ALASKA STATE LEGISLATURE  JOINT MEETING  SENATE SPECIAL COMMITTEE ON ENERGY  HOUSE RULES STANDING COMMITTEE  July 9, 2008 1:40 p.m. MEMBERS PRESENT  SENATE SPECIAL COMMITTEE ON ENERGY Senator Charlie Huggins, Chair Senator Bert Stedman, Vice Chair Senator Kim Elton Senator Lyda Green Senator Lyman Hoffman Senator Lesil McGuire Senator Donald Olson Senator Gary Stevens Senator Joe Thomas Senator Bill Wielechowski Senator Fred Dyson Senator Thomas Wagoner HOUSE RULES Representative John Coghill, Chair Representative Anna Fairclough Representative Craig Johnson Representative Ralph Samuels Representative Beth Kerttula Representative David Guttenberg MEMBERS ABSENT  SENATE SPECIAL COMMITTEE ON ENERGY All members present HOUSE RULES Representative John Harris OTHER LEGISLATORS PRESENT  Senator Con Bunde Senator John Cowdery Senator Gene Therriault Senator Gary Wilken Representative Bob Buch Representative Mike Chenault Representative Sharon Cissna Representative Harry Crawford Representative Nancy Dahlstrom Representative Andrea Doll Representative Mike Doogan Representative Richard Foster Representative Les Gara Representative Berta Gardner Representative Carl Gatto Representative Mike Hawker Representative Lindsey Holmes Representative Kyle Johanson Representative Reggie Joule Representative Scott Kawasaki Representative Wes Keller Representative Mike Kelly Representative Gabrielle LeDoux Representative Bob Lynn Representative Kevin Meyer Representative Mark Neuman Representative Kurt Olson Representative Jay Ramras Representative Bob Roses Representative Woodie Salmon Representative Paul Seaton Representative Mike Stoltze COMMITTEE CALENDAR    SENATE BILL NO. 3001 "An Act approving issuance of a license by the commissioner of revenue and the commissioner of natural resources to TransCanada Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as licensee, under the Alaska Gasline Inducement Act; and providing for an effective date." HEARD AND HELD HOUSE BILL NO. 3001 "An Act approving issuance of a license by the commissioner of revenue and the commissioner of natural resources to TransCanada Alaska Company, LLC and Foothills Pipe Lines Ltd., jointly as licensee, under the Alaska Gasline Inducement Act; and providing for an effective date." HEARD AND HELD PREVIOUS COMMITTEE ACTION BILL: SB3001 SHORT TITLE: APPROVING AGIA LICENSE SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 06/03/08 (S) READ THE FIRST TIME - REFERRALS 06/03/08 (S) ENR 06/03/08 (S) REPORT ON FINDINGS AND DETERMINATION 06/04/08 (S) ENR AT 10:00 AM TERRY MILLER GYM 06/04/08 (S) Heard & Held 06/04/08 (S) MINUTE(ENR) 06/05/08 (S) ENR AT 9:00 AM TERRY MILLER GYM 06/05/08 (S) Heard & Held 06/05/08 (S) MINUTE(ENR) 06/06/08 (S) ENR AT 10:00 AM TERRY MILLER GYM 06/06/08 (S) Heard & Held 06/06/08 (S) MINUTE(ENR) 06/07/08 (S) ENR AT 10:00 AM TERRY MILLER GYM 06/07/08 (S) Heard & Held 06/07/08 (S) MINUTE(ENR) 06/08/08 (S) ENR AT 1:00 PM TERRY MILLER GYM 06/08/08 (S) Heard & Held 06/08/08 (S) MINUTE(ENR) 06/09/08 (S) ENR AT 10:00 AM TERRY MILLER GYM 06/09/08 (S) Heard & Held 06/09/08 (S) MINUTE(ENR) 06/10/08 (S) ENR AT 10:00 AM TERRY MILLER GYM 06/10/08 (S) Heard & Held 06/10/08 (S) MINUTE(ENR) 06/12/08 (S) ENR AT 10:00 AM FBX Carlson Center 06/12/08 (S) Heard & Held 06/12/08 (S) MINUTE(ENR) 06/13/08 (S) ENR AT 10:00 AM FBX Carlson Center 06/13/08 (S) Heard & Held 06/13/08 (S) MINUTE(ENR) 06/14/08 (S) ENR AT 10:00 AM FBX Carlson Center 06/14/08 (S) Heard & Held 06/14/08 (S) MINUTE(ENR) 06/16/08 (S) ENR AT 9:00 AM ANCHORAGE 06/16/08 (S) Heard & Held 06/16/08 (S) MINUTE(ENR) 06/17/08 (S) ENR AT 9:00 AM ANCHORAGE 06/17/08 (S) Heard & Held 06/17/08 (S) MINUTE(ENR) 06/18/08 (S) ENR AT 9:00 AM ANCHORAGE 06/18/08 (S) Heard & Held 06/18/08 (S) MINUTE(ENR) 06/19/08 (S) ENR AT 9:00 AM ANCHORAGE 06/19/08 (S) Heard & Held 06/19/08 (S) MINUTE(ENR) 06/20/08 (S) ENR AT 9:00 AM ANCHORAGE 06/20/08 (S) Heard & Held 06/20/08 (S) MINUTE(ENR) 06/24/08 (S) ENR AT 1:00 PM MAT-SU 06/24/08 (S) Heard & Held 06/24/08 (S) MINUTE(ENR) 06/26/08 (S) ENR AT 1:00 PM KENAI 06/26/08 (S) Heard & Held 06/26/08 (S) MINUTE(ENR) 07/01/08 (S) BILL CARRIES OVER FROM 3RD SPECIAL SESSION 07/01/08 (S) ENR AT 9:00 AM BARROW 07/01/08 (S) Heard & Held 07/01/08 (S) MINUTE(ENR) 07/08/08 (S) ENR AT 1:00 PM KETCHIKAN 07/08/08 (S) Heard & Held 07/08/08 (S) MINUTE(ENR) 07/09/08 (S) ENR AT 1:30 PM TERRY MILLER GYM BILL: HB3001 SHORT TITLE: APPROVING AGIA LICENSE SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 06/03/08 (H) READ THE FIRST TIME - REFERRALS 06/03/08 (H) RLS 06/03/08 (H) WRITTEN FINDINGS & DETERMINATION 06/04/08 (H) RLS AT 9:00 AM CAPITOL 120 06/04/08 (H) Heard & Held; Subcommittee Assigned 06/04/08 (H) MINUTE(RLS) 06/04/08 (H) RLS AT 10:00 AM TERRY MILLER GYM 06/04/08 (H) Heard & Held 06/04/08 (H) MINUTE(RLS) 06/05/08 (H) RLS AT 9:00 AM TERRY MILLER GYM 06/05/08 (H) Heard & Held 06/05/08 (H) MINUTE(RLS) 06/06/08 (H) RLS AT 10:00 AM TERRY MILLER GYM 06/06/08 (H) Heard & Held 06/06/08 (H) MINUTE(RLS) 06/07/08 (H) RLS AT 10:00 AM TERRY MILLER GYM 06/07/08 (H) Heard & Held 06/07/08 (H) MINUTE(RLS) 06/08/08 (H) RLS AT 1:00 PM TERRY MILLER GYM 06/08/08 (H) Heard & Held 06/08/08 (H) MINUTE(RLS) 06/09/08 (H) RLS AT 10:00 AM TERRY MILLER GYM 06/09/08 (H) Heard & Held 06/09/08 (H) MINUTE(RLS) 06/10/08 (H) RLS AT 10:00 AM TERRY MILLER GYM 06/10/08 (H) Heard & Held 06/10/08 (H) MINUTE(RLS) 06/12/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER 06/12/08 (H) Heard & Held 06/12/08 (H) MINUTE(RLS) 06/13/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER 06/13/08 (H) Heard & Held 06/13/08 (H) MINUTE(RLS) 06/14/08 (H) RLS AT 10:00 AM FBX CARLSON CENTER 06/14/08 (H) Heard & Held 06/14/08 (H) MINUTE(RLS) 06/16/08 (H) RLS AT 9:00 AM ANCHORAGE 06/16/08 (H) Heard & Held 06/16/08 (H) MINUTE(RLS) 06/17/08 (H) RLS AT 9:00 AM ANCHORAGE 06/17/08 (H) Heard & Held 06/17/08 (H) MINUTE(RLS) 06/18/08 (H) RLS AT 9:00 AM ANCHORAGE 06/18/08 (H) Heard & Held 06/18/08 (H) MINUTE(RLS) 06/19/08 (H) RLS AT 9:00 AM ANCHORAGE 06/19/08 (H) Heard & Held 06/19/08 (H) MINUTE(RLS) 06/20/08 (H) RLS AT 9:00 AM ANCHORAGE 06/20/08 (H) Heard & Held 06/20/08 (H) MINUTE(RLS) 06/24/08 (H) RLS AT 1:00 PM MAT-SU 06/24/08 (H) Heard & Held 06/24/08 (H) MINUTE(RLS) 06/26/08 (H) RLS AT 1:00 PM KENAI 06/26/08 (H) Heard & Held 06/26/08 (H) MINUTE(RLS) 07/01/08 (H) RLS AT 9:00 AM BARROW 07/01/08 (H) Heard & Held 07/01/08 (H) MINUTE(RLS) 07/02/08 (H) BILL CARRIES OVER TO FOURTH SPECIAL SESSION 07/08/08 (H) RLS AT 1:00 PM KETCHIKAN 07/08/08 (H) Heard & Held 07/08/08 (H) MINUTE(RLS) 07/09/08 (H) RLS AT 1:30 PM TERRY MILLER GYM WITNESS REGISTER PAT GALVIN, Commissioner, Department of Revenue (DNR) POSITION STATEMENT: Supported AGIA GENE DUBAY SR., Chief Operating Officer, Continental Energy Systems POSITION STATEMENT: Opposed AGIA HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas Development Authority (ANGDA) POSITION STATEMENT: Presented information about an in-state gas pipeline project. DAN DICKINSON, CPA under contract to Legislative Budget and Audit POSITION STATEMENT: Supported AGIA TONY PALMER, Vice President, Alaska Development, TransCanada POSITION STATEMENT: Supported AGIA STEVE PORTER, Consultant to Legislative Budget and Audit POSITION STATEMENT: Presented information & answered questions about Point Thomson. BILL WALKER, Project Director, Alaska Gasline Port Authority POSITION STATEMENT: Opposed AGIA. Presented information about an in-state gas pipeline project. RADOSLAV SHIPKOFF, Financial Advisor, Greengate LLC POSITION STATEMENT: Opposed AGIA. Presented information about the economics of an in-state gas pipeline project. ACTION NARRATIVE CHAIR CHARLIE HUGGINS called the joint meeting of the Senate Special Committee on Energy and the House Rules Standing Committee to order at 1:40:39 PM. SB3001-APPROVING AGIA LICENSE  HB3001-APPROVING AGIA LICENSE  1:41:06 PM CHAIR HUGGINS welcomed the panel members and thanked members of the public for their input at these public meetings. He had before him SCR 22 INSTATE PIPELINE/DISTRIB/SPECIAL SESSION, which was introduced and passed on March 2, 2008, and said that the topic of an in-state gasline was a strong common thread through all of the recent public testimony. Today's meeting would kick off with discussion of an initiative for a possible joint venture to produce in-state gas. 1:44:56 PM CHAIR HUGGINS recognized the panel organizations: Alaska Natural Gas Pipeline Authority (ANGPA); Alaska Natural Gas Development Authority (ANGDA); The Alaska Gasline Port Authority (AGPA); TransCanada Alaska; Enstar; Legislative Budget and Audit (LB&A); and Commissioner Pat Galvin of the State of Alaska, Department of Revenue. He announced that Commissioner Galvin would introduce the initiative he referenced in his opening remarks, the financial implications of it, and a projected time schedule to reach a contract. 1:46:00 PM The panel members introduced themselves: PAT GALVIN, Commissioner, Department of Revenue (DNR); GENE DUBAY SR., Chief Operating Officer, Continental Energy Systems; HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas Development Authority (ANGDA); TONY PALMER, Vice President, Alaska Development, TransCanada; BILL WALKER, Project Director, Alaska Gasline Port Authority (AGPA); RADOSLAV SHIPKOFF, Financial Advisor, Greengate LLC; DAN DICKINSON, CPA under contract to Legislative Budget and Audit (LB&A); STEVE PORTER, Consultant to Legislative Budget and Audit. CHAIR HUGGINS reminded members that today's meeting would be a round table discussion of various scenarios related to in-state gas. 1:47:55 PM PAT GALVIN, Commissioner, Department of Revenue (DNR) explained that the state, Enstar and ANGDA were working together to form the organizing structure for developing an in-state pipeline that would initially be built from the existing fields in the Cook Inlet area to Fairbanks with the intent to provide gas to communities in the interior as soon as possible. It would use existing Cook Inlet gas reserves and hoped to spur exploration of new gas reserves. If new reserves could not be found and additional gas was needed for Fairbanks and South Central, a line would continue north in order to bring those gas supplies into the system. They also saw an opportunity to hook this line into the main line from the North Slope, so gas could move in either direction. The announcement was the beginning of the formation of this partnership. Details were not worked out yet, but they expected to make an agreement public within a few months, at which time they would provide more detail about the organizational structure of the entity and the expected financial involvement of the players. They intended to provide any necessary legislative requests at the beginning of the regular session in January 2009. 1:51:05 PM CHAIR HUGGINS asked Commissioner Galvin to review what led from SCR 22 to a news conference announcing this partnership. COMMISSIONER GALVIN responded that Enstar and ANGDA have been focused on in-state gas for years. Their activities were undertaken independent of each other and sometimes in competition with one another. A combination of recent factors had changed the landscape surrounding this issue, including the state's focus on in-state gas and the high price of energy. When the administration's discussions expanded in the last couple of months to include Enstar and ANGDA, with the idea of focusing the first phase on getting Cook Inlet gas into Fairbanks and moving north from there, it was recognized as an opportunity for them to work in tandem if an agreement could be reached. The timing was right to advance the in-state line, to provide a market for Cook Inlet gas and to get exploration going in Cook Inlet. 1:55:07 PM CHAIR HUGGINS asked where they got the 460 mcf/d volume figure that was mentioned. COMMISSIONER GALVIN said that was the number Enstar anticipated to be their volume coming south. The actual flow of the line would depend upon the market being served and the initial line north to Fairbanks would not be that capacity because the market was not sufficient for that volume. The opportunity to expand it to that size would come with an extension north into the foothills. 1:56:08 PM GENE DUBAY SR., Chief Operating Officer, Continental Energy Systems, the parent company of Enstar, added that they could meet the communities' needs at fewer than 500 mcf/d. 1:56:54 PM REPRESENTATIVE GUTTENBERG was pleased with the concern for exploration and new reserves in Cook Inlet, but wondered what efforts had been made to encourage exploration in the Nenana Basin, which is only 20 miles from the Railbelt. He was told that the Basin was comparable to Cook Inlet and had not been tapped yet, and thought development there could save quite a bit of pipeline and time. COMMISSIONER GALVIN answered that he was absolutely right; when he talked about phase one connecting the Cook Inlet area to Fairbanks, one issue was whether gas would be found along the route, and that would include the Nenana Basin. The Nenana Basin was close enough to the Fairbanks area that its gas could be linked into the Fairbanks system. He added that both Cook Inlet and the Nenana Basin had fairly limited markets, so there was not much incentive to finance exploration. The new pipeline would spur interest in exploring both areas. 1:58:58 PM REPRESENTATIVE GUTTENBERG asked if they had initiated discussions with Doyon Limited on the Nenana Basin, or Atna Resources Ltd. in the Glennallen area yet. COMMISSIONER GALVIN replied that the new venture had not reached the point of formal discussions. However, the state as a resource owner had many discussions over the years with both Doyon and Atna about where the gas would go and the need for a pipeline to get it to market. 2:01:25 PM REPRESENTATIVE HAWKER was gratified to hear of the collaboration between Enstar, the state and ANGDA. He wondered how long the administration had been in negotiations with Enstar over bringing this together, and how far those negotiations had really progressed. The press release sounded as if a deal had been cut and he was interested to hear some more background. 2:02:35 PM COMMISSIONER GALVIN responded that discussions had been going on separately for quite a while, but joint discussions began only recently. The administration chose to wait to announce it publicly until they had a commitment from both parties to work together toward one project. All parties had committed to work diligently to reach agreement on a binding contract to bring to the legislature with a clear statement of what the state's role in it would be. 2:04:47 PM REPRESENTATIVE HAWKER said the press release was the only information he had received. He asked Commissioner Galvin to comment on the public statement made by a senior member at ANGDA that "It is a bit of a shotgun wedding..." and they were thrown together very abruptly. He was put off by the use of that expression by one of the partners to this collaboration. COMMISSIONER GALVIN did not know who made that statement or what the context was. CHAIR HUGGINS referred to Commissioner Galvin's statement that the parties had been working together for "some time" and asked Mr. Heinze to clarify how long "some time" meant. 2:05:48 PM HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas Development Authority (ANGDA), explained that they were contacted two weeks ago Monday to meet with the administration, and met with Enstar for the first time the Wednesday after that [July 2, 2008]. From ANGDA's point of view it was very early in the process, but that did not mean they didn't have a strong commitment to it. CHAIR HUGGINS asked if Mr. Heinze or Mr. Dubay could address the specific comment about a shotgun wedding. 2:07:17 PM MR. DUBAY confirmed that the timeline was as Mr. Heinze described. However, they had been working with the legislature and the administration for a while regarding development of their project and their supply requirements for the community. 2:07:47 PM CHAIR HUGGINS said he understood that there were two proposed routes, one along the Parks Highway and the other the Glennallen spur route. He asked if that was still true or if Enstar was considering other routes. MR. DUBAY replied they had been working on a project along the Parks Highway and had engineers in the field to better define the cost, the time line, permitting, and the environmental issues on that route. MR. HEINZE interjected that the legislature needed to put all of this in context. Because of Department of Energy studies that had been ongoing for over 3 years, Enstar and ANGDA had both participated in and evaluated projects that would use the Parks Highway and the Glenn Highway/Richardson route. Those studies were performed by very competent contractors and made part of the public record. What changed a week ago was that they were no longer talking just about a project; they were talking about a business structure that they would be involved in and committed to in a financial sense and in other ways. That would take time. 2:10:32 PM REPRESENTATIVE GARA said he had heard many times since coming to the legislature that Cook Inlet would be out of gas soon, so he was surprised to hear about a proposal that would take gas from Cook Inlet north. He asked Mr. Dubay how that jibed with the presentations of the past few years that we were running out of gas in Cook Inlet, and with the fact that about 40 percent of Cook Inlet gas was being exported to Asia. 2:11:39 PM MR. DUBAY advised that Enstar was not in the exploration and production business and could only supply the community with gas purchased under contract. So while they agreed that there might be a lot more gas in the Inlet, they could only get the supply they needed under contract through the end of 2013, and only had all the deliverability they needed through the end of 2010. That was why they'd discussed accessing additional gas with a line into the community to serve their customers. MR. HEINZE added that ANGDA would describe the issue as deliverability, how much gas could be made available on a daily basis on a cold day in the middle of winter, and he believed it was awfully close the previous winter. He noted that the administration was part of an agreement related to extending the export license and had negotiated with Conoco Phillips and Marathon to drill five wells each; he hoped those wells would improve deliverability and be part of the solution. With regard to the possibility of sending gas north, they had looked at the volumes involved and, as he had stated in previous presentations about the volumes of in-state gas, the heating load was about 100 mcf/d; about 115 mcf/d was required for electrical, and 250 mcf/d for industrial use, which was very close to the 460 mcf/d number Commissioner Galvin mentioned. More importantly, looking ahead, if they fed Golden Valley Electric, the refinery, and Fairbanks Natural Gas, it would require less than 50 mcf/d, a fraction of what was used in Cook Inlet. He summarized that some improvement in the Cook Inlet situation might make a difference in supplying gas to Fairbanks. 2:14:52 PM REPRESENTATIVE GARA saw this as a concept plan rather than a proposal and did not see what the legislature could accomplish during this special session. He asked if someone was going to assure them that the investment in a bullet line to serve the Railbelt would be more cost effective than other options, such as hydro power from Lake Chakachamna or geo-thermal power from Mount Spur or more wind power. COMMISSIONER GALVIN replied that they would expect to provide information about the economics of this project in comparison to other options that might be available when they brought them a proposal asking for state participation. To preview that discussion however, he anticipated that a line with this particular design would incorporate a combination of things. Its initial intent would be to provide gas to Alaskans, but also to provide the opportunity for Cook Inlet gas and gas along the route to ultimately reach a market. When they looked at the Cook Inlet current reserves, they were in the neighborhood of 1.5 to 1.7 tcf. Given current consumption, that represented a 9 or 10 year supply. The very conservative estimates coming out of the Alaska Division of Geological & Geophysical Surveys (DGGS) of technically recoverable, economic resources that would likely be found if the investment in exploration were made, were in the neighborhood of 3 to 5 tcf. From the state's perspective he saw two competing interests: 1) getting gas to Alaskans as quickly as possible and at an affordable price, and 2) trying to maximize development of Alaska's resources. This line was intended to serve both of those functions. 2:18:22 PM MR. HEINZE illustrated the conceptual nature of that by saying the governor had not asked the organizations involved to stop what they were doing. ANGDA was continuing to do wetlands determination for a 300 mile spur line to Delta Junction. He said what they might do as a result of conversations and in order to meet Fairbanks' needs more quickly, was to continue their wetlands work all the way up to Fairbanks along the TransAlaska pipeline. If they could pre-build the spur line to Delta Junction with a pipe that would hook into a big project at some time in the future, perhaps running a high-density plastic pipe for 80 miles, it might solve both problems without incurring a lot of additional cost. CHAIR HUGGINS asked Mr. Dubay to reflect, based on his experience, on what impediments existed to delivering gas to Alaskans. MR. DUBAY replied that they were working on the engineering for a line from Anchorage to the foothills area through Fairbanks. As they were going ahead with the engineering work, Anadarko was proceeding with exploration in the foothills area and Doyon was working on exploration in the Nenana Basin; so they were trying to identify the gas that would be available on that line. He believed they had the customer demand from various sources including utilities; Agrium, which he felt would commit to bring the plant back up if Anadarko or Doyon made a commitment to deliver gas; and a robust market in fertilizer and LNG. He said that ANGDA also had contracts before the regulatory commission for the additional supply they needed for 2009 through 2013 and that was a hurdle. If they were unable to secure approved contracts for supply in the short term, he did not see how they could have certainty with regard to a longer term commitment either for space in a line, or for a commitment to purchase gas from a producer. He stressed that they all needed to work together; they needed to get an agreement and a structure together as soon as possible. 2:22:44 PM MR. HEINZE said, in addition to the Regulatory Commission of Alaska (RCA) and the importance of approved supply contracts, two other hurdles for an in-state pipeline were: 1) Project permitting including right-of-ways, U.S. Army Corps of Engineers permitting, Environmental Impact Statements (EIS) and other permissions; and certification from the RCA as a pipeline. He explained that these generally required 1 to 2 years of field work. 2) An in-state open season involving North Slope gas would utilize a portion of the statute that had never been used by the RCA. They would recommend some changes to it that would give the RCA greater flexibility in how it would deal with those issues. 2:23:40 PM CHAIR HUGGINS opined that it was incumbent upon the legislature to make the RCA effective, efficient, and timely in the long- term. 2:24:06 PM REPRESENTATIVE CHENAULT said he ought to be happy to hear talk of revitalizing the Agrium plant, which employed 300 people over time; and he was please that they seemed to have a lot more gas in Cook Inlet than he had realized. He questioned Commissioner Galvin's statement that the administration was not asking for anything at that time, because he had a request for $25 million from the administration for engineering, permitting, planning and design of this project, which he believed would end up in the capital project summary. He also said, while he would love to see more gas in Cook Inlet, or gas from the North Slope to Cook Inlet or the Railbelt area for use by individuals, they continued to talk about keeping the Agrium plant in business. In reality, whether Agrium or the LNG plant could continue to operate would depend on the price of that gas. If the gas price was too high it wouldn't matter how much there was, because they would not be able to compete in the world market. He was concerned about investing a lot of money to send gas north, spurring investment in the Cook Inlet for only a short time, and felt they needed to do a lot more talking about it. 2:26:33 PM CHAIR HUGGINS said he saw the $25 million also. 2:26:43 PM MR. HEINZE responded that the $25 million was a request to cover work on the right-of-way, preliminary engineering, permitting, planning, and design of a 370 mile spur line from Delta Junction to Beluga. That line would be a continuation of the project that the legislature had already been funding and which he felt was in the best interests of Alaskans. He said they were on a very aggressive time-line and, if they were to maintain that schedule to reach open season at the same time as the AGIA licensee, it would require the $25 million. 2:28:19 PM DAN DICKINSON, CPA under contract to Legislative Budget and Audit (LB&A), said his question revolved around whether the parties would seek to have this pipeline regulated by the RCA, to have the initial certification done by the legislature or by some other process. A lot of this had been adjudicated in a small sense already. Fairbanks Natural Gas was taking gas from Cook Inlet, extracting the liquids and trucking them up to Fairbanks where it had industrial customers. As it began to have supply issues, it had some adjudication before the RCA and he believed it was extended, allowed a short-term contract, and asked to find other solutions. He thought that, earlier in the year, the solution they came up with was a supply contract with Exxon for the North Slope, where a small amount of liquids could be extracted and trucked south to Fairbanks. So the RCA had already looked at the issues of supply and demand there and whether it made sense to take liquids up to Fairbanks. It had come up with the more traditional view, which was that exploration would have to keep going to make the gas that would be used in 2013 and beyond as contracts expired. 2:30:04 PM REPRESENTATIVE FAIRCLOUGH noted that a major concern raised in discussion over the previous 30 days was triggering the treble damages in the AGIA clause while providing for in-state gas. Specific to that, 500 mcf/d would be the trigger point for those treble damages if no in-state line existed and the big line had not been built. With that said, she asked Commissioner Galvin and Tony Palmer if she was correct in her understanding that TransCanada wanted to provide the gas line itself for Alaska. COMMISSIONER GALVIN asked which gas line she was referring to. REPRESENTATIVE FAIRCLOUGH replied that she meant the in-state gas line. She said that in previous hearings TransCanada offered to facilitate building the in state portion of the line. TONY PALMER, Vice President, Alaska Development, TransCanada, corrected that TransCanada's proposal had been to build the main line from Prudhoe Bay to Alberta and if sufficient gas volumes were nominated to Valdez, they would build the line to Valdez. They had never proposed building a "bullet line" to Anchorage, although they had proposed to provide off-takes off the main line, which would be available along the route to Delta Junction or, if a line were built to Valdez, along that route as well. 2:32:25 PM REPRESENTATIVE FAIRCLOUGH addressed Commissioner Galvin saying that the administration told the legislators 30 days ago that half a bcf was sufficient off-take for the big line, but the proposal before them was already at 460 mcf/d; she wondered how they were supposed to balance that. If, within a private sector development, they had 460 mcf/d proposed to provide gas to just the Anchorage or Railbelt area, she wondered how they could reconcile that with his statements that .5 bcf/d would handle the entire in-state load until the big line was built. COMMISSIONER GALVIN replied that the 460 mcf/d was Enstar's size going from the foothills south; that had to do as much with supply and the amount of throughput they anticipated as it did with the expected demand in the Cook Inlet market. What the administration provided information on was just the demand side, that is how much demand they expected to have for Alaska during the time in which the treble damages clause would be a factor. The 500 mcf/d would be more than sufficient given that they also had Cook Inlet supplies to meet the demand during that time. He continued to say that on this particular project, the line would go from south to north to pick up the additional needs of folks along that line. He added that it was difficult to balance these things because they were comparing apples to oranges, and the question came down to why one would build a pipeline designed with a throughput of greater than 500 mcf/d. In state demand could not reasonably be expected to exceed 500 mcf/d in that time frame, so the only reason would be to improve the economics of the line. From the administration's perspective, the 460 mcf figure provided corroboration of the upper limit of demand during the period to which treble damages would apply. 2:35:49 PM MR. DUBAY confirmed that 500 mcf/d should meet the demands of the community based on historical load profiles. REPRESENTATIVE FAIRCLOUGH said she was not convinced that .5 bcf/d was going to sustain the state until 2017, which was the earliest they could reasonably expect to see gas flow on the big line. She also questioned whether the state was being a good partner to TransCanada by supporting another line that would pull customers away from them. 2:37:07 PM MR. HEINZE said a reasonable projection for heat and light to Alaskans would be 250 mcf per day. In addition, Fairbanks might take 50 mcf per day for the refinery. He hoped to have industrial customers as well, but at open season the applicants would have to come forward with more than an expression of interest. He estimated the total commitment for utilities in the State of Alaska would be about $10 billion, but they had not yet found anyone willing to even talk in that scale of numbers, so he felt they could count on only the residential utility business. With regard to the relationship with TransCanada, he said whether the pipe was Denali or TC Alaska, they were customers of that pipeline and intended to ship their gas in the first 540 miles of it. He saw no way in which that would be in competition with their purpose. 2:39:00 PM REPRESENTATIVE FAIRCLOUGH asked TransCanada if Alaska was being a good partner right now. MR. PALMER answered that based on his understanding, the proposal as currently structured would be within the bounds of AGIA and would not breach in any way the state's obligations to TransCanada. As long as the state stayed within those boundaries he saw no problem. REPRESENTATIVE FAIRCLOUGH queried very specifically whether a 20 inch pipe that was proposed to carry 460 mcf and that could be expanded to over 500 mcf would cause TransCanada to attempt to recover damages based on the treble damages clause in AGIA. MR. PALMER replied that a 20 inch line designed to flow less than 500 mcf/d and actually flowing less than 500 mcf/d until the big line was in service, would not trigger treble damages under AGIA. REPRESENTATIVE FAIRCLOUGH asserted that the line would accommodate up to 700 mcf/d and wanted to be clear that it would not kick off the treble damages. MR. PALMER responded that the 700 mcf/d was a new number to him; his understanding was that the project would be designed to flow less than 500 mcf/d. By that he meant that it would have the facilities installed to flow less than 500 mcf/d. He gave an illustration: If someone constructed a 48 inch pipeline, dribbled through 460 mcf a day and took a subsidy from the state, it would clearly be a breach. But if the facilities were designed and installed to flow less than 500 mcf a day, it would not trigger treble damages. 2:43:15 PM STEVE PORTER, Consultant to Legislative Budget and Audit, said he thought that the clause was intended to look at a 500 million a day project that was in competition to TransCanada, and gas coming from Cook Inlet and going to Fairbanks would have nothing to do with that clause so it was nothing to worry about. What they might need to worry about would be competing against North Slope gas. 2:43:50 PM MR. PALMER read the portion of the clause that dealt with this and summarized that, if over 500 mcf of Cook Inlet gas were going north it clearly would not be in competition. REPRESENTATIVE FAIRCLOUGH pointed out that they had been told they could not "flag" Alaska's molecules [of gas] and, if Fairbanks were a consumer, it would put TransCanada in a position to argue that it was a competing line because it took away part of the market. 2:44:41 PM MR. HEINZE said there was also the technical part of the question, which was that a 20 inch pipe had a varying capacity to carry gas, depending on how many compressor stations might be installed. He asserted that, with a 20 inch pipeline and the volumes needed in Alaska, they would only need one compressor station located in Glennallen to bring the gas in. That project would clearly be under 500 mcf/d. If someone wanted to move more gas through that pipeline at some future time, the RCA would require the addition of other compressor station/s to accommodate greater throughput. The upper end number was a reasonable estimate of what you could get on that project if you built it out all the way. 2:45:43 PM MR. PORTER agreed with Representative Fairclough that, if there were a Fairbanks market for over 500 mcf/d and that took away somehow from the trunk line, it might be a problem; but Fairbanks would need only about 50 mcf. He cautioned that they needed to focus on the business plan and decide now whether they wanted to build the pipe of a size to take advantage of North Slope gas coming south in the future. That would be the only reason for the size of the pipe. He also opined that this was an opportunity for creativity regarding how to maximize local hiring and training, and recommended they build this pipe before the big one got underway as there would not be enough workers to build both at the same time. 2:47:34 PM MR. PALMER clarified that he was the author of "you can't flag your molecules" and that was true once they were comingled in the pipeline. However, they would know the source of those molecules and the intention was clear that if there were more than 500 mcf per day coming from the North Slope it would trigger damages. 2:48:05 PM COMMISSIONER GALVIN wanted to clear up a misconception regarding the issue of competing gas. He said the competition was for the gas, not for the market, not for the sale. The question was whether they were trying to move North Slope gas off the North Slope at greater than 500 mcf/d. The reason this discussion was relevant was due to the possibility of phase two of the project. If they planned to build from Fairbanks north to the foothills, that area was considered under the definition of AGIA to contain North Slope gas. If they simply built phase one from Cook Inlet to Fairbanks and sufficient supplies were discovered either in Cook Inlet or along the route so they never had to build phase two, it would have absolutely no implications for AGIA regardless of the size or the design. He emphasized that when they talked about 460 mcf/d they were talking about the potential for a line going up to the foothills and bringing gas down. So phase one would have no implications under AGIA; it would only be an issue if they had to build the second phase and bring North Slope gas down into the rest of the state. 2:49:34 PM CHAIR HUGGINS said he shared Representative Fairclough's concern; the legislature wanted to get gas to Alaskans and did not want any impediment to that. 2:49:51 PM REPRESENTATIVE DOOGAN said that as he understood it, the difference between today and the day before the press conference was that there had been the announcement of a partnership that had yet to be formed, to ship gas that had yet to be discovered, in what seemed to most people to be the wrong direction, in a pipeline that had yet to be built and details would follow. He asked if he had gotten the gist of it. 2:50:54 PM COMMISSIONER GALVIN conceded Representative Doogan's characterization of the situation, but noted that the administration deemed it a significant advancement to have Enstar and ANGDA working together to advance this project. He agreed that, before asking for anything associated with the project, the state would have to provide much more information than they had done to date; but they were not at that point. Going back to the question about the appropriation however, he said that money was being requested to get the route moving because it would satisfy either outcome, a spur line or this particular project. 2:52:12 PM CHAIR HUGGINS requested a tentative time-line to reach a contract. He also asked that the energy coordinator be introduced to the committee and made available for questions. 2:53:00 PM REPRESENTATIVE SALMON indicated on the map that the pipeline proposed to cross the Tanana and Yukon Rivers. He said there was another route that ran from Nenana up and down the Yukon River, which should also be considered. He pointed out that there had been little discussion about which route would be used, or about the possibility of barging gas to river villages. 2:54:52 PM COMMISSIONER GALVIN referred Representative Salmon's concern to Mr. Heinze. MR. HEINZE responded that ANGDA recognized at least one third of the population could not be reached by pipeline. Fortunately North Slope gas is extraordinarily rich in propane; their estimate was that over 50,000 barrels of propane a day could be carried down a big mainline pipe. With that in mind, they looked at what it would take to separate propane at the Yukon River, for instance, and move it up and down the river system. They believed that had a lot of potential and were working with the City of Tanana on a demonstration project to understand how they would use propane in that community, which they felt was the key question. He had also hired a propane coordinator who was under contract to develop a commercial wholesale propane facility within one year, with the cooperation of the producers. He added that it might also be of value to truck propane to Fairbanks, as it was not uncommon in the gas industry to feed a distribution system with a propane/air mixture. 2:56:42 PM REPRESENTATIVE SALMON said it seemed as if private industry was again dictating to the state what it could and could not do, when the state should have been telling them what it wanted. He asserted that the state had an infrastructure already in place off Nenana and they should use it. 2:57:18 PM MR. HEINZE reminded him that the legislature funded both of the programs he had been talking about. 2:57:33 PM REPRESENTATIVE RAMRAS applauded Mr. Galvin and the administration for moving so aggressively to facilitate an agreement between ANGDA and Enstar. He asked if he could have a list of the meetings the administration had had with Enstar specific to this issue. He also reminded Senator Stedman that they were only seven days away from voting on AGIA, and reiterated his request for a list of meetings between the administration and the producers with regard to getting gas into the line. CHAIR HUGGINS said he would provide both of Representative Ramras' requests to the administration in writing. 2:59:34 PM SENATOR WIELECHOWSKI said he had heard in at least a dozen presentations that they were running out of gas in Cook Inlet, so he was surprised to see a proposal to send gas north. He had also heard that the cost of building a bullet line from the North Slope down to Anchorage would be about $3 billion; the cost to import LNG for natural gas would be about $3 billion; and the cost of exploration to get more gas out of Cook Inlet would be about $3 billion. When the legislature took up the issue of an in-state gas line in the special session, the administration was violently opposed to it and said Alaska was better off building the big line and using economies of scale to keep the tariffs low. He wondered what had happened to change their opinion. 3:00:35 PM COMMISSIONER GALVIN disagreed with the Senator's characterization that they were "violently opposed" to the resolution. The issue at the time was the timing of the resolution and the purpose of the issue coming up at that particular moment. Regarding economies of scale, that was a recognition that in the long term, the focus was on getting gas off the North Slope, getting it to market, and providing both revenue to the state and the opportunity for off-take of that gas for Alaskans. They acknowledged, within that same time frame, that a bullet line was part of the discussion. The economics of a bullet line remained in question, but they had said consistently that the state's involvement in either a bullet line or a spur line was a factor in those economics. It was a question of what would give the state the best bang for the buck. They talked about Cook Inlet running out of gas because the known supplies of gas were being depleted and they had not discovered any new gas fields, although a number of studies indicated that they should be out there. The evolution of the discussion, which spurred the group to come together, was the administration's suggestion that they combine the issues of giving Cook Inlet gas the opportunity to reach bigger markets and spurring interest in exploration, while also meeting the short-term need to get gas to Alaskans as soon as possible. With the formation of this idea to go from Cook Inlet north and then build off from there if necessary, the economic discussion changed; they were no longer looking simply at the most cost effective way of delivering gas to Alaskans, but also at getting Cook Inlet gas to market. In that context the analysis changed and the opportunity presented itself for the state to do more than just fulfill the needs of the households along the way. 3:04:34 PM CHAIR HUGGINS asked what the difficulty was with the timing of the resolution. COMMISSIONER GALVIN could not recall and thought it might have been because they were near the end of the session. CHAIR HUGGINS pointed out it was only half way through the session and said he took exception to the commissioner's comments as he had offered that resolution. 3:05:15 PM REPRESENTATIVE HAWKER asked Mr. Dubay about the impediments he saw to expanding their ability to deliver gas to Alaskans, particularly the RCA regulatory hurdle they were facing with their existing contracts. He commented that he had read a newspaper article recently that said Chugach Electric filed as an "intervener" in their regulatory proceedings, and questioned whether Chugach's counsel was also under contract to the administration. He was also interested in the issue of expansion permitting in Cook Inlet. 3:06:43 PM MR. DUBAY clarified that when he spoke of "impediments" he was not referring to construction, engineering, or licensing, which he considered tasks rather than impediments. He acceded that Chugach was an intervener in their gas contracts case and that two of the experts Chugach was using were Litsinger and Hosie [Spencer Hosie, Hosie/Rice LLP], who had represented the state on royalty issues. The experts took the position that the producers were obligated under royalty agreements to develop and produce the reserves, so Enstar didn't really need to meet a market price. That position conflicted with Enstar's, which was that they wanted to see the producers continue to develop reserves in the inlet and were looking for ways to promote that interest. Enstar supported relicensing the LNG plant because they felt it was an important anchor as a customer off a new line, and that a longer license period would give the producers more incentive to develop production within the inlet, off the foothills, in the Nenana Basin or anyplace where they had access to a line. That license was extended through 2011. 3:10:33 PM REPRESENTATIVE HAWKER thanked Mr. Dubay for his testimony and commented that he would feel much better if he could hear additional details from Chugach to better understand the foundation of the regulatory dispute. 3:11:16 PM CHAIR HUGGINS asked the commissioner if he had any comments. COMMISSIONER GALVIN said he had nothing to add. CHAIR HUGGINS encouraged each member of the Judiciary Committee to look at the propriety of having legal experts being paid to look at both sides of the issue. 3:11:28 PM SENATOR DYSON said he knew of no Cook Inlet geologist who did not think there was a lot more gas in Cook Inlet. USGS testified only a week or so before that there was a reasonable expectation of 17 tcf/d in Cook Inlet. Senator Wagoner, Representative Keller and he wrote to the president asking for permission to explore in the Eastern part of the Cook Inlet basin under the federal lands and, thanks to Senator Steven's efforts they received some interesting contact from the Department of the Interior about that. He stressed however, that in order to get the explorers to spend money on Cook Inlet exploration there would have to be a market for more gas, and that meant the industrial users. He felt they had done a good job of providing tax advantages for Cook Inlet explorers, and the administration gave the LNG export license some teeth for replacing if not increasing the reserves; but people who knew Cook Inlet economics had been saying for years that they needed to build a spur line or bullet line to connect with the main line and give them a decades-long market to all of North America. CHAIR HUGGINS paused to recognize Representative Richard Foster. 3:14:47 PM SENATOR THOMAS said he had been looking at the Econ One demand study published in 2002, which combined the residential, commercial and industrial historical use figures and projected them out to 2020. They also calculated a petrochemical plant, doubled Agrium, put server barns in place in Alaska, converted every coal burning generator and plant to gas and even put gas in places for which there was no transportation. He believed that is where people were getting the figure of half a bcf per day of gas in 2020. He wondered what would drive the drilling operation in Cook Inlet to get things moving if Agrium was out of business and they couldn't supply Fairbanks with natural gas. What could they do to get exploration moving? MR. DUBAY ventured that to invest in exploration a producer would want to understand where they could sell what was produced and what they would be paid for it. He pointed out that there was some uncertainty with regard to the market. Agrium could take gas if it was in sufficient quantity to keep the plant going, but there had been some uncertainty because their LNG plant license was scheduled to expire in 2009. There was also uncertainty with regard to the price, because their last supply contract with Marathon was rejected by the RCA. 3:18:41 PM MR. HEINZE added that to the extent oil prices were significantly above what they had been one year before, anyone in the exploration/production business had tremendous incentive to find places to increase their production of both oil and gas, and they were doing that. He felt there should be some price effect in Cook Inlet as well, but they may not have been seeing the full price effect on the supply side. The other part of it was the uses of gas in Alaska; fertilizer, LNG delivered across the Pacific Rim, all of those commodity prices were up so significantly that the economics of those activities were very attractive, yet they were not seeing a lot of people respond. 3:19:58 PM SENATOR THOMAS opined that building the line north sooner rather than later seemed like a wise idea. 3:20:14 PM SENATOR COWDERY asked Mr. Palmer what would have to happen for the state to incur treble damages. He also questioned whether the price of Cook Inlet gas going south would be the same price as that going north. 3:21:17 PM MR. PALMER said the statute set the responsibilities of the state out quite clearly with regard to what would incur treble damages. If the state granted TransCanada a license and then breached the statute by providing financial incentives to a competing project of over .5 bcf/d it would be obliged to pay treble damages. He could not answer Senator Cowdery's question regarding the price of gas coming south from Prudhoe Bay. If Fairbanks gas were connected to the overall marketplace in North America, it would be a fairly straightforward calculation, not specifically, but a basis differential between transportation points along the pipeline would be relatively straightforward to understand. If there were no liquid market in Fairbanks and the large pipeline was in place, you could get a proxy of what the price would be by looking at the first liquid market, which would be Alberta, and deducting the transportation costs. It might not always trade in Fairbanks at that exact cost differential, but it would often trade in that range. If Fairbanks was not connected to the North American market and you were strictly moving gas from Cook Inlet north, you'd have to look at a test case of how Cook Inlet gas was being priced. He suggested that Mr. Dubay might be able to add something. 3:23:42 PM MR. DUBAY said they had gas under contract using both a Henry Hub price and an oil index price. Under proposed contracts, they had a number of different delivery points for Conoco and Marathon. He emphasized that they had not negotiated contracts beyond 2014, so he did not want to guess what that price would be, but said that usually where there was more production than demand, there was a discount to the index. Where there was less production than demand, there was some kind of premium to the index. They were hoping to have more production available into Cook Inlet than they had demand. If what happened in other producing areas was an indicator, they should end up with a discount and a better price. 3:26:39 PM REPRESENTATIVE SAMUELS asked if his business model was to become the local distributing company (LDC) in Fairbanks. 3:27:15 PM MR. DUBAY replied not at this point. REPRESENTATIVE SAMUELS asked if Enstar would need strong assurances that they would have more exploration, more gas and a big pipeline before they would put their shareholders' money in the south to north project. MR. DUBAY replied not necessarily. They had been working for the past several months toward developing a line along the Parks Highway route from Anchorage to the Foothills. When they looked at the business model for that pipeline, they looked at Fairbanks being part of that load, but saw them as a "city gate customer." That is, they would not have all the residential users; they would be delivering gas to Fairbanks and the industries around Fairbanks, but it wouldn't be their distribution system. He clarified that when he talked about "the customer group" he was talking about Agrium, the Flint Hills Refinery and that type of customer. Production would be from Anadarko and Conoco Phillips in the foothills and Doyon if they found gas in the Nenana Basin. If they started south to north and a lot of gas became available in the Cook Inlet, he could see how they might continue past Fairbanks. 3:30:22 PM REPRESENTATIVE SAMUELS submitted that it would not be in Enstar's business model to put their capital at risk before gas was committed to the pipeline. He asked how the timing would work. 3:30:56 PM MR. DUBAY replied that they were trying to get the engineering done in early 2009 and were scheduled to meet with Anadarko the following week with regard to their drilling and exploration activity. He expected them to commit to having two rigs in the foothills for the next drilling season. They had a lot of permitting and environmental work to do between spring of 2009 and 2010, but he believed that they would be ready to dig a trench in 2010 that would give them lot more data about the gas available to the line before they committed hundreds of millions of dollars. Overall he felt the timing should work out pretty well for gas delivery in Cook Inlet in 2014. REPRESENTATIVE SAMUELS questioned, since Anadarko had no way of knowing when the big line would be built, when they would start spending exploration capital. MR. DUBAY said he was reassured by the fact that Anadarko was already spending significant dollars on its exploration effort. He reiterated that he was confident by the time they were ready to lay pipe next year, Anadarko would have the confidence they needed that the line would be built, and Enstar would have the confidence they needed that they'd have supply to go into the line. 3:34:34 PM MR. HEINZE added that the question Representative Samuels raised of whether you drill wells before there is a pipeline, or build a pipeline before you drill wells, was a fairly common one in the industry. In Wyoming, the Wyoming Natural Gas Development Authority played a major role in standing between the pipeline builders and the explorers and giving both the confidence to move forward. The result was the timely building of a pipeline to tap into the drilling of exploration wells. He suggested the state consider some way to encourage both activities to occur and lessen risk for the capital investment involved. 3:35:25 PM MR. PORTER went back to Senator Cowdery's question about treble damages and whether changing the production tax would trigger them. The production tax discussions occurred before, during and after AGIA; there was a plan to deal with the gas tax issue and it was not intended to be in conflict. The statute itself said "if the state extends to another person preferential royalty or tax treatment..." so changing the gas tax equally for all parties without regard to a specific project would not trigger damages. He cautioned however, that extending TransCanada's benefits, such as fiscal certainty at open season for their shippers, to other parties would be in violation. 3:36:50 PM CHAIR HUGGINS announced a break at 3:36:58 PM. CHAIR HUGGINS called the meeting back to order at 3:57:39 PM. BILL WALKER, Project Director, Alaska Gasline Port Authority (AGPA), said this had been a helpful discussion and he appreciated the opportunity to comment. They were surprised to read about this association in the media and would like to have had the opportunity to learn about it and see where they could add value to it; but their calls to Enstar attempting to set up a meeting were not returned. He was concerned to know how they could work within the confines of the exclusive license without triggering the treble damages. Looking at life after AGIA, he wondered whether they could continue to work on the project they had been pursuing for 10 years, a line from Prudhoe Bay to Valdez, without in some way violating AGIA. He stated that their project remained the same, an "all Alaska" line from Prudhoe Bay to Valdez. They had always believed the most economic gas would come off a large line, so their project called for a 48 inch pipe to Delta and a 42 inch pipe to Valdez, with a spur line off at Delta. He introduced Radoslav Shipkoff to respond to questions regarding the financial aspects of their LNG project. 4:01:36 PM REPRESENTATIVE CRAWFORD noted that when they were talking about the liquifaction facility, the administration provided numbers that were much higher than what the Port Authority had come up with. He wondered if the time frame in which they were generated could account for the difference between their numbers. 4:02:25 PM RADOSLAV SHIPKOFF, Financial Advisor, Greengate LLC, agreed that the LNG plant was one of the principal areas of discrepancy between their assumptions and the assumptions used by the administration in their evaluation of the relative economics of the two projects. The Port Authority's estimate was developed by Bechtel on the basis of an extensive technical study, which involved a large team of highly qualified engineers who had extensive experience in implementing large liquifaction projects of this type. Their understanding of the administration's analysis based on the materials that were made public was that, rather than creating a bottom-up evaluation of the cost of the plant taking into account the specifics of the proposed project, they implemented a top-down approach, which had taken a wide database of projects implemented world-wide and looked at the variability of costs per ton of capacity. They then translated that into what, in the view of that analysis, the cost per ton of capacity would be for the Valdez Project and translated that cost per ton into the figure for the total plant based on the capacity AGPA was proposing. MR. SHIPKOFF pointed out several problems with that methodology. The commercial and technical literature frequently cited dollars per ton for the cost of LNG plants, but not all LNG plants were the same. One would have to take into consideration the scope of the project, the specific technical parameters involved with that scope, and the location. He explained that the location-specific factors would make it very difficult to compare a project in one location with a project in another location. For example, many LNG projects involved an integrated gas monetization solution which had an upstream component and, tied to the upstream component, the liquifaction onshore aspect. The LNG plant in itself frequently included gas treatment facilities including liquid sludge removal, condensate stabilization, acid gas removal, dehydration, and mercury removal. All of those components would be included in the figure cited as dollars per ton. In the case of this project, that function would be performed on the North Slope. A second technical aspect that did not appear to have been taken into account by the administration was the high pressure of the feed gas fed into the Valdez plant from Prudhoe Bay. A significant amount of cost which would otherwise be installed in the plant for compression could be saved because the gas would arrive at high pressure. The ambient conditions should also have been taken into account as the colder climate in Valdez would create additional savings. Bechtel advised that the combination of high pressure feed gas and the ambient conditions alone would result in cost savings of between 35 and 40 percent. Site preparation would also vary greatly from one location to another, as would the cost of marine terminal facilities. Bechtel's estimate was based specifically on the Anderson Bay location, which had very favorable conditions with regard to the costs associated with the marine terminal. Additionally, one would not generally know what comprised the figures that were put out in the public domain or whether they were inflated. So when you put all of those variables together, this methodology would not result in a probability distribution of the capital cost of the LNG plant, which was supposed to reflect the risk profile of the LNG plant in Valdez. It would really reflect the distribution and the variability of the various factors that were location specific. 4:08:00 PM He pointed out that the probability distribution presented by the administration with respect to the LNG plant had a p25 to p75 variability, which was $6 to $8 billion compared to the p25, p75 variability of the pipeline, which was only $2 billion. The engineers who looked at cost risks associated with the pipeline and the LNG plant told them that the cost variability associated with the pipeline was significantly larger than that of the LNG plant, because the unknowns associated with the pipeline were significantly greater. While they would certainly expect some unknowns with an LNG plant, they used a fairly well established, proven design. 4:09:50 PM CHAIR HUGGINS asked if he agreed or disagreed with the administration's analysis. MR. SHIPKOFF replied that they disagreed with the administration's estimate of the cost of the LNG plant because they did not believe it took into account factors specific to the location. He said they did agree with some of the assumptions regarding prices in various potential markets for the LNG project; so if he used the LNG plant cost assumption developed by Bechtel and a range of assumptions for prices developed by both the administration and the legislative consultant, a strong case could be made that, under a wide range of price scenarios, the economic proposition to the producers in terms of netback price per Mmbt on the North Slope was the most attractive for the LNG project. 4:11:04 PM REPRESENTATIVE GATTO said he was confused by the assertion that costs could be reduced 40 percent due to environmental conditions affecting the gas. He asked if Mr. Shipkoff was mixing operational costs with construction costs. MR. SHIPKOFF answered that temperature and pressure would directly influence capital costs because they determine the amount of compression necessary to liquefy the gas, which would be installed as part of the capital costs. REPRESENTATIVE GATTO asked if he was saying the administration failed to include those factors in their analysis. MR. SHIPKOFF said he had seen only the materials the administration made public and had tried to determine their methodology from that. Based on their description, it appeared that they had derived their cost per ton estimate based on a database of projects worldwide, most of which had conditions that differed significantly from the unique conditions of this project. 4:13:09 PM REPRESENTATIVE SEATON said that Cook Inlet had been a stranded gas basin with no external market other than limited industrial capacities and questioned what the price scenario would be if it were connected into a large pipeline. He wondered if the RCA would consider Cook Inlet gas the same price as Alberta gas since it was indirectly connected to that market, and how that would affect the project going forward. 4:14:17 PM COMMISSIONER GALVIN replied they could not project what the price would be, but could discuss the relative price between different options. He observed that what they had right now was the Cook Inlet, South Central area transitioning from a fairly low cost to produce gas, to a price that would be high enough to incentivize development costs for new gas. If they projected that out in isolation from the rest of the system, either they would transition out of gas or continue to increase the price to the point that it would encourage enough exploration to meet their demand. He elaborated, if they factored in the option of connecting Cook Inlet to a larger market by a spur line or hooking into the main line, it would end up connecting Cook Inlet to the North American market in general. At that point pricing would be a combination of the cost to produce in the local area and the availability of other gas on the system, and that system would include North Slope gas with gas from other basins along the route. So the price would be a combination of that integrated market. He considered the relative advantage of that versus not having the connection and, based on their projection of what the North American market would bear, the price would probably be below the expected cost to develop the resource independently, so in that way the consumer would end up in a better position. In response to the second part of Representative Seaton's question, how that would affect the economics of the line, he felt that was what they needed to be looking at as they developed the project plan. They needed to determine if the price was going to be such that it could cover the cost of transporting the gas through the system, or if there would have to be other state involvement to make the price reasonable and bring that transportation cost down. REPRESENTATIVE SEATON referred to Mr. Dubay's comment that he hoped to have more production in Cook Inlet than they had demand in order to keep the price down. He asked if tying that gas into the large line going through Canada would equalize prices, and whether he anticipated that the price of gas throughout the system would be basically Alberta hub minus location sensitive charges. 4:18:45 PM MR. DUBAY replied yes, if you could take Cook Inlet gas someplace else without permitting impediments, then you would be able to get that price less the transportation. He added that it seemed like that might be a ceiling as opposed to a floor; but he thought local use could get it at that price or below the delivered price minus transportation into the larger market. 4:19:43 PM REPRESENTATIVE SEATON commented that, if the gas were connected into the Alberta hub there would be a very definite impetus to base the gas price throughout Alaska on the Henry hub or Alberta pricing. MR. HEINZE interjected that one of the reasons ANGDA had been so enthusiastic about a spur line was that it offered a deliverability; pipeline rates could be varied for free. He also noted that utilities in Cook Inlet were very economical because they had bought gas in the ground a long time ago; that could happen again if Cook Inlet were hooked into gas on the North Slope. 4:21:49 PM REPRESENTATIVE SEATON questioned Enstar's commitment to local service. He said that the North Fork unit about ten miles north of Homer, had one well and recently Homer Electric Association (HEA) and Enstar competitively sought RCA approval to service the Homer area with a couple of conditions: 1) that a second well be produced and 2) that eight miles of pipe be laid to Anchor Point. The second well was being spudded in at that time, but he had heard that Enstar might decide not to service the local area and would instead go north through a connection to Kenai-Kachemack pipeline for either LNG export or to the Fairbanks area. He wanted to know how committed they were to fulfilling their obligation for distribution in the local areas. MR. DUBAY said he believed they still had an agreement in place to service Homer if the gas was developed in that area and if they got commitments from at least 2,000 customers to use gas as a heating source. He added that if their contracts were approved, they had the gas under contract through 2014 and would not be able to take the Armstrong gas into the Inlet for their local customer needs until 2014. Their intention would be to get a commitment from the citizens of Homer to take the gas if it were developed by Armstrong. 4:24:47 PM SENATOR FRENCH said he heard that there was no cost estimate for this pipeline and he found that frustrating. He felt inclined to associate himself with the remarks that Senator Wielechowski and Chair Huggins made regarding the resolution of the Senate back in March to add in-state gas to the call of this session. He brought that up because they still had no cost estimate for the project when they were being asked to write individual checks to Alaskans to help them with the high cost of energy. He felt they should be working with the administration on this and making some investments to get it going. 4:26:46 PM MR. HEINZE interrupted that cost estimates had been put on the table. SENATOR FRENCH returned that the question was more specific to the legal issues that surround [the project]. He acknowledged that they could not sell royalty gas below market and wondered, as they considered some other state involvement in infrastructure in a pipeline, what legal impediments might arise and what that would mean to citizens who did not participate in the benefits of the gas pipeline. He also wondered if they would run into a constitutional prohibition if they tried to bring the price of gas down too far. 4:27:53 PM COMMISSIONER GALVIN replied that the constitutionality of the price of the state's royalty gas would not be impacted by participation in a pipeline. The pipeline participation would simply be an infrastructure project on the transportation of that gas, not on the actual price at the wellhead. He did not believe there would be any legal impediment to the state participation in an infrastructure project that benefited only one portion of the state, and pointed out that they did it all the time. With regard to a cost estimate for this project, he said it had just evolved. There was a cost estimate for the Enstar project and cost estimates from ANGDA on spur lines, but the idea of moving gas from Cook Inlet to Fairbanks before the big line, with state participation in that project, was new. While it was similar to the bullet line in that it would be a small capacity line designed primarily to meet in-state demand, it was being proposed for a different reason. The bullet line was problematic from the administration's perspective because it had the long- term impacts associated with potentially discouraging exploration in Cook Inlet. This project would take the gas north, meet in-state demand and hopefully spur exploration in the Cook Inlet, then hook up to the big line, connect to the main markets and meet both of their goals. Cost estimates for this particular project were scheduled to be in place before the legislature in January. He stressed that the administration wanted to work with the legislature on this matter to meet the needs of Alaskans. MR. HEINZE said that during the hearings in Juneau and Fairbanks, Enstar did present an estimate of about $1 billion for a pipeline linking Fairbanks and Anchorage, and about $2.3 billion for a line linking the Foothills to Fairbanks. At the subsequent meeting in Anchorage, he presented tariff estimates for those based on different assumed flow rates. What they showed was that there was some rationality for the tariff at those cost levels for volumes that were based entirely on utility needs in Alaska. The challenge the government presented to them on Monday was to find a way to make it work even better and he had tried to explain how that might be done. CHAIR HUGGINS commented that Representative Jay Ramras from Fairbanks voiced the slogan "Gas in 5 years, swinging first to Fairbanks." He said he would like to see a Cook Inlet development program that would mature to the extent that they could get something to Fairbanks within 5 years. 4:34:37 PM CHAIR HUGGINS continued that he wanted to see what that program would look like so they [the legislature] could help, because it had to be a cooperative process. He stressed that they were all in it together and should not be communicating through news interviews; the legislators represented the people they were talking about getting the resources to. 4:35:31 PM SENATOR STEDMAN said he was puzzled by Enstar's recent decision to take gas from Cook Inlet and asked Mr. Dubay to explain the analysis they went through that changed their business model for the source of the gas. 4:36:49 PM MR. DUBAY replied that the project they were working on was to build a line from Anchorage to the Foothills; that was where they had invested their capital dollars. They had always felt it would be most logical to build from Anchorage going north to Fairbanks, because if the opportunity presented itself to gather gas from Doyon, for instance, they could get gas to Fairbanks earlier than they might otherwise. While they had not changed direction, they were committed to sit down with the state and ANGDA to work on a structure for a partnership and reevaluate their options to get the best project done for the community. SENATOR STEDMAN said that during the previous session, Senator Thomas worked quite a bit on Susitna hydro to broaden the analysis of how to get energy to Alaska, particularly in the rail belt. The Senate appropriated funds in the capital budget for that study, which was still several months from completion. Then he saw a press release about a business arrangement with Enstar that came out of the blue eight days into the fiscal year, and he was concerned about the lack of openness in the arrangement between the administration and Enstar. He asked Commissioner Galvin to help him understand what was going on. 4:41:22 PM COMMISSIONER GALVIN responded that the venture being undertaken was to put together both a business plan and a proposal to the legislature with regard to this project. When the proposal came to them, it would go through the same public process Senator Stedman described relative to the money that was allocated to study the Susitna project. In that context, it would have to justify itself under a number of potential benefits to the state including opening the Cook Inlet Basin for more exploration, and getting gas to Alaskans as quickly as possible. 4:44:10 PM SENATOR STEDMAN was concerned about the state's involvement in a capital project that seemed to be driven by the marketplace without state or federal aid. 4:46:17 PM COMMISSIONER GALVIN assured them that if the state was going to consider playing a financial role in this project, there would be a large number of hearings as the process moved forward and Mr. Dubay would have the opportunity to sit in the same chair that Mr. Palmer had in terms of answering questions. Other entities would also have the opportunity to express their interest in whether or not the state should be involved in the project. SENATOR STEDMAN reiterated that he was concerned the state was interjecting itself too early into this process. 4:49:10 PM MR. HEINZE emphasized that the state's possible role in supporting this case was still undefined. He offered the Gravelly Lake hydro project as an example of how the state might be involved. The citizens who depended on Gravelly Lake for their power enjoyed a lower rate because the state stood behind the project; it did not spend a nickel on the project but it did stand behind the debt. 4:50:00 PM REPRESENTATIVE JOULE questioned whether Cook Inlet gas could be used for those communities up and down the Yukon River. MR. HEINZE replied that there was no propane in the Cook Inlet gas, so the option was eliminated technically. He suggested that as an intermediate step, propane from North Slope gas could be trucked to the Yukon River giving the rural communities the opportunity to participate. Ultimately, they would hope that a large amount of propane could find its way to Tidewater to service the coastal communities such as Juneau as well. 4:51:33 PM COMMISSIONER GALVIN added that when they began discussions about this line, it was basically about a substitution for the idea of a bullet line from the foothills south. That line was not intended to carry liquids, and the fuel source was not intended to provide the opportunity to strip off liquids at the river. This project would not change the time frame or dynamic of the opportunities presented by the larger line coming off the North Slope. He felt it was important for all Alaskans to understand as they moved forward with these hearings, that although the hearings might focus on one aspect of the project, they were not excluding other opportunities. There had been a number of studies done and it was the objective of the administration and ANGDA to explore how to maximize the opportunity to make gas and other similar products available to as many Alaskans as possible. 4:53:27 PM SENATOR GREEN commented that she believed anything the state might do at that time to fit into this project would only serve to slow it down. CHAIR HUGGINS shared some of Senator Green's concerns and reminded Commissioner Galvin that they wanted that chronological timeline objective for reaching a contract to move them forward. 4:54:37 PM CHAIR HUGGINS reminded members they would meet again from 6:00 to 8:00 PM for Mr. Porter's presentation on Pt. Thomson, and that they would begin at 8:00 AM the following morning with the Denali project; TransCanada workforce issues; TransCanada Exxon Mobile presentation. The CBI Mediation Group would be presenting from 6:00 to 8:00 PM. He adjourned the meeting at 4:55:02 PM. Note: Due to technical issues, this section of audio was recompiled from other sources. Recording volume of this segment is significantly lower than the rest of the meeting. CHAIR HUGGINS called the meeting back to order at 6:08:13 PM and introduced Steve. Porter, who would be presenting "The Point Thomson Dilemma." 6:09:22 PM STEVE PORTER, Consultant for the Legislative Budget and Audit Committee, said he wanted to begin by providing context: why they were where they were; why they might get a gasline; and why Point Thomson was probably economic. It was all related to gas price and commercial decisions, not to stranded gas, AGIA or anything else they might have done. 6:10:30 PM Slide 2: Plains All American L.P.'s WTI Crude - Posted Price MR. PORTER said there was a time in about 1999 when the industry thought they were in a $15 per barrel world in perpetuity. About that time ARCO liquidated, Pt Thomson did not look economic, and a gas pipeline was marginal. Slide 3: U.S. Wellhead Natural Gas Price - In the early years from 2002-2004 there was the Stranded Gas Act. They were in a $2.00 world into the late 1990's and 2000. From 2001-2003 prices were volatile and it was hard to determine where prices would go. Even when they were negotiating stranded gas, they were talking about cases of $3.50 to $6.00. 6:11:58 PM MR. PORTER added that the economists of the world are usually 6 to 12 months behind price in their analysis; but in about 2005 to 2006 they recognized that they were entering a different world. Assumptions on oil and gas were substantially higher. At this point they believed that both Point Thomson and the gas pipeline had become economic due to prices. 6:12:56 PM Slide 4: Pt. Thomson Unit Status prior to Director's Decision - Just prior to the director's decision they had 21 [22] plans for development. The State wanted the producers to drill the wells necessary to determine whether gas cycling or a blowdown strategy was appropriate. The producers were unwilling to spend the money because they wouldn't see a return on it any time soon, so there was tension between the Department of Natural Resources (DNR) and the producers prior to the 23rd plan of development, which resulted in that plan being disapproved. 6:14:13 PM DNR recognized that they had to either disapprove it or stagnate indefinitely, and he felt they had made the appropriate decision. Slide 5: Director's Decision - Failure to submit an acceptable plan of development was grounds for termination and that was the director's decision. The individual lessees with certified wells were required to commence production by October 2009. 6:15:06 PM MR. PORTER continued to Slide 6: Commissioner's Decision - As with any director's decision, they had the opportunity to escalate it to the commissioner, and the commissioner's decision changed a few things. The decision did reject the plan of development because it did not commit to put the unit into production, but it terminated the Point Thomson Unit as opposed to saying they had grounds for termination. That was a shift from the director's decision that the courts would come back to. It also revoked the certification of Point Thomson wells, where the director's decision required them to go into production. Both of these changes showed up later in the December 25th court decision. 6:16:01 PM Slide 7: May 1 Decision - The producers went to court to stall the process. The court said it would let the process move forward but warned DNR that they had probably failed to follow their own statutes when they decertified the wells. Mr. Porter quoted a section from that decision: "the undisputed fact remains that the Department certified these wells pursuant to 11 AAC 83.361, and that as a result of these certifications, the wells 'will be considered capable of producing hydrocarbons in paying quantities' for purposes of 11 AAC 83.374" 6:16:51 PM REPRESENTATIVE SAMUELS asked Mr. Porter to clarify whether this was Judge Gleason's and not Tom Irwin's decision. MR. PORTER answered yes; it was the court's May 1st decision by the same judge who made the final decision. REPRESENTATIVE SAMUELS asked how many wells this decision affected. MR. PORTER replied that he thought there were 7 certified wells. 6:18:01 PM SENATOR BUNDE commented that, although they usually thought of Point Thomson as kind of a monolith, it was actually 46 separate tracts. He noticed there were test wells drilled in about 15 of those, so the producers explored a third of what they had under lease. He wondered how that compared to other leases. MR. PORTER said the issue was not so much the amount of property drilled, it was whether they had found out enough about the reservoir to decide whether to do gas cycling or gas blowdown. In fact, the records of that court case show that if the producers had agreed to drill even the single well that DNR wanted them to, they would have delayed a lot of the other lease obligations, because DNR recognized that they needed to see what was going on down below in order to make a decision on how to move the project forward. 6:19:53 PM Slide 8: Dec 26 Court Decision - Mr. Porter felt that this was a very good decision. 6:20:19 PM He said there were four main issues: 1) Did DNR have the authority to accept or reject the plan of development? The answer was yes, the law gave DNR very broad authority to accept or reject the plan of development. That gave DNR a lot of clout to force a unit operator to move forward with a project however, if they rejected a plan of development, the unit was at risk of being terminated. 2) They found that DNR had the authority to terminate the unit, but not without a hearing to determine the appropriate remedy for rejection of the plan of development. 6:21:36 PM REPRESENTATIVE HAWKER asked if the May 1st decision was in 2008 th and the December 26 decision was in 2007. MR. PORTER replied they were May 1, 2007 and December 26, 2007. REPRESENTATIVE HAWKER wanted to confirm that DNR had the authority to terminate, but not without a hearing. He said that seemed significant. The way he read it, it seemed to say they could terminate but had to provide some remedies. MR. PORTER clarified that, to terminate the unit they had to provide some notice. DNR went back and held hearings and the commissioner issued another decision. But the court indicated that there were some standards associated with that review. 3) Termination of unit is only one possible remedy, and a key phrase was: "consider the import of Section 21 of the Point Thomson Unit Agreement, as amended in 1985, in determining the appropriate remedy." That said, there was a higher standard for unit termination than there was for plan of development termination. 4) Certified wells: Mr. Porter said he would come back to this point in a moment. 6:24:14 PM MR. Porter turned to Slide 9: Point Thomson Unit Agreement - This addressed Section 21, which specified that authority "shall not be exercised in a manner that would (i) require any increase in the rate of prospecting, development, or production in excess of that required under good faith and diligent oil and gas engineering practices; ...or (iii) prevent this agreement from serving its purpose of adequately protecting all parties in interest hereunder, subject to the application conservation laws and regulations." He explained that there was a standard rather like the reasonably prudent operator standard. If you were going to take an $80 billion asset away from somebody, you would have to prove they weren't being a reasonable and prudent operator at the time. In this case, the court said Exxon lost on the plan of development; on the unit termination, they said a reasonably prudent operator would probably have moved this to production and if they didn't, they would probably lose that too. But they created a balance. They told the state that if they couldn't figure out a way to agree with Exxon, they would leave them with the certified wells. That meant that Exxon would get to keep those seven leases, which would split the unit between them and probably result in years of litigation and negotiations. 6:26:29 PM REPRESENTATIVE SAMUELS asked Mr. Porter if the term "unit termination" was really a lease revocation, and if the leases without certified wells would revert to the state. MR. PORTER replied that unit termination would end up with all of the uncertified leases going back to state. As far as certified wells, the court referred the state to their May 1st comments. 6:27:45 PM SENATOR STEVENS asked if there were remedies other than termination or negotiation. MR. PORTER said the court did not delineate the remedies. Under the contract, anything that would have moved this forward and been acceptable to both parties was an option. 6:29:32 PM REPRESENTATIVE DOOGAN asked if it was when the commissioner made his decision that the court ruled DNR had failed to follow its own statutes and regulations when it decertified the wells. MR. PORTER confirmed that it was at the commissioner's level. REPRESENTATIVE DOOGAN asked if the court's decision was absolute, or could the department have gone back and fixed the defects that the court recognized in its process. MR. PORTER responded that the commissioner said it was bad policy to certify wells that had been plugged and abandoned. The court said whether or not he thought it was bad policy, they were certified and the commissioner did not have the authority to overrule his own regulations and statutes. DNR could go back and fix that problem but they would have to follow a regulatory process. He explained that as a rule, a certified well that was good policy would have pressure to the surface. A certified well that was bad policy would have a plug below the surface. In Alaska, unlike the lower 48 however, it might make good safety sense to plug a certified well if you didn't plan to bring it on line for 8 or 10 years because, due to bad weather and remote locations, it could be hard to get back on site if there were a problem. 6:32:58 PM REPRESENTATIVE DOOGAN queried, if it was not possible for the state to take back leases that had wells on them which could be producing gas but were not, how was it possible for the state to enforce that part of the lease that required the lessee to produce. MR. PORTER said that was a good question and one he kept coming back to, because the question was whether they could ever get the leases back. He said that it was even worse than that because there was a part of the law that said if you drilled an exploratory well or two, from a conservation standpoint you would have to make sure to include all the leases of the reservoir and develop a unit plan before you started producing the leases. So from a logical standpoint, for DNR to tell the lease holders to produce that individual well wouldn't work, because every time somebody found an exploratory well they'd have to start producing immediately. Mr. Porter admitted that he didn't know the answer, but he understood that if the Point Thomson Unit did get terminated and they broke it up, they would have to put the unit back together with those seven certified leases and submit another plan of development. REPRESENTATIVE DOOGAN said that from his standpoint, if the state had laws and regulations that allowed people to find producible oil and gas and then just camp on it, they needed to change those laws. MR. PORTER agreed. REPRESENTATIVE GATTO recalled the statement from Howard Johnson's presentation that "every single lease was in default except for one." He asked if that would mean the unit was entirely in default. MR. PORTER replied that he did not say only one lease was in default; there was only one lease that was in its primary term so they could still pay rentals on that particular lease, and if the unit went away it would not be affected. Every other lease would need a reason to be held out of production. That was why the certified wells were so important. In his opinion, that was also why DNR originally decertified the wells; they feared this exact circumstance would happen. If the wells were certified, the leases would be held by the certified wells. 6:37:32 PM REPRESENTATIVE GARA said he believed Mr. Porter had studied the issue and must have some recommendations to make to them. He was not particularly interested in the lower court ruling because the matter would be appealed to the Supreme Court anyway. He expected them to say that since our partners had already violated 24 plans of development, we did not have to work with them any more. He asked Mr. Porter what he was expected to take from this discussion. If it was that they should mediate, he knew they wouldn't get anywhere with that unless both parties had a desire to do it. 6:39:08 PM CHAIR HUGGINS pointed out that some of them needed to understand the process of litigation. MR. PORTER countered that the producers did not violate 24 plans of development. In the early years DNR did not put penalties in their plans of development. When they expanded the unit and DNR wanted to be sure the producers met the provisions of the expansion, they started to do that, but the early ones had little meat to force compliance. 6:41:36 PM REPRESENTATIVE GARA conceded that they might not have violated all 22 of the previous plans, but many of those were breached and every single time the state gave them another chance. As a result, Point Thomson might not be available as a gas field for the gas pipeline. He asked why the state would not say it had given them 22 chances and they still had not produced, so it wanted a new partner. MR. PORTER totally agreed with Representative Gara regarding mediation; as a sovereign state, Alaska should tell Exxon the rules. In this case, DNR had the right and the responsibility to tell Exxon what it would and would not accept. With regard to the delay, he opined that the reason the producers were finally moving the project was that if they started now it would take 6 years to go to development; they would have to cycle the gas for at least 5 years, so they would be ready to push gas into the pipeline in about 11 years. The pipeline was scheduled to be done in 11 years, so they would be ready to put gas in the line either at the beginning of the line or within a few years. If this were to go to litigation, it would take another 10 years. REPRESENTATIVE GARA said that in his experience, after a superior court ruling, the Alaska Supreme Court decides within about a year and a half. He asked Mr. Porter what the basis was for his statement that it would take 10 years. 6:44:55 PM Slide 12: Probable Outcome MR. PORTER explained that this case alone might take only a year and a half or 2 years; then they would have to litigate the certified well issue if the state wanted all of the leases, which would take another 3 years to go through superior court and Supreme Court. Once DNR had the leases back they would have to go through a "best interest" finding, which would take at least a year, and then they would get sued on best interest finding. It would take another six months to a year before the courts would allow them to hold a lease sale. If DNR were lucky and the lease sale concluded within six months, they would then have a new lessee(s) who would have to review and analyze the data, form the units, and create a new unit development plan that would probably end up looking a lot like the existing one. After all of that was done, they would be back where they started, ready to start developing the unit. 6:47:16 PM SENATOR WIELECHOWSKI took issue with the statement that "they finally figured it out" about gas cycling. He said they figured th that out in 1986! In their 16 POD, they said they needed to cycle the gas and promised to drill 7 to 10 wells but did not drill a single one. In previous POD's they said they could not develop Point Thomson until a gas line was built; but the opposite turned out to be true. He said he fully supported Governor Murkowski's and Commissioner Irwin's action to finally take the leases from them. MR. PORTER also supported what DNR did in terms of pushing the producers to move the unit forward, and admitted that Senator Wielechowski was absolutely correct about the unit plans of development; they did propose cycling twice but then backed off of it. He expressed his opinion that they got excited about what they thought they could get out of stranded gas and thought they could do gas blowdown. They thought they could get it approved by the legislature, circumvent the rest of the process and not comply with the POD's, and move Point Thomson straight to gas blowdown. 6:49:27 PM SENATOR THERRIAULT disagreed with Mr. Porter's statement that new lessees at Point Thomson wouldn't have the data. He pointed out that some of the same companies that were on the current list of lessees could come back in and would have access to the data. 6:52:20 PM MR. PORTER conceded that was a possibility. He said he had made an assumption that the state got rid of Exxon and the existing owners, but if Exxon got in with the new owners somehow, they would probably cut a deal to share the data. SENATOR THERRIAULT referred to Mr. Porter's statements that "the state can tell them what's acceptable" and "the state can tell them what to do" and pointed out that the state brought the producers in because they had expertise in developing oil and gas that the state, the sovereign, did not have. He questioned whether the state had the right to tell them how to develop the leases. MR. PORTER said that 11 AC 83.343(b) gave them that right. (Slide 14 - State's Obligation Under Point Thomson Contract) SENATOR THERRIAULT asked if the burden of proof would shift to the state in that case. MR. PORTER said no, not at that point. What 11 AAC 83.343(b) said was that if you rejected a plan of development, you had the right to propose an alternative that would be acceptable to you. (Slide 15: DNR's responsibility under regs.) SENATOR THERRIAULT asked what would happen if they disagreed. MR. PORTER answered that if they disagreed, the state had the right to reject the plan of development and then follow the process for lease termination. SENATOR THERRIAULT questioned what would happen if the producers maintained that the alternative offered by the state was not what a reasonable, prudent operator would do. He asked if the state would have to prove to the court that what it had proposed was fair, reasonable and prudent. MR. PORTER did not agree with Senator Therriault that the burden of proof would shift just because the state met its statutory responsibility. He thought the court would defer to the state's sovereign rights. SENATOR THERRIAULT insisted that the court should give some credence to the producers' claims in the matter. MR. PORTER said he understood the argument and that argument had actually been made, but it was not what the court did. The court told Exxon that the state had the authority to do what it pleased as long as it was not arbitrary. SENATOR THERRIAULT felt strongly that turning down their POD and telling them how to proceed were two different things. MR. PORTER clarified that the reasonable and prudent operator standard would not apply at the plan of development phase, but at the unit termination phase. 6:56:08 PM SENATOR STEDMAN asked if it would be correct to assume that if Exxon's leases were terminated and the leases were re- advertised, Exxon could submit a new bid to buy those leases. MR. PORTER answered yes. SENATOR STEDMAN asked how much information the existing Point Thomson lease holders, primarily Exxon, might have that would create an advantage in re-acquiring those leases. MR. PORTER referred the question to DNR because he was not sure what information was considered confidential and how much, if any of it, would become public if the owners lost the leases. CHAIR HUGGINS called a brief at east at 6:57:50 PM. CHAIR HUGGINS called the meeting back to order at 7:12:09 PM. He recognized Representative Doll and thanked her for her suggestion that a map be displayed in the front of the room. 7:13:22 PM MR. PORTER said in the interest of time he would skip to discussion of his recommendations for the future and what the benefits would be of moving Point Thomson forward timely. If Point Thomson gas was not available for first gas, the project would go from a 4.5 bcf/d pipe to about a 3.5 bcf/d pipe, which would still be at the economic limit of what TransCanada proposed. He stressed that whatever that number would be, the tariff differential was what they needed to look at. He estimated that to be roughly $.50 to $1.00. He stressed that if they fought Point Thomson out, everyone would lose. No matter when they expected to get Point Thomson gas into the pipe, they would still have a 10 year delay if it was litigated. He believed that DNR was interested in upholding the interests of the state and hopeful that the parties would find a solution to move the project forward so the court never had to make a decision on this case. In his opinion, DNR thought they couldn't talk to Exxon before they had submitted their proposal to the courts. Now that had been done, he thought they would be able to sit down with Exxon and work things out. Basically, he hoped it was just a timing issue and they would be able to get the project moving within six months. 7:18:22 PM SENATOR BUNDE said as he understood it Exxon was a majority holder at Point Thomson, but there were minority holders as well. He asked Mr. Porter to talk about how they played into the situation and whether they could negotiate on their own. MR. PORTER understood that under the old plan, Exxon had veto power over moving the project forward, but he believed they had recently changed the operating agreement so that if all of the owners got together, they could roll Exxon. He said that the other owners included BP, Chevron, Conoco Phillips, and probably 20 smaller owners. 7:20:30 PM REPRESENTATIVE LYNN felt he was stating the obvious when he said that it wouldn't make any difference who they went with, everybody would make less money if Point Thomson did not come in. MR. PORTER confirmed his statement. The sooner they could bring Point Thomson in, the better it would be for any project that moved forward. 7:21:57 PM REPRESENTATIVE DOOGAN said, if by some miracle the department were to allow this plan of development to go forward, he understood that the producers would have to delineate the field better and then, according to the Alaska Oil and Gas Conservation Commission (AOGCC), they would have to either produce the gas liquids and the oil rim or demonstrate that they could not, before they could start taking off gas and reducing pressure in the field. He asked Mr. Porter what the timing would be to take the oil off first and get to gas. MR. PORTER responded that getting to the gas would be based on drilling a few more wells. Hypothetically, if Point Thomson owners started producing the unit 6 years from now, that would be phase one and they would have a lot more information. Even before production, AOGCC would begin evaluating what they had found, but once they were in production AOGCC would have a lot more information about how much oil they could use, whether or not they could even produce out of the oil rim, how gas cycling worked, and how much of the condensates would be producible. At that point they could begin to develop a time line, but that would not start until the project started. So if they started immediately, Point Thomson [gas] could show up as early as first gas or a few years after. REPRESENTATIVE DOOGAN reiterated that even under best case scenario they would barely make first gas, and it wasn't likely. MR. PORTER agreed that it was possible but not likely. 7:26:17 PM CHAIR HUGGINS commented that the fundamental question was whether it would be available for open season. MR. PORTER said if the project moved forward, the owners of that gas might show up at open season and commit the gas; but a gas commitment is for 25 years, so even if they got in 2 or 3 years late they would have to make that commitment or they would have to commit at the expansion level. 7:27:10 PM REPRESENTATIVE ROSES paraphrased Mr. Porter's testimony that if they didn't bring Point Thomson on line it would drive the tariffs up and the state would make less money. Then he referred to Exxon's testimony about Point Thomson. They said it had cost them about $500 million to obtain the information they had over the years and to reach the point that they could put this plan of development in place. If they were to lose the leases, since much of that information was proprietary, whoever bought them would have to spend a considerable amount of money to get to that point. MR. PORTER deferred discussion of that to DNR. REPRESENTATIVE ROSES felt it would be fair to assume there would be some cost to a new owner to acquire additional information. MR. PORTER said they would have to acquire information from the existing owners and then spend some time getting up to speed. REPRESENTATIVE ROSES continued that whoever got those leases and had to drill for information would be entitled to the credits the state gives for exploratory operations. So if Point Thomson wasn't on line and they had to go to those as yet undiscovered reserves, the state would have to pay incentives to the explorers for their drilling operations. That would mean even more loss of revenue to the state in terms of Point Thomson gas not being committed by the current lease holders. MR. PORTER allowed that Representative Roses was correct in terms of explorers; if someone spent money exploring a lease, the state was going to pay for it and he thought that was what they would want to have happen. REPRESENTATIVE ROSES agreed, but maintained that when they talked about the expense of not having Point Thomson gas available, it included not only loss of tariff, but the money the state would have to pay for exploration incentives to get back to the level they would be at if Point Thomson were not "taken off the map." MR. PORTER thought they would end up with some incremental costs on whoever came in with Point Thomson. In terms of other explorers, they would explore whether Point Thomson showed up or not. So while there would probably be an incremental cost associated with Point Thomson he didn't know what it would be. 7:30:57 PM SENATOR BUNDE said, because the stakeholders at Point Thomson were in litigation they obviously could not book the reserves; but they were also aiming at a moving target with regard to when a pipeline would be available. He asked at what point they could book the reserves if the producers and the administration made piece, and if Mr. Porter could venture a guess as to what the value to the producers would be when they booked those reserves. MR. PORTER replied that he didn't have a clue; he was sorry but it was not his field. 7:31:55 PM SENATOR THERRIAULT conjectured that AOGCC would not be able to give its blessing on an off-take rate for the first open season. He asked if it was possible to bid for capacity on a reserve that AOGCC had not "blessed." MR. PORTER responded that he thought TransCanada only required 40 percent of the bid be identified reserves, so it would be possible for the three majors to overbid Prudhoe. SENATOR THERRIAULT felt a growing concern that Point Thomson would not be able to participate in the first open season, because he didn't see how AOGCC could come to an off-take decision that quickly. If it were bid without AOGCC blessing, it seemed that would be taken into consideration by the financiers. MR. PORTER replied that AOGCC would not be a factor at open season, but it would be in terms of what a risk-taker would be willing to risk. If Point Thomson owners believed they were at least 10 years out and might not have the Point Thomson leases, they might not factor that into their bid. If they believed they had some chance of bringing that Point Thomson gas into the pipeline soon after first gas, they would show up and bid the gas, even if AOGCC had not approved it. If they could look forward and feel confident that they would approve it, they would risk that in their bid. With regard to the financiers, if Exxon, Conoco Phillips and BP came forward and bid 4.5 b without Point Thomson, and committed to 4.5 b over the next 25 years with TransCanada, TransCanada would have a pipeline and could finance it. SENATOR THERRIAULT touched again on the question of whether any new lessee would be starting from scratch with regard to down- hole technical information and said that was not true. MR. PORTER interrupted that it would depend on who the lessees were. SENATOR THERRIAULT continued that it could be an existing lessee who already had access to all of that information. 7:35:59 PM SENATOR WIELECHOWSKI went back to Senator Doogan's timeline regarding when the gas would be available. He noted that the unit owners intended to pull 10,000 of the 5 or 6 million barrels per day of condensate which, according to DNR's calculations, would take over 40 years at that rate. Based on not getting started for 6 years, they would be looking at first gas rolling out of Point Thomson under Exxon's current plan in 2054. So yes, they were promising to develop just like they had for the last 43 years. SENATOR WIELECHOWSKI said that according to DNR's testimony in Anchorage, the physics of the gas cycling as proposed by Exxon didn't work. He wondered if Mr. Porter had an opinion on DNR's testimony. MR. PORTER maintained it was completely irrational for Exxon to build a $1.2 billion facility and then cycle it for 40 years producing only 10,000 barrels a day. He stressed this was a phase 1 process; either it would work and they would expand it, or it wouldn't and they would go to gas blowdown. What would not happen would be 10,000 barrels a day for 40 years. SENATOR WIELECHOWSKI said if this is the largest undeveloped field in North America, and if the Superior Court affirmed Alaska in taking the leases back, shouldn't they have producers lining up to take those leases? MR. PORTER agreed it's worth a whole lot. That's why the producers finally decided to move forward. 7:39:54 PM REPRESENTATIVE HAWKER followed up on the Point Thomson testimony in Anchorage. A great deal of it seemed to be speculation by dueling consultants over the proper way to develop that reserve, whether they should do gas cycling or go straight to blowdown, and how they should deal with the oil rim. The oil rim seemed to be a very critical factor and he couldn't understand how the experts could have such widely differing opinions on how to deal with it. As he understood it, there were two exploratory wells that had gotten close to the oil rim and could provide tangible information. One of those wells was solidly into the oil rim; the other well got into the mixing zone where the oil met the gas liquids. That test well that was solidly into the oil rim came up at 18 API. MR. PORTER interrupted that it was actually 11 API and the well in the mixing zone was 18 API. REPRESENTATIVE HAWKER confirmed that the well in the rim was 11 API, very viscous, and the one in the mixing zone was 18. He asked Mr. Porter to explain those numbers to him. MR. PORTER said that those were the only two pieces of information available on that oil. REPRESENTATIVE HAWKER asked if he was correct that the administrative consultant's report, on which DNR based its own proper plan of development, used 20. MR. PORTER answered yes, that a debate was going on between the consultant and AOGCC as to whether 11 API was truly a good number. If it was a good number and the 18 API was a mixed number, then 20 was probably not appropriate and they should have used 11. He said the right number was somewhere in that range, but they wouldn't know for sure until they punched some more holes. He added that they had used the term "discontinuous oil rim," meaning it would be difficult to estimate how much oil would come out of that particular section of the reservoir. 7:44:52 PM REPRESENTATIVE HAWKER asked if Mr. Porter could distill that into layman's terms and tell him what it meant. MR. PORTER explained that if that was the only decision you had to make, you would punch some holes to see if you could produce that oil rim. If it was really that heavy, if it was 11 API gravity even under high pressure, then the estimate of value to Point Thomson, the amount of oil you would need to produce, and how many years you would need to produce it would go down substantially. REPRESENTATIVE HAWKER said this was one of his favorite topics in these debates; the false precision of putting a chart on the wall and asking them to believe that what was up there was the truth. CHAIR HUGGINS asked Mr. Porter what he meant by "punching a hole" and how much that would actually cost. MR. PORTER said the problem with these wells was that there were very high pressure zones down below that required special drilling equipment and techniques that would greatly increase the cost. He had heard figures from $80 million to $100 million per well but could not really say how much it would cost. 7:47:04 PM REPRESENTATIVE SAMUELS said the way he understood it was that the small scale cycling project was a good idea, but they didn't' believe Exxon would do it. He asked if that was too broad a simplification of the situation. MR. PORTER agreed that was fairly accurate. The problem was believing Exxon would move forward. He reiterated that, from a contract standpoint, if you don't believe someone, you set the contract penalty structure accordingly. DNR tried imposing penalties for not drilling, but Exxon just paid them and didn't drill. DNR's stance was that they didn't need money, they needed a well. Exxon finally said they were ready to drill a well, but DNR didn't trust them. It created a catch 22 because the state was basically saying to the court that they wanted out of the contract because they didn't trust Exxon and, under the law, the courts could not allow that to stand or it would mean a sovereign could unilaterally jump out of any contract. He summarized that DNR would eventually have to come to the table with the producers and solve the penalty problem. He believed and hoped that both parties wanted to come to some agreement; if they failed to so, the court could very easily hold against them on the unit termination issue. 7:51:32 PM REPRESENTATIVE GARA said they had been focusing on how Exxon was supposed to develop Point Thomson, but the bigger argument was that they didn't have all the information necessary to decide how it should be developed because Exxon had not done the exploration they needed to do to provide that information. He asked if that wasn't a strong part of our case. Exxon had a duty to explore, so the problem was not so much that they didn't move forward but that, they didn't perform the exploration they were required to under the leases. MR. PORTER said that was true, but in the 23rd plan of development, they proposed to do that. He stressed that under contract law, the court wouldn't look back at what they didn't do in plans 1-21, only at what they were currently doing, and they actually did what they were supposed to do in the 23rd plan. REPRESENTATIVE GARA objected that the 23rd plan came out after the state had said "we're not giving you any more chances." Up to the 22nd plan they hadn't explored like they were supposed to, so the state said "tough we're not playing this game any more." After the state sued because they hadn't followed through on their obligations, Exxon made another offer. He felt the latest plan wasn't binding because it was offered after the state filed suit. MR. PORTER corrected that the suit was kicked back into the administrative process, and the court didn't care what had happened in plans 1 through 22. They cared about what was in the 23rd plan of development, which was a proposal to the court as a solution to unit termination. 7:55:18 PM CHAIR HUGGINS interrupted and advised those who wanted to continue the conversation that Mr. Porter would be available afterward. He asked Mr. Porter to wrap up. 7:55:33 PM MR. PORTER said the key on this was in the owners' hands. He hoped they would be able to solve the problem with Exxon because if they fought it like a battle, the state would lose. If DNR approached the Point Thomson Unit owners as a problem to be solved, the state could win. He did not think the parties were that far apart and was confident this was soluble. 7:56:49 PM CHAIR HUGGINS thanked Mr. Porter for his insights and announced that they would begin again with a new presenter at 8:00AM sharp. CHAIR HUGGINS adjourned the meeting at 7:57:18 PM.