment); that leaves $532 million, which can be used to increase the netback for reserves, to accelerate debt payment, a whole host of different things including potentially building in incentives for whoever the operator of the pipeline etc. and the Port Authority might be. What I've done at the bottom of this is include a sensitivity table for the use of the committee. Basically, what that does is show you what happens if various things happen to the price of gas, to interest rates, price of NGLs, etc. So, basically, a 10 cent increase in the price of the gas will increase the amount of revenue by $200 million per year. A decrease in interest rates of .5 percent would increase the amount available by $120 million per year. An increase in the sales price of the NGLs and LPGs of $2.50 would increase the amount available by $300 million per year. A reduction in the EPC construction cost of $1 billion increases the amount available by $120 million per year. We thought it would be useful for you to have some kind of sensitivity, but I think what this also illustrates is that because of the $532 million per year cushion that we have, we could actually absorb and decrease in the sales price at the Chicago, for example, of about 20 cents and maybe more (40 cents) if the decrease is only on the Chicago price and not on the LNG side, as well. There has been a lot of discussion as to what the benefits of this Port Authority are and what difference would be if this were a private project versus a Port Authority project. What this slide is designed to show you that basically the private project would pay $516 million in taxes; the Port Authority doesn't pay those taxes. That money would be used to increase payments to other people or to pay debt or what-have-you. Also, you can because the Port Authority isn't paying taxes, its unlevered project return is 12.9 percent. For a private project, its 6.8 percent and that's only by decreasing the amount of payment to the producers to 69 cents as opposed to the 75 cents in the Port Authority case. This slide is basically one of a group of slides at the end of the financial presentation that we gave and the primary reason I wanted to put it up there was to give you an idea of the liquids in this project. In the third column second line, you can see that the liquids are producing approximately $1.5 billion of revenue per year. That's a lot of money. What I'd like to do if it's alright is start with the questions that were posed by the committee to the Port Authority. The first question deals with the benefits of the Port Authority concept and why is there a difference between what we're saying and what the producers (sponsor groups) are saying. We don't know why they don't believe this structure provides any benefits. We've had limited discussions with them; they have not had any significant discussion with us that would explain to us why this tax benefit has no value. We will give you where we see our value coming from. In the first place, we do not pay federal income taxes and money that would otherwise be used to pay those taxes can be used to pay debt and increased payments to stakeholders. We've just gone through the slide, which shows you the producers in our example of a two-project line would pay approximately $516 million in taxes; they can use that money to increase the netback to do other things that would be a benefit to the producers and the citizens of the State of Alaska. We have heard it said that if we gave all of that money that's the difference between the revenue that's generated by the Port Authority and the revenue that would be generated by a private individual to the producers, they would end up having to pay taxes on that money and they would be left in the same situation. That's not exactly true, because if they owned the pipeline, they would pay $516 million on the pipeline. If we gave them that $516 million, for example, they would only pay a tax of 35 percent roughly, not the entire $516 million. I don't understand that particular argument, at least. In addition, one thing you should know that the income taxes for a private project will increase over time as debt is paid, because of the increased debt payments, interest will not be a deduction and you're payment of taxes will increase. One of the biggest benefits of the Port Authority is that they are seeking a much lower return on the project than would be required by the sponsor of a private project. The return requested by the Port Authority is $370 million, which equates to a negative 2.6 percent. The return is negative because the $370 million doesn't start until five years out in the project. If you take into account the time value of money, it basically erodes the principle that you would end up recovering. Typically, a company like BP requires 14 - 15 percent unlevered return in order to invest in a project of this type. There is no way we believe they would get that kind of a return if they owned this project. Consequently, it becomes very difficult for a private company to build a project like this, we believe. The next benefit that we feel addresses a lot of this committee's concerns is the fact that the Port Authority project would be exempt from FERC regulation. This would give Alaska an ability to better control capacity, usage and rates. Some of the companies the Port Authority has talked to believe the FERC exemption could substantially increase their interest in the pipeline. Some of the debt could be financed with tax exempt bonds. The Port Authority believes that between $3 - $6 billion of debt can be financed with tax-exempt bonds depending on how the contracts for the sale of gas are structured. Tax-exempt bonds basically sell for 2 percent than taxable debt on average for a project like this. The project will not cost the producers any capital and will be non-recourse to the producers, the state or the Port Authority. This project will be project financed. That means that the banks will not lend money to the project unless they believe that the contracts which form the basis for this project - the contract for the construction of the project, the contract to buy the gas, the contracts to sell the gas, the operation contracts for whoever is operating the pipeline - all of those various contracts have got to be sufficiently precise that the banks will rely on them to lend the money required for this project. It's sort of a self policing mechanism, because if the contracts aren't good enough, you can't borrow the money. If they are good enough, you can borrow the money. There are also benefits to the State of Alaska. I mentioned earlier the $370 million; there's also much more certainty for gas for instate usage. The Port Authority will ensure that a spur line will be built to allow Anchorage, etc. access to the gas. The Port Authority can use retained earnings to develop LNG transport to other communities accessible by road or water. There's also more control over price to the consumer of instate gas usage - for example, gas to Anchorage or Fairbanks could be in the $1.80 per million BTU range. That's a little bit simplistic; the actual price will probably be over $1.80, because you'll have to add on the costs of tapping into the line and all of that kind of thing, but it shouldn't be substantially above that at the wholesale level. Although, probably a private entity might look at pricing that at the marginal cost of other fuels as opposed to just subtracting off what the transportation cost might be for the distance the gas didn't have to travel. There's no need to give up tax revenue, royalties, etc. to subsidize the project. We modeled this and found out that the benefits from the tax exemption substantially exceed the benefits, if they were given the maximum benefits permitted by HB 393. And if in addition to those benefits, you eliminated royalties, this benefit still exceeds that amount. The second question posed was the ability of the Authority to operate outside the municipal boundaries of the initial founders of the Port Authority. Basically, the short answer is that there's no limiting language in the enabling statutes that precludes the Port Authority from doing business or owning assets outside the boundaries of the member utilities. The only limitation is we do not have condemnation authority outside the boundaries of these communities, but within the boundaries we do have that authority. The third question deals with cost over runs with respect to the construction contract. First of all, the total contingency contained in our design and financial model for this project is $2.7 billion - $1.8 billion of contractors' contingency and $900 million of owner's contingency. Bechtel obtained two or three quotes for most of the equipment in their design study. A critical feature of this project is that it will be 100 percent financed on a project financed basis. In order to do that, the construction contract must be for a fixed price with a fixed delivery date and meet certain performance criteria. Failure to meet the performance criteria or delivery date will result in liquidated damages, which in this case can be quite substantial. Only a few companies in the world are capable of forming a consortium to take this kind of risk. Bechtel is one of them. Basically, the bottom line is that banks will not finance the project if the contract does not adequately address over run risk. If the project is late, does not meet performance criteria, or has over runs in excess of the contingencies, Bechtel and any partners it has in the project will be responsible if they end up being the contractor. The next question deals with the value of LPGs. I mentioned a little bit earlier that that value including the NGLs on the Slope amounts to about $1.5 billion per year. The gas that's produced on the North Slope contains a substantial amount of propane and butane; however, these liquids are too volatile to be transported in TAPS to Valdez. Consequently, over 100,000 barrels of these liquids are reinjected into wells on the North Slope every day. In the past, gas pipeline design and technology did not permit the transport of propane and butane. However, the new designs and technologies that are being proposed for the transportation of North Slope gas will enable the pipeline to transport propane and butane in a gaseous form. This propane and butane is very valuable as I mentioned earlier and depending on the sales price can generate sufficient revenue to basically pay for both the conditioning plant and pipeline. The propane and butane in the Lower 48 branch of the line will probably be extracted in Alberta or Chicago. If the instate consumption in Fairbanks and from the spur line to Anchorage is large enough, it might be economical to extract the propane and butane from that gas in the Fairbanks or Glennallen area. At the price of $12.50 per barrel, the LPG from the two branches of the line generates $3.25 million of revenue per day or about $1.1 billion per year. A price increase of $2.50 would add approximately $200 million of revenue per year. The fifth question, the committee heard testimony about the problem of dealing with FERC for sizing the line for instate gas usage. As I mentioned earlier, a Port Authority project would not be subject to FERC jurisdiction. In addition, the line would be owned by the Port Authority. Facilitating instate gas supply is part of the mission of the Port Authority. The line has been designed to supply up to 500 MCF/D of instate gas usage at relatively little incremental cost. If instate usage expands to a higher amount, the Port Authority has every incentive to add compression stations, etc. to enable increased delivery. The sixth question had to do with whether Bechtel reviewed the cost estimates for other routes including an over-the-top route. We've heard a lot of estimates for a lot of different projects. Most of the estimates don't specify what's comprised in the estimates. Do they include contingency money? Do they include the conditioning plant? Do they include working capital? Do they include a debt service reserve? So, it's very difficult to compare these projects, in fact, it's pretty much impossible. The only things we did do is when the arc numbers were first announced for the over-the-top route, we asked Bechtel to give us a back-of-the envelope estimate of the all end costs of a similar project and basically the conclusion we reached was that all the costs were not included in the arc numbers, because the difference in the numbers were very substantial. The next question deals with the CERA presentation; in particular, we focused on the answers to the questions that CERA gave in written form to this committee on July 17 of this year. The questions posed to CERA indicate an interest by the state to promote instate usage of gas for residential, industrial and petrochemical use and reserve in some fashion capacity on a line should a large demand develop in the future. There's also considerable interest in natural gas liquids that could be transported in a high-pressure dense phase line. On the whole, the CERA answers to the questions in these areas we felt were not very encouraging. However, the answers might be more favorable if the questions were not so limited in scope. Most of the question limit the answer to only a Lower 48 project or only an LNG project. It is almost as if there's a silent agreement to only talk about a Lower 48 pipeline with a possibility of a limited use spur line to carry liquids, for example, to tidewater or only an LNG line. The proverbial elephant sitting in the corner of the room - a combination of both an LNG and Lower 48 line - is ignored. Inclusion of this elephant in the questions might lead to more favorable answers to a number of issues critical to this committee and the citizens of this state. Basically, the two-project line will deliver 6 BCF along 550 miles to Delta Junction; then 3 BCF 156 miles to the Canadian border and 3 BCF 250 miles to Valdez. This concept should have more benefit than the 4 BCF minimum suggested in the answer to question 16 by CERA for a $15 billion pipeline. It also avoids having to take over 3 BCF through Canada, which some testimony in Anchorage indicates might be a problem. It enables the extraction of gas liquids in Valdez for export or instate use. The liquids in the economics of a larger size line to Delta Junction makes the LNG competitive in Asia especially when one considers security of supply issues and it gives Alaska LNG a very substantial competitive advantage over other LNG resources to delivery to the West Coast of the United States and Mexico. We've outlined in our statement a couple of examples of the effects of limited answers to limited questions. The first is CERA question 11 - capacity for instate gas use expansion. CERA discusses the problems and cost of expanding the use of instate gas only in the context of the Lower 48 project. In short, a concern is expressed that if the amount and timing of the expansion are not fairly predictable, the producers might design the pipeline to maximize delivery to the Lower 48. In such a case, use of the Alaskan portion of the line for instate gas could result in underutilization of the more distant parts of the line. A two-project line might afford a much greater degree of leeway, because the North Slope to Delta Junction portion of the line will be very large diameter pipe, 56 inches, to which adding more compression at existing stations will add substantial capacity at a relatively small incremental cost. Most instate usage is likely to occur at or above Delta Junction and along the Valdez branch of the line and, thus, should not affect the Lower 48 branch from Delta Junction, if instate usage is increased to as much as 500 MCF/D. CERA's question 6 asks how much gas needs to go through the line to make it economically viable and second whether there will be sufficient capacity in Canada to deliver that amount of gas to the American markets. CERA's answer is basically that a $15 billion pipeline will require at least a 4 BCF/D throughput and a Chicago price of $3 to offer a netback in the range of 74 - 95 cents per thousand cubic feet. However, testimony at the Anchorage hearing indicated that there may be Canadian resistance to permitting a throughput of over 2.5 - 3 BCF/D. Clearly, CERA recognizes that the larger the throughput for a green field pipe, the cheaper the gas is to transport on a per unit basis. A two-project line that splits at Delta Junction achieves these economies of scale. The main trunk line carrying 6 BCF to Delta Junction only requires 3 BCF to transit Canada, because the other 3 BCF goes to Valdez for delivery of LNG to Asia, the West Coast of the United State or Mexico. The CERA question 8 basically asks what changes would make a stand-alone Alaskan LNG project delivering its product to the Asian market economic. Here again, we agree with CERA. The possibility of a single project to Valdez just for LNG without the Y-line, probably at best is marginally economic. It's the Y-line, the combination of the two projects that makes the LNG economic, as well as the value of the liquids. CERA really didn't go into much analysis of the value of those liquids in terms of offsetting the cost of making the LNG in the pipeline. The CERA question 2 and 3, regarding petrochemical industry possibilities - basically, CERA's view is that the liquids to service a petrochemical industry would basically have to be delivered to a coastal location and instead of assuming this might be combined with an LNG branch of the line to Valdez, they assume that basically just a pipe would be put in to carry the liquids only to Valdez and they concluded that would be fairly uneconomic. They are probably right on that, but the combination with the LNG project, taking the liquids out, which will be from a very substantial volume of gas there, changes the equation and would probably change CERA's answer. Lastly, you've asked for our view of the Lower 48 and Canadian gas markets. We don't have a view of the Canadian gas market. We didn't do any research on that; we haven't asked any people to do research on that - other than to look at the issue of whether they thought Canada would permit large volumes of Alaskan gas to transit Canada. We do believe that Canada is not going to embrace the transit of gas through it to the United States, which may preclude or reduce their ability to market additional Canadian gas. Frankly, we think, were it not for ANGTA we would have a serious problem here. We do believe that if the Foothills project is implemented as part of this overall scheme, it would be pretty difficult for Canada to stop the transit of 2.5 BCF, at least, and probably 3 BCF. But we believe additional volumes will be very problematic. With respect to the Lower 48, the Port Authority believes this market as it relates to Alaskan gas is critical to both the Lower 48 line and LNG to the West Coast. Some of our research indicates that the sheer volume of new gas- fired electric generation has been planned over the next 4 - 5 years in the Lower 48 will substantially increase demand. Conversations with gas marketers in the United States indicate they have seen shortages in certain areas of the country over the next 4 - 5 years. This shortage is so serious that independent power producers are now integrating into the gas market because they believe that they may have a better ability to protect themselves against gas shortages if they go in and start buying gas reserves and perhaps building gas pipelines. A good example of this is the gas pipeline that Calpine, one of the leading independent power producers in the United States, has announced it's going to build in the California area. A number of companies have also stated to us that they are working on LNG regasification permitting issues with respect to a number of sites in California, as well as Mexico. We have also researched the Asian markets with respect to LNG. It is believed that demand in this market is largely dependent on three factors, which for the most part are all interrelated, because this market is rapidly becoming a global market. The factors are the pace of economic recovery in Asia, especially as it may be affected by the United States. Second, the pace of deregulation of the electricity and gas markets in Asia and the consequent growth of independent power producers, especially those that integrate into the fuel sector. And lastly, the growth of the Indian market and the [END OF TAPE]… TAPE 01-15, SIDE B MR. BOYKIN continued: The Indian market has the potential to absorb a very large amount of LNG over the next decade. I would note that recently a contract for 7.5 million tons per year was recently signed for an Indian project. It was announced not long ago. To give you an idea of scale, that represents basically 10 percent of the entire Asian demand in one swoop, roughly half of the 15 million tons that this project would produce in Valdez. We believe, based on the research that the Port Authority and its consultants have done, that the market is there for Alaskan gas, particularly at the prices set forth in our financial model. The Port Authority agrees with CERA that there's a window of opportunity now, but the Port Authority also believes it may be extremely difficult or a very long time before the window reopens for the size project that is required by the economics of an 800 mile pipeline through Alaska. As announcements to build lines, announcements of drilling discoveries in the Gulf of Mexico and off the coast of Canada, announcements for the LNG terminals in Mexico, the Bahamas and the West Coast of the United States, those announcements are not going to wait for Alaska to get its act together. All of these facilities require contracts for the sale of gas or LNG to get their financing. Many of these negotiations are taking place today. An example is the El Paso letter of intent to buy LNG for delivery on the west coast of Mexico from Phillips from a yet to be constructed facility in Australia. If this contract is realized, it takes away an opportunity to sell 5 million tons of LNG to a location, Mexico, where Alaskan LNG will have a substantial transportation cost advantage. The bottom line is there are two projects that are at least partially permitted. Endorsement of both of these projects by the Alaskan government may be the only way North Slope gas can meet this window. We believe this window is a lot shorter than most people believe; people are contracting for huge amounts of gas and LNG right now. It would be nice to have a perfect project, nice to have perfect legislation and perfect protection of Alaskan interests. I think if we wait for all of that, Alaska will miss the current window. 4:35 REPRESENTATIVE OGAN said he shares his frustrations watching the different projects. He would love to ship gas to Mexico. He asked how you get the producers to sell the gas. MR. BOYKIN responded: I think we stated in our earlier testimony that we have sort of given up on the producers doing something themselves in a short timeframe. We don't think that's probably going to happen. So, we've focused instead on trying to get big users of gas interested in putting something on the table for the producers up here. That means going to the Enrons of the world, the Dukes of the world, the El Pasos, etc. and try and get them interested in putting an offer on the table, because we believe without an offer on the table, it will be probably difficult if not impossible for the state to get the producers to do anything. But, if there is a bonafide offer from a credible player, such as an Enron, Duke or El Paso, or a consortium of those players, then it becomes very difficult for the producers to say, 'Hey, we're not building it and by the way we're not going to sell it to those guys either.' At that point in time they've got to decide, I think, either we will build it or we'll sell the gas to that consortium. I think it places a lot of pressure on something to happen. Whether that's a realistic goal, I don't know, but it's the only game in town that I see. REPRESENTATIVE OGAN agreed with that and said if there were any way to help, he would be glad to assist. MR. BOYKIN responded that there was something that could be done to assist that and that is: The state government needs to get together. These companies have come to us and said, 'Where's the state on this? Will the state support this? What's happening in the governor's office? What's happening at the legislature? Where is all of this? I think that whole effort would be helped immeasurably if there is sort of one unified stance within the state that would encourage this effort. CHAIRMAN TORGERSON asked why Enron, Duke or El Paso weren't here today to talk to them. "We haven't been hiding from them." MR. BOYKIN said he understood that, but he thought they had talked to individuals in the legislature and the state administration. They believe rightly or wrongly that they have been getting some conflicting messages. One sort of thought they were being told, 'Don't meddle in our business. We'll get this all squared away and the pipeline will be built by the producers eventually.' Whether that is an accurate view of what they were told or not is another question. REPRESENTATIVE OGAN noted the Duke was there, although they weren't testifying. He said they are producing Scotia gas and shipping it to the east coast and he thought it would be advantageous to get a presentation from them on some issues shipping from Canada into the U.S. He knew that El Paso had been at a meeting in the past. He had spent some time with them at a conference in Whistler a couple of weeks ago. He said that the Japanese and Pacific markets view us as dysfunctional because the governor says one thing, the legislature says something else. The governor does not want to consider LNG, but he thought with the two projects piggy backing on each other made the economies of scale possible. CHAIRMAN TORGERSON said he wasn't commenting about people physically being there taking notes, but proposals that are laying in front of them for review. MR. BOYKIN responded that he thought there were a number of companies doing the due diligence that is required to make such a proposal. CHAIRMAN TORGERSON responded that he understood that, but Mr. Boykin said that the legislature is not listening or talking to them. "They're not putting anything on the table…When they get their act together, they're welcome to sit where you are too, and tell us they want to buy a couple billion feet a day. An then there may be some action happen!" MR. BOYKIN replied that in putting their proposals together, they are making assessments now as to where the state stands and there is some concern that they can't determine that. "Perhaps they haven't been talking to the right people." CHAIRMAN TORGERSON said, "My guess is that it's happening in board rooms in the Lower 48 like the producers are doing. Decisions aren't necessarily made within this state. Do you agree with that?" MR. BOYKIN agreed. REPRESENTATIVE FATE explained how gas utilization was applied as a throughput LNG plant to Valdez, gas to Canada, etc. and extraction of LPGs, etc. He then went in to instate use and asked for a clearer picture: "If the state wanted to embark in a petrochemical industry, which is being driven offshore in the Lower 48, and fill that vacuum, how would you go about releasing enough gas for that industry without harming the throughput into the LNG plant or, for that matter, another spur to the Cook Inlet, which we all know is going to require some in about 12 years." MR. BOYKIN responded: The petrochemical industry that would probably best be put here, if that's what you wanted to do, would probably be based on propane or butane and that will be taken out at Valdez. So, it could be used very easily. REPRESENTATIVE FATE said he was talking cash back, not utilization of those by the state or any other part of the gas in state usage. MR. BOYKIN responded: The propane and butane that's produced in Valdez, whether it's used instate or out of state, the price should be the same for it. So, the economics of the project are not adversely affected. It just makes those liquids available there in Valdez without damaging the LNG at all, because the propane and butane would not be used to make the LNG. The plant is designed that way and everything. There's a possibility you could use some of the ethane, as well. We really didn't look at ethane; we basically only looked at the propane and butane and assumed that the ethane and methane would be sold as LNG. But, the line has been sized to also permit a substantial amount of gas for instate usage making ammonia, perhaps, as well as power generation or what have you at very minimal cost. REPRESENTATIVE FATE said he was speaking in generic terms and other presentations have a finite idea of what royalty gas, for an example, would be in instate usage. He didn't get that feeling from his presentation. "What was their requirement going to be at the LNG plant in Valdez?" MR. BOYKIN replied: The highest estimates we've heard so far for instate potential usage out into the future is .5 BCF/D. We believe we have designed that so that it can be delivered with minimal incremental cost. The liquids can also be used instate and it's immaterial to us whether they are used instate or out of state, because it doesn't affect any of our downstream operations. REPRESENTATIVE DAVIES asked if he knew what the sale price was for the 7.5 contract in India he referred to. MR. BOYKIN replied that he didn't know; he guessed that it was more of a commodity type price rather than a basket of oils, which is the historic way of pricing. He said there was an excellent report on LNG by Deutch Bank prepared in May that gives a very good background on what's going on in the LNG markets. CHAIRMAN TORGERSON thanked them for testifying today and said they would take a short break (3:47 - 3:50). 3:50 PRODUCER GROUPS CHAIRMAN TORGERSON said they would next have presentations from producer groups. MR. ROBBIE SCHILHAB, Alaska Gas Producers Pipeline, said Mr. Joe Marushack was with him and he had addressed them at the last meeting in Anchorage with Ken Conrad of BP. He said: Today, what I would like to do is address primarily the question that you sent to us, Senator Torgerson, to give an analysis of the proposed legislation. With that, let me start. Since July when we last met with you there's one thing I'd like to stay in the forefront, our team has continued to progress and work. We've got about 100 company employees and about 400 contract employees that are working through the engineering and environmental work we've talked about. Hopefully, in the near future, we'll be wrapping up a phase of that and be able to come back to you with some information on that on an interim basis. Thus far, our analysis indicates that a project is not economic. I think we've heard a lot of information that's related to that today. So, that's probably not a surprise. With that we continue to look at ways to develop and create an economic project. Because we have not found an economic project, obviously we've not made a decision on route either. Many of the issues that are being evaluated by the team include looking at the optimization around a pipe size, around the pressure, the volume that we could handle in the pipeline, construction techniques, both in the Beaufort and in the terrain going through the mountain passes through Alaska and into the Yukon area of Canada and then, finally, the route center lines which is critical for us to have that so we can continue to finish our environmental work. We're still targeting for the end of the year for both the engineering and the environmental work to be concluded and at some point, we'll then be able to come forward with maybe some more firm decisions. As I mentioned, my presentation today will really focus on the proposed federal enabling legislation that is summarized on the next page of the handout. In general terms, this proposed legislation seeks to enhance the existing FERC processes to provide a simpler, more efficient process for permitting an Alaska gas pipeline project or projects. Absent this legislation, parties wanting to build a pipeline could do so under the normal FERC process in 7(c) in the Natural Gas Act. This legislation creates a market driven expedited regulatory process for any viable Alaska pipeline project or projects. The project would still be subject to the FERC regulations including the fair and reasonable terms and provide for an open access consistent with the FERC rules. The project would be subject to all the environmental laws and regulations with an environmental impact statement completed within 18 months. It creates the Office of Federal Pipeline Director in the U.S. in the White House to coordinate all the related government activities and provides for timely judicial review. Finally, in summary, the legislation helps mitigate the uncertainty in the risk associated with what could be a protracted regulatory approval process for a high risk, high cost project. That's really the essence of the proposal. Before I go into the details of the proposed legislation, a commonly asked question is how does this relate to ANGTA. Let me go through a couple of points and then we can talk about them later. First, the proposed legislation does not alter ANGTA. ANGTA remains in place and a project can proceed under it. ANGTA is a specific statute for a specific project passed in the 70s where certain permits were given to specific parties, rights now held by Foothills and TransCanada. ANGTA is not something anyone can file under, only the holder of the permits can use it. I'd also like to point out that a lot has changed since ANGTA was passed 25 years ago. Relative to today's market, we have a deregulated gas market, which really has changed the pipeline industry. FERC has moved to a market driven climate, technologies have greatly changed, the modern environmental standards are higher than they were 25 years ago, and finally, ANGTA has obligations and liabilities that were probably appropriate at the time they were made 25 years ago that could be a significant drain or downside to a modern project. And finally, it's also not route neutral. Let me turn to the next slide. This is an outline of the contents of the sections of the proposed legislation. The essence of the bill is really contained in sections 5 - 9, so I'd like to just go through those five sections and give you some of the background behind them. First, under section 5, FERC would be required to issue a certificate for the Alaska portion of a pipeline to Alberta if three criteria are satisfied. First, the applicant must have reached an agreement with a shipper of Alaska natural gas for the transportation of that gas with the intent that all or a portion of that gas ultimately be delivered to the Lower 48 states. Second, that FERC is satisfied with the shipping rates and terms and conditions including access. Third, that FERC is satisfied that the project will comply with all applicable environmental laws. FERC would be directed to act within 18 months of receiving an application. And finally, FERC may issue a certificate for an Alberta to the Lower 48, what we all B to C, segment by following their normal FERC procedures. So, in effect, this bill separates the two large segments, the Prudhoe Bay to Alberta and then Alberta into the Lower 48 markets. The next page discusses section 6, which requires separate environmental impact statements for the Alaska to Alberta segments and for Alberta to the Lower 48. It designates FERC as the lead agency for both segments. It sets the deadline for completing the draft environmental impact statement to within 12 months of the filing of the completed FERC certificate application and the final environmental impact statement within 18 months. It requires consistency between the scope of the EIS and the scope of the FERC certificate application. This means that the EIS would focus FERC's jurisdiction on the U.S. portion and the Canadian's portion would be reviewed by the Canadian agencies, which is consistent with FERC's purview today. Section 7 on the next page would establish the Office of Federal Pipeline Director. The director would be appointed by the President and confirmed by the U.S. Senate. The responsibilities of the Federal Pipeline Director include coordinating the expeditious discharge of all federal agency activities on Alaska gas projects including all environmental and other studies. This role includes the coordination with federal, state, local and tribal agencies as well as coordination with the Canadian agencies. This section authorizes the funding and requires regular reporting to the U.S. Congress. Section 8 directs the federal agencies to expedite their handling of all Alaska gas project actions. It requires the federal agencies to cooperate and coordinate with one another to expedite the decision making process doing this through MOU's, joint documents, joint meetings or the like. It prevents federal agencies from including discretionary terms in the permits if the federal pipeline director finds that such terms would prevent or impair the expeditious completion of an economically viable and environmentally sound system. Finally, under section 9, challenges to the action of the federal agencies or officers under this act must be brought forward within 60 days of such actions. Challenges would be brought directly to the D.C. Court of Appeals, with the court directed to provide expedited consideration of these. The judicial review would be limited to claims of constitutionality and statutory authority of FERC. So, in summary the enabling legislation has five keys: to provide for expedited review and approval of the applications, it authorizes the appointment of a federal director, expedites the resolution of disputes, focuses on the North Slope to Alberta segment, and specifies FERC as the lead agency. The proposed legislation is an essential step to the market based effort to bring Alaska gas to consumers in a manner consistent with today's environmental standards. We see this legislation as a positive step to expedite getting Alaska gas to market and we hope you see it the same way and will support the legislation. Before I close, let me address two other questions that you had in your letter. First, in the area of Canadian legislation, we have not proposed any legislative changes in Canada, nor do we see a need to do so. We don't see the need for that forthcoming. Finally, in the handouts of the last meeting, we had included a commercial issue on gas valuation for royalty and taxes and I think we heard some of the testimony earlier about that. At this time, we do not have a specific proposal to offer up. Again, what we're trying to do is initiate some discussion around this so we can start identifying the issues that would then lead to specific proposals. That concludes my prepared remarks. MR. MARUSHACK, Alaska Gas Producers Pipeline Team, said it's important to talk about his enabling legislation. He said: If you recall, the three companies came together under an MOU in December. It took us a while to get there because the companies had different views, but a project like this requires huge assets and huge commitments and it made sense to come together. In February, I believe, we met with both the legislative hearings and in it we said, 'Here's where we're going and here's what our timetable is; here's what we're trying to do.' The legislature came back and said, 'What can we do to help?' and our statement at the time says, 'Please let us do our work. Let us figure out what we've got. Let me see if we've got an economic project. Please just let us do our work. We'll be back when we need help.' So far we've been on our plan; we're on our timeline to do all our engineering work, figure out if we have an economic project, make route decisions by the end of the year. We're starting to get more and more engaged with the state on the fiscal plans, on the tax requirements, on setting up what is the wellhead value as well as trying to get more information out now, now that we're getting some information, out to groups such as yourself. Currently, we have a very tight thin project. Even as we work the economics and work the technology, it's going to remain tight. So, what does that cause us to do? That means we have to reduce the uncertainty. So, we're focusing on technical aspects and now we're moving into how do we reduce that uncertainty. The risks are associated with the market and the costs. The costs, we can work that ourselves; the market, we have no control over, although every company will do its own marketing and there are different things you can do there. But, timing is also an extremely important issue. Our plan is to systematically address how we reduce risk and improve the economics. The first step is to address timing issues and permitting issues. What we're trying to do with this enabling legislation is achieve a known and as rapid response as possible. We are going to apply and make a modern EIS; there's no shortcuts; there's nothing in here that we think is damaging. In fact, we think it ought to be very much supported by Alaska. It is route neutral at this point in time. There is no question about that and we understand there is an issue there. However, I do not see any way that we do a project eventually without the state supporting in anyway. So yes, it's route neutral; we don't know which way we're going to be going yet; we do not as a team spending all this money, we don't know the technical aspects well enough of the Beaufort Sea versus the South, yet to make that decision. What the proposal does, it works for any pipeline - ours, others, Foothills. It doesn't affect ANGTS; it could still be used by any party that wanted to use the ANGTS proposal. It does not affect state control of the gas resource, of native rights, of subsistence, and I don't know why I'm saying this other than I'm getting feedback from our team that there's been all these claims out there. It doesn't affect any of those things, which brings me quickly to the start. You asked what the legislature could do to help us move this project along. This is the first time we asked for help. It's difficult to see how any project can go forward without the state's support and without this enabling legislation. We think it's good for the project; it's good for Alaska. It improves our chances of success and we can get this enabling legislation done, but I think it's going to require help from Alaska to see it done. With that I'm ready to respond to questions. CHAIRMAN TORGERSON said he appreciated them talking to the committee. Our own John Katz and Robert Loeffler don't agree with your assertion that this has nothing to do with enabling '77 legislation…I just read you the basically three things. One, is it could be seen as an alternative to the 1976 with respect to the southern route because it takes some of the provisions of that - the limited judicial review and some others - and applies it to any route. The amendments would give the applicant the control of the gas a significant leg up in a modified FERC application process, which you're asking for that to happen. The other comment that he made is what the enabling amendments do, for example, with respect to the northern route, would be to apply the expedite process to that route and possibly to the same expedited project would be applied under that amendment to the southern, or in the case of Foothills, using the expedited process to ANGTA. So, clearly the two sides don't necessarily agree and we'll hear from Foothills next to see what they say. I just make that as a statement; if you want to respond, you can. MR. MARUSHACK responded: I think the first one; you're right on the southern route. It is potentially something different rather than being ANGTA. That's a clear statement; hopefully that came out in here. It works for both north and south. On your third statement: yes, it would provide enabling legislation for the north. On the second statement, though, I don't buy into that one. We worked the language for several months and tried to come up with something that we thought was palatable to all the parties out there. We're not in love with all the language. People think there's something in there that precludes someone else from being able to use that. We're open to working on that. In fact, we expected that there would be changes made to the language. It's just a matter if I write it, it's going to have one thing, if you do, it's going to have another. But, the provision was never to give the guys who owned the gas a leg up other than to say right now we're the guys trying to do the project. We're also trying to do a pipeline and we believe it allows us to get some sort of certainty and clarity in that permitting and time process, but if there's something in there that looks like it doesn't work other pipelines, that wasn't the intent. CHAIRMAN TORGERSON said the committee had not had a chance to debate the issue, but they plan on having a meeting in mid- September on the legislation. "…We hope to work that with the administration so that we'll have a unified voice when we go back, if Senator Murkowski is successful in getting hearings before the committee, but we haven't had a chance, yet. What you'll hear now will be individual remarks on it." 5:10 REPRESENTATIVE FATE had two questions based on things he saw under current analysis, which indicates the project is not economic. It says that they are still targeting the end of the year for engineering studies. He asked when they first testified, they had a project that cost $10 - $12 billion and then "all of a sudden it goes up to $15 - $20 billion without the engineering completion and now I see here that it is not economic, at least at this point your analysis says that. How did we ever arrive at these figures at this late date?" MR. SCHILHAB answered: Let me address that because the danger there is numbers and we heard it earlier today. Numbers come out and you really have to understand what's in the numbers. Earlier, when we talked a $10 - $12 billion project, those numbers weren't including a gas treatment plant, NGL plant; it may not have even included some of the lines all the way into the Lower 48 and some of the development costs. We talk about a higher cost and it really includes a ringed fence around the entire project. Unfortunately, as we start talking about these other numbers, we really need to be explaining that these aren't any different because we really are working off the preliminary numbers that we were sitting down and talking with you in the April timeframe. We're starting to refine some of those numbers, but a lot of that is around adding or taking away compressor stations, doing some modification to the gas treating plant or getting a little bit firmer numbers through the engineering. Those numbers still haven't been modified. Those are the numbers that we really feel like that by the end of the year we will have modified and then be able to look and make a decision of whether there's an economic project. In today's terms it's really not too much different than it was in the spring when we, again, didn't have an economic project that we felt was robust and we could go out and start sanctioning and move forward. I would think that by the end of year before the end of the year, we're going to be in that position of where we can do that. REPRESENTATIVE FATE said he hope as they refined their figures that it would lower and become economic. MR. MARUSCHACK said that was their hope, too. Just to be clear. The reason that Ken mentioned the $15 - $20 million last time is because people are out there with all sorts of numbers and we talk that number, we're talking about the gas treatment plant, the pipeline all the way to the Alaskan border, a brand new pipeline all the way to Chicago and the NGL system. So, that's a fully integrated project that has all the pieces in it and there's a lot of things we're trying to do in order to make that more economic. One of the things we can do is address timing uncertainties and that's part of the legislative enabling action that we're looking for. REPRESENTATIVE FATE said he had one more question: The next page over says that enabling legislation would be market driven, expedited regulatory process for any viable project, then under that it says it's subject to FERC regulation, fair and reasonable terms, open access, which leads me to another question. If one of these third parties, and we've mentioned Enron and Williams and Foothills. If one of these third parties came to you and said I'm ready to buy your gas and I'll buy it at the wellhead that gives you a heck of a profit. Would you sell that gas? MR. MARUSHACK replied, "We do things like that all the time, Representative Fate. Most of our gas is sold at the wellhead, so that would not be unusual." REPRESETNATIVE FATE said that was a hypothetical answer and asked if he wanted to build a pipeline and own the gas and build a pipeline or would he sell to some other project group? MR. SCHILHAB answered: What you're getting into is the individual companies as opposed to a joint project team. A joint project team is together to try to come up with the lowest cost solution to get gas to market so that we can sell it. If somebody came in with an alternative and had a better mousetrap that would be lower than something we have on paper that we're looking at, I think the answer is yes. As long as you felt like they would control it, they were going to maintain that at that lower cost and they had the backing to ensure a high degree of confidence that it was going to get built. If somebody came to you that you never heard of, that you don't know whether or not they really understand the pipeline business at all and said they were willing to buy your gas, you would probably think twice. Because what you're trying to do is market that gas at the best price, lowest cost to market so that we can compete and compete against all these other alternatives that are going to be in the market place. REPRESENTATIVE FATE said the parties he was thinking of certainly qualify under the criteria he presented. CHAIRMAN TORGERSON asked if anyone had made an offer to buy the gas on the North Slope, like Duke or Enron? MR. SHCILHAB answered that to his knowledge no one has made an offer to Exxon Mobil. MR. MARSHACK said: A proposal is a difficult thing to say. Let me tell you what has happened and then you can interpret that. We talk with marketers all the time. We talk to the ones you're talking about, we talk to other ones. We have talked about his project, too. We have talked about the possibility of long term fixed, we've talked about the possibility of spot, we've talked about buying it at the wellhead, down in the Chicago, all these other places. We have not done any firm deals on it, yet, and there's a whole myriad of reasons for that. It really gets into anybody has got the same dilemma that we've got right now. But we're exploring all those sorts of things. Do we have a bonafide offer on the table, but could you sign a contract? No. REPRESENTATIVE OGAN said he wanted to talk about the congressional statement of purpose in section 3. "It looks to me like subsection (a) they are relying on competitive market forces to determine which set system or systems can be built and operated in an economically viable manner." He said it sounds to him like an end run around a law the legislature passed last year saying the only thing that's legal is an Alaska Highway route. He asked if he was wrong. MR. SCHILHAB answered: I don't think the intent was to fly back in the face of the state. The intent was to try to get legislation that would allow a project to go forward. That's through this legislation or to have just an open market driven type process that would allow a project that's economic to move forward and compete with other projects. If other projects want to move forward, there's competition and the one that's going to be the strongest will probably get built. REPRESENTATIVE OGAN said if the northern route is the one that's economic, and it's in the federal law that this is what happens, that could supercede state law and they could build the northern route. He asked if that's what this legislation would do. MR. SCHILHAB responded: As I mentioned earlier, before a project is going to get built, there's going to have to be full support from the state that they would want the project to go forward. That would be a northern route, a southern route, whatever that project is. At that time, they would have to address legislation or other rules that are there. There will be other things we'll have to work out. We'll have to change the field rules. MR. MARUSCHACK interrupted: Representative Ogan, the intent was not to specifically find some way of getting around the state 164. The procedure is route neutral right now. That was not our primary…We weren't trying to take a hammer to 164. REPRESENTATIVE OGAN said he was confused and asked if the federal legislation, as written, enabled them to build a northern route. MR. SCHILHAB said, "It doesn't preclude it." TAPE 01-16, SIDE A 4:19 [THE FOLLOWING 14 MINUTES OF TRANSCRIPT WERE DONE MOSTLY WITH THE HELP OF NOTES, BECAUSE OF RECORDING DIFFICULTIES] REPRESENTATIVE OGAN said he was glad to hear that, because the state doesn't support the northern route. CHAIRMAN TORGERSON said he wasn't sure there wasn't another barrier with Representative Young's amendment. "You're not going to get them both in the same bill." SENATOR KELLY asked what their assumptions were for pricing. MR. SCHILHAB replied that it wasn't the same as CERA's testimony. They used an interest free number. CHAIRMAN TOGERSON asked what the timeline was on these projects. MR. SCHILHAB replied that they are still committed to finishing the interior and environmental studies by the end of the year. MR. MARUSHACK replied that to do the work they needed to do and have an open season so people could try to respond to it, and then do a filing pushed them back three months. "There will not be a hard yes or no on this thing. I hope that we will see continued progress to try to get this thing on line…decade." REPRESENTATIVE OGAN said their legislation seems to preclude any LNG project that specifically addressed gas to the Lower 48 and asked if they would consider adding LNG to it. MR. MARUSHACK said he didn't think it was necessary… There were continued questions from Representative Davies and Ogan, with answers from Mr. Schilhab and Marushack. 4:34 [TAPE RESUMES] FOOTHILLS PIPE LINES LTD. MR. ELLWOOD, Vice President, Engineering and Operations, Foothills Pipe Lines Ltd., said: FERC had no preference for receiving an application under NGA or under ANGTA and while that may be so, I think the truth is that there is no provision in ANGTA for anyone to apply for a certificate of public convenience and necessity. That statute is specific to the ANGTS project and can be used in the same way the Natural Gas Act can be used. Turning, then, to the proposed legislation, we have had a look at this and we have reached the conclusion that legislation of this type is required. It is not needed to provide the legal and regulatory framework to expedite the construction and operation of an Alaskan natural gas pipeline. That legal and regulatory authority or framework already exists in the Alaska Natural Gas Transportation Act (ANGTA) and the proposed producer legislation in our view contradicts the very purpose of ANGTA. If enacted, it's our view that it would create a very chaotic and confusing parallel procedure for authorization of a natural gas pipeline from Alaska. Clearing up that very confusion and chaos was the very purpose of ANGTA in 1977. We believe that the enactment of that producer legislation as drafted would be justified only if congress desired to accomplish two objectives. One of those would be if congress desires to revisit the previous careful and deliberative selection of the Alaska Highway route as the most economical and environmentally sound route and if congress desired to allow for consideration of other routes including the over-the-top. The second provision would be that this might be the kind of legislation one would enact if you wanted to authorize a filing of new producer sanctioned applications that could exclude any independent pipeline participation in the ownership and the governance of the Alaska pipeline. Our evidence to support those conclusions is found in the legislation itself, in that each of the major provisions designed to expedite construction and operation of the pipeline is copied almost directly from the existing law, the ANGTA. As you are aware, ANGTA engaged the regulatory expertise of the federal agencies, the international expertise and jurisdiction of the president and the public decision making process of congress before selecting the route and the project to deliver Alaska gas to the Lower 48. In contrast, this legislation would appear to place responsibility for those critical judgments in the hands of the North Slope gas producers. In our view, this raises profound public policy issues, not only for congress, but also for natural gas consumers and for Alaskans. Finally, we would note that the proposed legislation is not needed because the parties already authorized to construct and operate the Alaska Natural Gas Transportation System, that is ourselves, Foothills, TransCanada and West Coast, we are ready willing and able to build that pipeline as soon as the producers decide to market their gas. In this regard, Foothills continues to explore avenues to establish a collaborative dialogue with the ANS producer group and we urge this committee and through it the legislature to publicly encourage all stake holders to initiate some real and substantive collaboration and discussion regarding the proposed Alaska Natural Gas Pipeline. One more issue that I would like to comment on here - there's been a suggestion from time to time that proceeding under ANGTA is some how a way to shortcut the environmental process or circumvent it or fail to proceed in an environmentally sound manner. I want to assure you that in our view that is absolutely false. Proceeding under ANGTA will provide the same degree of environmental protection as under any other statute. The laws of the country are the laws and we will obey them; we will meet or exceed all standards. I would like to say a few words about the withdrawn partner issue. I'll be very, very brief here. We just want to inform the committee that the remaining partners in the Alaska partnership - the ANNGTC (Foothills and TransCanada Pipe Lines) - we are making progress towards eliminating any potential future contingent liability to the withdrawn partners. Discussions with the withdrawn partners have commenced and although the specifics of the matter is being discussed, it must remain confidential until resolution is achieved. We do fully expect that these discussions will lead to removal of issues that are perceived to impede implementation of this project. Finally, I would like to say a few words about where we stand relative to the Mackenzie Valley project and how we see both Alaska gas and Mackenzie Delta gas being developed. Firstly, we are strongly of the view that the market can absorb production from both Alaska and the Mackenzie Delta. We have publicly advocated a two- pipeline approach. In our view it is important to acknowledge that the long-standing concern of the government of Canada about possible stranding of Mackenzie Delta reserves. That is an issue for our government; we think it is a legitimate issue for them to consider and we are trying to address their concern. From a historical perspective, that's the same concern that existed when ANGTA was passed. In the context of a recent question on how to expedite that Mackenzie development, shareholders of Foothills have suggested to the Canadian officials that they focus on a stand alone Mackenzie Delta project, separate it from any combining or over- the-top route. Similarly, we would urge Alaskans to focus on committing to get the Alaska gas to market and we believe that the way forward here is for Alaska to endorse ANGTA and the ANGTA process and openly support the Alaska Natural Gas Transportation System. That's the end of my non-controversial remarks. CHAIRMAN TORGERSON said, "You kept it pretty clean. I have to give you credit." REPRESENTATIVE DAVIES said the previous group testified that they had discussions with a number of independent pipeliners and asked if that included Foothills. MR. ELLWOOD answered yes, they are talking with the North Slope producer group and they intend to continue that. REPRESENTATIVE DAVIES said they also heard from them that there is no bonafide offer on the table that one could sign tomorrow if the sanctions were given and asked why that was the case. MR. ELLWOOD replied: I believe that discussion was in the context of an offer to purchase their gas and that's not our business. We are transporters of gas, not purchasers. So, we would not put an offer forward to buy gas. Marketers will do that or end users might do that. But we are the trucking company of the gas business and we don't own the goods that are in our truck. To put forward an offer, to jointly develop such a project is a long and complicated process and is not something that we could envision putting forward an offer that they could simply sign. We need to understand their objectives, where the markets are and all these matters, which are a matter of some lengthy discussion between the parties before a commercial deal could be written up on paper. REPRESENTATIVE DAVIES asked, "But if you're a trucking outfit, can't you give them your tariff?" MR. ELLWOOD answered: The tariff is one thing, but the toll when you don't know how far you want the goods to travel is a different matter, or what volume of goods. All of those matters are of crucial importance, of course, to the producers and that just needs to be worked out over some time. REPRESENTATIVE DAVIES asked if they were basically a by-stander in the process? MR. ELLWOOD answered: No, I don't think that we're a by-stander. We're an active participant here. We are in discussion with the producer group. We are in discussions with marketing companies, with end users, to see where and how the various parties could come together and what that commercial arrangement might look like. CHAIRMAN TORGERSON said he wanted Mr. Ellwood to talk a little more about the Mackenzie Delta reserves, because they are competing projects and he didn't disagree with his assertion that they should be looking at two, but he is in the camp that the first one ready to go is going to be the winner and the other may be stranded for a few years. Clearly, you said from the historical perspective, they recognized that in the '77 law when they put the Dempster lateral in as part of that, but now we're suggesting not to do that and have two stand alone projects. What's their timeline for moving Mackenzie Delta versus what you think you think our timeline is in Alaska? MR. ELLWOOD replied: I only know what we read in the papers about the timeline for the Delta producers and that's quite vague. They are in a similar position as producers are here. They have a study group; they are looking at what the economics of the project might be. Our shareholders have their own view of that matter and I have seen some of their numbers that suggest that it would be economic. With respect to the stranding issue and which one goes first, most of the discussion that I have heard to date would center around a flow of gas from the Mackenzie Delta between 800 MCF/D and 1.5 BCF/D, which is a very small quantity to absorb in the market. I think we heard from CERA today that they are expecting the market to grow about 1.5 BCF/D. So, that's half enough to perhaps fit the growth in the market next year and, in my view, would not strand Alaska gas at all. Likewise, I think the market growth in the timeframe in which one can do these fairly large projects is such that if Alaska gas were to reach the market first, the Mackenzie Delta gas would not be stranded either by the time we could get that project to go, by "we" I mean the industry, there would be room in the market for it as well. CHAIRMAN TORGERSON commented that he had mentioned to some of his staff that the withdrawn partners is a bigger issue than he thinks from what he heard back in congress. Foothills has a $4 billion price tag on it before they even start throwing dirt around. So, it is a major issue and they all seem to be vaguely familiar with the withdrawn partners and the debt that has accumulated over a period of time. Somebody suggested that's the conspiracy theory going with the producers; they've run around flopping this rumor all over the capital, but at any degree, it's all over and you need to, I believe at least, get this thing settled so you, once and for all, come up with a number of what it's worth or where you're starting from or what you have to offer for sale, besides the $4 billion. The other one is, and I think you heard the remark that the committee is going to be looking at this legislation soon and I'd like to request that you give us a little bit more detail, section by section, if you would, on your remarks about if it's an identical section to ANGTA, if you would reference that section and just some general remarks about what you think those particular sections do and I hope to get that from the producers and then sit us all down and work through this a little bit at a time. We'll be dealing section by section when we go through this and word by word, more than likely… REPRESENTATIVE DAVIES said they also heard that the producers' legislation could be passed and leave ANGTA entirely in tact. "Assuming that were to happen and that a project were to go forward under that new legislation, it seems that you would be in the position where a considerable grant of privilege will have gone by you. Do we then get into protracted court battles?" MR. ELLWOOD replied, "That's one possible outcome, yes." CHAIRMAN TORGERSON asked if they had similar issues surfacing with the NEB (National Energy Board) that we do with FERC on the treaty or on any of the access questions or things that we have been wrestling with our regulatory commissions. MR. ELLWOOD answered: To my knowledge, Mr. Chairman, our National Energy Board has not really indicated whether they believe that they could hear an application under the National Energy Board Act as opposed to the Northern Pipeline Act. I know that they are asking themselves that question and it may come forward as it has with the FERC. I don't know their answer at this stage. REPRESENTATIVE FATE asked if he had any idea of what state of development the Mackenzie field is and off shore of that? He has heard that they are not ready to transport that gas out, because they aren't in the state of development that Prudhoe Bay is. MR. ELLWOOD replied: That's clearly the case. There has been some exploration done in the Mackenzie Delta. There was one well drilled this winter. Prior to that, all of the exploration had been done 15 - 25 years ago, somewhere in that timeframe. There is some uncertainty and different numbers floating around as to what is the size of the reserve - somewhere between 6 - 9 TCF as opposed to 35 TCF proven for the North Slope area. There is one small bit of production in the Mackenzie Delta right now. There is one well that is in production and is delivering gas through a very small pipeline a few miles into the town of Inuvik, but there's no real production facilities of the scale that would support a pipeline as there is on the North Slope. So, in terms of the infrastructure that will be needed there, the North Slope is clearly more developed than the Mackenzie is right now. REPRESENTATIVE FATE said: "As a comment for those of you who hadn't seen his picture, he makes a very good director of the FBI." 4:52 CHAIRMAN TORGERSON thanked Mr. Ellwood for joining them and announced they would take a short break before calling the committee meeting to order in which they would cover their brief agenda. 5:00 JOINT GAS PIPELINES COMMITTEE MEETING CHAIRMAN TORGERSON called the Joint Pipeline Committee meeting to order. The first item is a discussion of the official protocol trip that is next Monday and to get that information disseminated to everyone. The rest is to set dates for the next two meetings - one for the draft sponsors' legislation and the other one for the next regular meeting and then general discussion on the schedule. MS. RONDA THOMPSON, Special Assistant on International Trade Policy for the Alaska Legislature, asked them to look through the itinerary she gave them for the Western Canadian Protocol Mission on August 20 - 25, 2001. CHAIRMAN TORGERSON thanked her for all her work and discussed the committee's agenda. RERPESENTATIVE DAVIES said there was a letter from Commissioner Pourchot and asked what was the process for coordinating with the Governor's Office for a united front on this issue. CHAIRMAN TORGERSON said the Policy Council is meeting in Anchorage on August 17. He had asked Foothills, the producers and John Katz for a side by side sectional analysis so they could see where the real conflicts are and, at this point, will have to invite the administration to be there. John Katz and Bob Loeffler would be there. REPRESENTATIVE DAVIES said it would be helpful to have the Governor designate someone to be at that meeting. CHAIRMAN TORGERSON said he thought it would be good to have a meeting on the same day as the Council since he thought they would be taking up the same issue, although their functions are different. He said that he firmly believes Alaska needs a unified front. PUBLIC TESTIMONY MS. KARA MORIARTY, President and CEO, Fairbanks Chamber of Commerce, thanked them for having their second meeting in Fairbanks. She said: Commercialization of our natural gas resources is a massive undertaking. As we have heard for the past two days and as we heard in Anchorage as I attended those meetings, this project is very much a work in progress. Our chamber put together a gas line committee about nine months ago to begin the process of learning and understanding the dynamics involved with this project. Obviously, it's a lot for community volunteers to get their arms around, but our goal is to be able to communicate with all the parties involved including your committee to be able to make sure the needs of our community and state are met. As the committee has met over the past several months, we have definitely learned two things. One, we have lots more to learn and two, all Alaskans need to work together on this project. The chamber sees much potential and benefit for our community with the development of this resource and we just wanted to stress publicly and on the record our willingness to work together with all involved that this project comes together… MR. GORDIE LEWIS, Golden Valley Electric Association, said they are a cooperative serving over 90,000 interior Alaskan citizens and they fully appreciate the value and importance of open public participation. He assured the committee that they, "stand ready to provide the power necessary for any potential future opportunities throughout the construction, operation and maintenance life cycle of this most important and far reaching initiative." He said further that: We're convinced that this project must be integrated into a state sponsored 50-year long range energy plan that creates the vision and goals for addressing the state's energy needs and use of our resources for the next 50- years. Such a plan should at a minimum should direct free and open access to gas as stipulated in 18 CFR, governing U.S. gas transmission infrastructure, create common carrier status under a State Certificate of Public Convenience, insure access to state gas royalties in- kind, which provides a real and lasting price point benefit for state residents, develop a price for royalty gas used in state and designate royalty gas proceeds for the creation of a state energy fund charter that insures future development of renewable energy supplies. Fairbanks already has the infrastructure and trained and ready workforce needed for such an undertaking and such routing in turn makes the possible establishment of a Fairbanks-based gas hub a reality. This hub with ready and easy access to cost competitive fuel can serve as a cornerstone of renewed economic development creating opportunities for new industrial, commercial and personal value adding enterprises. Ready access to this most efficient and cleaner burning fuel, when added to our current energy mix at Golden Valley will help us demonstrate responsible, responsive leadership in meeting increasingly stringent air quality standards while supporting an on-going responsibility of serving today's citizenry while meeting the future needs of the interior. Your crucial and timely decisions will ensure that all involved are remembered as visionaries and leaders that responded to this moment in history. With business and government working together, we can develop a plan that results in a more robust and diversified economy that insures current and future generations the ability to continue to live and work in our great land. MR. PAUL METZ, Department of Mining and Geological Engineering, UAF, said that he was testifying on his own behalf. He said: The economic analysis of mineral and energy projects is very sensitive to the quantities of the resources and the commodity prices, as you all know. We're dealing here with an energy resource that there's considerable substitutability for, and therefore, the prediction of prices over the expected life of this project is a monumental task. We've seen how volatile the prices of energy commodities have been over the last year and projecting that over a 20-year life makes it a very great challenging to the engineers and economists dealing with this problem. As important as price is the quantity of the commodities and we've heard a lot about the 30 - 35 TCF of proven reserves on the Arctic Slope of Alaska. These proven reserves have been found without the expenditure of a dollar of exploration dollars for gas. This is a byproduct of oil exploration and development. I think this is very significant. What we haven't heard over the last couple of the days are the producer's projections that there's an additional 60 - 65 TCF to be discovered once there is an economic incentive to do exploration for gas on the North Slope. This brings the sum total to 100 TCF, plus or minus. Again, what we haven't heard in either the discussion today or in the debate with respect to ANWR is the quantity of gas that the U.S. Geological Survey estimate in the coastal plain of ANWR. This again is based on limited drilling data and limited seismic work that has been done many years ago. Again, the best median estimates of both the U.S.G.S. and State Geological Survey are 60 - 65 TCF. This brings the sum total of the resource on the Slope to 165 - 170 TCF, which is equivalent to all the natural gas in the United States in the form of proven reserves. I think this is really an important issue, both with respect to the economic analysis of the project, the various routes, and of course with respect to the decisions on royalty and pricing issues, but also with respect to the debate on the opening of ANWR for development. I encourage the committee here to examine that. Those are conventional gas reserves. The unconventional gas reserves on the North Slope are much, much larger. The Chair very pointedly made some important comments at the Chamber meeting yesterday with respect to competing resources in Canada, particularly in Alberta. The total gas resources of Canada exceed 500 TCF, which is extremely large [END OF TAPE]. TAPE 01-16, SIDE B MR. METZ continued: Those resources are relatively small compared to the other energy resources in Alberta, though, and I would encourage you to look at those on your visit there. There's 300 billion barrels of recoverable oil and the Athabascan tar sands. There's huge coal resources similar to the huge coal resources we have here. So, in terms of total energy resources in North American, Alberta and Alaska have very large potential resources that need to be considered. We need to be considering these resources not in the terms of oil or tar sands or gas or coal, but in the gas equivalent that may be transmitted through the pipelines, whatever routes are finally selected. The important thing here is that there are huge quantities of gas hydrates in the Canadian Arctic Islands as well as in Northern Alberta and the Northwest Territories and Yukon Territories, but there's even larger quantities of gas hydrates here in Alaska. Estimates of 1,200 TCF have been published by the U.S. Geologic Survey. So, these gas hydrate resources dwarf our conventional gas resources. The coal resources that could be converted - either the extraction of coal by methane from those coal resources or the conversion of those coal resources to gas - dwarf the gas hydrates that are available. So, in terms of the resources and the quantities and the valuation of the economic feasibility, we need to look at certainly those resources that can be recovered within a reasonable time period - 20 years from an economic standpoint. But from a policy issue point of view, we need to look at those larger resources - unconventional gas, gas hydrates, coal bed methane, the gasification of North Slope coal and other coals in Alaska. CHAIRMAN TORGERSON said they had the MMS at their last meeting had run through about a half hour of known reserves and potential undiscovered reserves on the North Slope as well as all over the federal jurisdiction of the state. "One of the interesting things you mentioned, hydrates, they estimate that we have 170,000 TCF of hydrates in Alaska." SENATOR TED STEVENS CHAIRMAN TORGERSON then welcomed Senator Ted Stevens. SENATOR TED STEVENS said he was glad to have the opportunity to visit with the committee. He said that Congressman Young had done a terrific job on the energy bill with the help of a lot of people, particularly Jerry Hood of the Teamsters. He said: That bill has a very uncertain future right now with the opposition of the majority leader in the Senate. Under our procedure only the majority leader can call up a bill. Senators can offer amendments, but calling up a bill is another matter. So, we're going to have a tough job trying to figure out what to do about that. Clearly, the gas pipeline has another set of facts. Members are after us all the time asking when will Alaska's gas be available to the South 48. So, I don't think if there's anything that has to be done by the Congress that there will be this problem at all with regards to the gas pipeline. There is a draft that has been submitted by the producers. I'm not too happy with that bill, so far. I think there's a lot of explanation we have to have before we think about that. Frank's staff has that and I don't know what they've told you, but they are reviewing it. I really didn't have a chance before I left on the second of August to really read it. I had some explanation of it. Justin [Stiefel] probably knows a lot more about that than I do right now. I'm still convinced that the highway route is the best route for us and I congratulate the legislature for making that clear. Clearly, that's the option we need to bring the gas down to where we can use it not only to meet some of our needs, but also in the future if it's as great as we think it is, to use it as a commodity. And clearly we have the option to go to Valdez and Anchorage, as well as the South 48, if it comes here. As these people have come to my office, we have made it very plain that that's the case. As a matter of fact, I had a visit with some of the producers' representatives here recently and they said the economics didn't look too good if the gas price goes down and asked me what I thought Alaskans would do if that's the case - if the economics require a higher sustained gas price to pay for this extremely long pipeline. And I said, 'We'll wait. We've waited this long so far. I don't think there's any rush to take our gas out by a pipeline that crosses the top of the state and leaves and doesn't answer any of our needs.' The people that propose that will tell you that it'll mean a massive increase in our Permanent Fund, if that's the case, but that massive increase won't offset the increased cost of energy that we all predict out into the second decade of this century. So, I don't see any reason for us to even consider the other proposal. I've told them very seriously that we would do everything we could to join the state legislation in getting the Congress to prohibit them from taking that gas across the Arctic. As you know they plan on taking it out in the ocean and take it through over to Canada and pick up the Canadian gas. The Foothills people have been in to see us and they are very disturbed with that proposal as we are, but clearly what we're doing now is trying to work with Frank and the Energy Committee as they review the energy bill. I hope it will not be necessary for us to take any action to assure the gas pipeline comes through Alaska, but I think it may be possible. That bill, by the way, I should speak a little more about that. As you know, I was chairman of the Appropriations Committee and now I'm ranking member of the committee. Senator Byrd confers with me quite often as I used to with him, but clearly we have not sent to the President any one of our 13 bills. We have 13 appropriations bills; we have the patients' bill of rights bill; we have the bill that deals with campaign reform; we have the bill that deals with issues of Medicare particularly with payment for prescription drugs and we have about 12 weeks of actual session left when we go back into session before Thanksgiving. I don't think it's possible for us to contemplate the energy bill will come up and be a cause celeb in that time. I don't know what their tactics will be, but I'm sure they're going to try to take some action to defer at least the subject of ANWR in the Senate and deal with some of the other issues involved in that bill. Frank will have to tell you what his strategy will be with regard to the energy committee. I'm just assessing the situation from the point of view of the time left on the floor this year. Under the Senate procedures, as you know, there would be three or four possible filibusters against one bill. I don't see any reason for us to stand back, if they're going to filibuster if ANWR's is in the bill. I told them, 'Okay, we'll filibuster if it's not in the bill.' We'll just have to see what comes from tugging at this subject as far as the new majority of the Senate is concerned. Clearly, back to your subject, I think that the future is very great for gas in our country. The demand is increasing. Supplies aren't that available. I'm not sure how high the gas price has to go and stay to justify building that gas pipeline, but it's going to be very interesting to see the economics, which as you know are now being prepared. Incidentally, they are doing the study of the route across the Arctic, but that is a necessary thing from the point of view of complying with National Environmental Policy Act. In order to be able to deal with the EIS, they would have to show that they've examined all reasonable alternatives. I looked at it as a RA study, in terms of studying across the Arctic. I do believe some of the producers would rather have that route, as you know, but I'm convinced a great majority of Alaskans will stick with us and say it must take the Alaska Highway route. CHAIRMAN TORGERSON explained that this committee would convene again in Anchorage on September 19 along with the administration and they would look over that legislation in more detail and prepare unified comments for Senator Murkowski. He asked: Just one question I had on ANWR, just in case your filibuster approach doesn't work, a couple of years ago it came across in the budget reconciliation act, is that a possibility that there'll be another similar bill that provisions could not be filibustered that this might surface next year? SENATOR STEVENS replied, "There won't be one this year; there will be one next year. We've had our reconciliation act for this year and it contained the tax bill, as you know…" CHAIRMAN TORGERSON asked, "Even if we lost the debate in the Senate this year, there is still a strong possibility that that would be a fallback position to try to put it in the reconciliation act for the beginning of next year?" SENATOR STEVENS replied: It's still a possibility. Senator Conrad, Chairman of the Budget Committee would probably oppose that because his colleague, Senator Daschle, opposes bringing it up on the floor in any manner, but it would still be possible to offer this amendment to that bill when it got to the floor. That's sort of one of the last resort measures that I see it might be possible to get it within this Congress. The President is for it; the House has voted for it and I think the Senate ought to at least have an opportunity to vote. Back in the days when we got the old pipeline, there was sort of a gentleman's agreement that any issue that involved national security would not be filibustered and we were able to reach the position that building the oil pipeline was a matter of national security, although the vote was very close, it would have never passed if there had been a filibuster. REPRESENTATIVE DAVIES asked what the timeframe was in the Senate for the producers' bill and was there a need for legislative attention to the National Gas Act or ANGTA? SENATOR STEVENS responded: Senator Bingaman is chairman of the committee that Frank used to chair and the producers are a very powerful organization in our country. If they decide they want that bill brought up in spite of our opposition, and I would opposed that bill, it's going to be an interesting situation. I don't think that bill will pass without our support in the Senate. As it stands now I would oppose it. There has to be some substantial changes on it. If it's a bill to really accelerate the capability of the producers to get final approval to build the pipeline, that's good motivation for us to get a bill passed. But if it's one that going to assure that they alone will have the decision as to what route to take, then I'm not in favor of it at all. The timeframe is going to be up to Senator Bingaman. I think we could get it to the point where it does do what I said, it accelerates the ability to proceed with all other clearances that are necessary and hopefully we would get to the point of one-stop shopping in terms of the approvals that are necessary other than court review, which I think will be inevitable. That could be done very quickly, if that's what the producers want. They did discuss with us that problem, the problem of the myriad o of applications that are necessary to proceed. REPRESENTATIVE DAVIES asked if he thought that would preempt ANGTA? SENATOR STEVENS replied: No, I don't see any preemption involved in the bill that would be the kind of thing I'm thinking about. The timetable is such that the building of it doesn't have a short timeframe for design and construction. So, we're not to the point of crisis yet the way we were in the old pipeline days when we had to get a bill passed in order to start, because we had been delayed already for four years by the environmental litigation. Should we ever get to that point, I think the bill would have a different characteristic than the one I envision right now. CHAIRMAN TORGERSON asked: "We heard today that one of the producers is floating the idea of having the downside protection guaranteed by the federal government basically if the price of gas got down too low, that they might receive some royalty credits for future federal things - sort of sharing the risk a little bit. Do you see any chance of any proposals or any incentives like that passing in the Senate?" SENATOR STEVENS answered: It would really come in the point of view of a tax issue, you know. If you look at that from that point of view of saying that the gas price falls below a certain level, then there's some special consideration of taxes for the producers, that might be possible for a project of this size. One of the considerations, of course, is that Canada is going to get a sizeable payment for the use of a pipeline that travels 2,000 miles in their country. There's so many things involved in this economic study that we really don't know for sure how to quantify them, yet. I think it is possible that there could be some escape hatch for this pipeline in the event the price dropped down below a level that there would be special tax considerations for the producers as they sold their gas to assure there was a market price for that gas coming through. On the other hand, I'm also sure that the people who produce gas in the South 48 now wouldn't like that too much, because it would mean that this enormous supply would engulf the market at a price stabilized by tax incentives, whereas the others do not have that. It's not going to be an easy fight for the producers to get that unless it's something that is worked out with the gas industry as a whole in the United States. REPRESENTATIVE FATE said: Taking up where Representative Davies left off on both the Alaska Natural Gas Transportation System and Act, it was suggested today that a reconfirmation of both that system and that act either be undertaken by either FERC, and there was a question of whether they had that authority, or the congress, itself. Have you got any comment on that, Senator? SENATOR STEVENS said: I haven't crossed that bridge, yet. We have discussed that in several sort of think sessions with the producers, but they have been unwilling to spell out what they are willing to take on as far as a burden of legislative effort to assure the early construction of the pipeline. I don't think there's a great hurry. They don't appear rushed in terms of proceeding with the pipeline. We all know that. It's been a long time since that gas was discovered and they haven't moved forward, yet. There is no urgency from the point of a penalty for not moving forward and I don't think it would be possible to create one that would be acceptable. I think we'll have to wait and see how the route they want to proceed with to see what has to be done to comply with federal law and determine whether we can modify any of those requirements to accelerate the pipeline's construction. I haven't formed an opinion on that yet, mainly because they haven't asked us to consider any option, yet. CHAIRMAN TORGERSON said: One of the confusions is if they file an application under the Natural Gas Act, if they could do that over the top of the Foothills application, which is filed under ANGTA. We've been fencing with FERC trying to get an answer from them of which one of these federal laws prevails in Alaska. We had the El Paso proposal in '77 and the over-the-top, which is the ANWR proposal, we had almost the same thing as we do today and the President made a decision under the Natural Gas Act and Congress passed the ANGTA. Foothills believes and is ready to defend that in court that they have the only authorized route, which is the highway route down. FERC has basically said that if somebody gave them an application under either act, they are required to respond. What Representative Fate is talking about is today they said maybe the quickest fix would be a congressional fix, to have congress look at this and decide which one of these acts prevails today and if there's any cleanup because of the 20 - 25 years since the old act passed, then congress should maybe look at that instead of a regulatory agency such as FERC. SENATOR STEVENS replied: I think you can come to the conclusion that congress made a decision when it responded to President Carter's request and passed the act that accompanied the treaty. I really think Foothills has, literally, a foot in the door. On the other hand, the other project going across the top of our state was not contemplated at that time and I don't think we could say that project is prohibited by existing law. I do think that Foothills is right that as far as Canadian law is concerned, they have all the rights they need to proceed to construct a pipeline and transport that gas once it comes into their country. The problem is in our country and I don't think FERC could do other than just give an off the cuff opinion right now. I hope we don't see that day, because I think it's going to be a bloody day. If the producers file an application for a northern route, we're at a stalemate as far as we're concerned. I'll be very surprised if we get to that point, because they are part of our economy and they are going to have to live with us just like we have to live with them. I do not expect to see that come. CHAIRMAN TORGERSON said hoped they wouldn't see an application for the over-the-top. It is banned in the energy bill, also: It's no longer just the state of Alaska that has passed legislation. We have half of the congressional part passing it and we certainly have plenty of testimony from the North Slope Borough that they won't settle for that and the Whaling Commission and everything else. SENATOR STEVENS said that could come through the committee if the bill is reported. "On the other hand, they are very strong people." He said he would just as soon not have that fight. We need all the cooperation we can. These producers are the producers of our oil, too, and are the potential bidders on ANWR, if it ever gets to the point where we can issue leases. It is open now, but the bill has to be passed to give the approval of congress to the environmental finding under the EIS that there be no permanent harm to that area. We ought to work together. That's been my attitude…I've told them what I told you. I think Alaskans would rather wait than have the pipeline go across the top and it's very clear that our state's position that you all have expressed is a firm one and we don't intend to waiver in congress on that. CHAIRMAN TORGERSON said he appreciated that and that this committee has told the producers and Foothills that every time they get a chance. PUBLIC TESTIMONY MS. DEB MOORE, Northern Alaska Environmental Center, said she wanted to present their policy on natural gas development of Alaska's North Slope: The Northern Alaska Environmental Center believes that the United States as a member of the world community must aggressively reduce its dependency on fossil fuels through energy conservation, transition to cleaner burning fuels and increased development and use of renewable sources of energy. To prompt this transition, the Northern tends to believe the State of Alaska should adopt an aggressive policy of energy conservation standards for new building construction and vehicle purchases and should launch a new program using state funds to support rural alternative energy development emphasizing renewable energies. The Northern Center also recognizes that natural gas is a cleaner burning fuel than are others used in the Fairbanks areas and in many parts of the world. As such, the Northern Center considers natural gas a transitional fuel source in the move toward reduced and more conservative use of fossil fuels in favor of renewable energy sources. The Northern Center recognizes that energy is a strategic resource required by all Alaskans and is essential to their physical and economic well being. With this consideration, the Northern tends to believe that the development of North Slope natural gas reserves to be a reasonable certainty. However, unplanned and poorly conceived development as abetted by comparatively low energy prices can cause significantly long-term environmental, economic and health damage, particularly for the pollutant prone Fairbanks bowl and the fragile interior Alaska environment. Therefore, the Northern Center wishes to remain as involved as possible in the public debate and dialogue on natural gas and its impacts on the Alaska and Fairbanks North Star Borough environs and seeks to participate and provide assistance throughout the process of permitting and construction. If Alaska's proven North Slope gas reserves are developed, the Northern Center believes the following conditions should be met: · Any project must minimize deleterious impacts on local communities and traditional life styles and respect the basic human right to a clean, safe and healthy environment · The pipeline should remain as close as possible to the present utility corridors, excluding RS 2477 rights-of- way · No pipeline development should traverse wilderness frontier areas including off shore of the Arctic National Wildlife Refuge (ANWR) · The State of Alaska should develop a comprehensive energy production and management policy as a precondition to its issuance of a permit for construction of a pipeline. · The state and federal government should conduct studies that assess all reasonably anticipated impacts accruing from natural gas pipeline including the degree of pressure on the Arctic Refuge that may be expected from the addition of a pipeline from the North Slope · The project must go through a new EIS process. · There must be no regulatory shortcuts in the issuance of permits. · Any project must include best available technology and best management practices including where environmentally appropriate, seasonal construction techniques. · There must be a permanent adequately funded and independent formal citizens' advisory council for the oil and gas pipelines that includes representation by conservation organizations as well as local citizens that reports directly to the governor · The project must escrow sufficient funds for dismantling, removal and restoration of all project facilities and impacts in a way that regulatory agencies can insure that the original eco-characteristics of the corridor have been restored as facilities are taken out of service. This return to the original condition standard and the escrow's of DR&R funds must be stipulated in all permits and reviewed in the EIS. CHAIRMAN TORGERSON thanked her for testifying. MR. KEN FREEMAN, Anchorage, said he would work with John Katz to make sure that he and others in the administration are available on September 19 and he would definitely get the word out to the gas policy council, as well, to talk about the proposed federal legislation. CHAIRMAN TORGERSON said he might come up on September 17 and work with whatever they have put together. He noted that Lisa Robinson, Community and Economic Development Coordinator, had written a letter for the record instead of testifying. He said that concluded the meeting and adjourned at 6:02 p.m.