ALASKA STATE LEGISLATURE  SENATE SPECIAL COMMITTEE ON NATURAL GAS DEVELOPMENT  Anchorage, Alaska July 7, 2006 9:20 a.m. MEMBERS PRESENT Senator Ralph Seekins, Chair Senator Bert Stedman Senator Ben Stevens Senator Donny Olson Senator Thomas Wagoner Senator Kim Elton Senator Gary Wilken (via teleconference) MEMBERS ABSENT  Senator Lyda Green Senator Con Bunde Senator Fred Dyson Senator Lyman Hoffman Senator Albert Kookesh OTHER LEGISLATORS PRESENT  Senator Bettye Davis Senator Hollis French Senator John Cowdery Representative Norman Rokeberg Representative Paul Seaton (via teleconference) Representative Ralph Samuels Representative Berta Gardner COMMITTEE CALENDAR Roundtable Discussion on the Proposed Natural Gas Pipeline Contract PREVIOUS COMMITTEE ACTION   No previous action to record WITNESS REGISTER    JIM CLARK, Chief Negotiator Office of the Governor PO Box 110001 Juneau, AK 99811-0001 POSITION STATEMENT: Participated in the roundtable discussion.   ROGER MARKS, Petroleum Economist Department of Revenue PO Box 110400 Juneau, AK 99811-0400 POSITION STATEMENT: Participated in the roundtable discussion and talked about the proposed gas reserves tax. WENDY KING, Director of External Strategies ANS Gas Development Team ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 POSITION STATEMENT: Provided ConocoPhillips' perspective in the roundtable discussion. REPRESENTATIVE NORMAN ROKEBERG Alaska State Legislature Alaska State Capitol Juneau, AK 99801-1182 POSITION STATEMENT: Participated in the roundtable discussion. BOB LOEFFLER Morrison & Foerster Counsel to the Governor Office of the Governor PO Box 110001 Juneau, AK 99811-0001 POSITION STATEMENT: Participated in the roundtable discussion.   DAVID VAN TUYL, Commercial Manager Alaska Gas Group BP Anchorage, AK POSITION STATEMENT: Provided BP's perspective in the roundtable discussion.   S.A. (BILL) McMAHON JR., Commercial Manager Alaska Gas Development ExxonMobil Production Company Houston, TX POSITION STATEMENT: Provided ExxonMobil's perspective in the roundtable discussion. REPRESENTATIVE PAUL SEATON Alaska State Legislature Alaska State Capitol Juneau, AK 99801-1182 POSITION STATEMENT: Participated in the roundtable discussion.   REPRESENTATIVE RALPH SAMUELS Alaska State Legislature Alaska State Capitol Juneau, AK 99801-1182 POSITION STATEMENT: Participated in the roundtable discussion.   KEN GRIFFIN, Deputy Commissioner Department of Natural Resources 400 Willoughby Avenue Juneau, AK 99801-1724 POSITION STATEMENT: Participated in the roundtable discussion. SENATOR JOHN COWDERY Alaska State Legislature Alaska State Capitol Juneau, AK 99801-1182 POSITION STATEMENT: Participated in the roundtable discussion. HAROLD HEINZE, Chief Executive Officer Alaska Natural Gas Development Authority (ANGDA) Department of Revenue 411 West 4th Anchorage, AK 99501 POSITION STATEMENT: Provided ANGDA's perspective in the roundtable discussion. SENATOR HOLLIS FRENCH Alaska State Legislature Alaska State Capitol Juneau, AK 99801-1182 POSITION STATEMENT: Participated in the roundtable discussion. DAN DICKINSON, CPA Consultant to the Governor Office of the Governor PO Box 110001 Juneau, AK 99811-0001 POSITION STATEMENT: Participated in the roundtable discussion.   U.S. SENATOR TED STEVENS United States Senate 522 Hare Senate Office Building Washington, DC 20510 POSITION STATEMENT: Provided his perspective during the roundtable discussion.   ACTION NARRATIVE CHAIR RALPH SEEKINS called the Senate Special Committee on Natural Gas Development meeting to order at 9:20:46 AM. Present were Senators Ben Stevens, Bert Stedman, Thomas Wagoner, Kim Elton, Gary Wilken (via teleconference) and Chair Ralph Seekins. Also attending were Senators Bettye Davis, Hollis French and John Cowdery, and Representatives Norman Rokeberg, Paul Seaton (via teleconference), Ralph Samuels and Berta Gardner. ^Roundtable discussion on the Proposed Natural Gas Pipeline  Contract    9:21:55 AM CHAIR RALPH SEEKINS announced the committee would continue discussion on the proposed natural gas pipeline contract. He asked Mr. Clark to continue yesterday's discussion about basic structure and to expand on taking gas in kind. ^Jim Clark, Chief Negotiator, Office of the Governor JIM CLARK, Chief Negotiator, Office of the Governor, explained that the basis on which the administration proceeded in taking the mandate from the legislature in the form of Alaska Stranded Gas Development Act ("Stranded Gas Act") amendments was to interpret the Act as providing direction for negotiating a business deal. He noted in October 2004 the administration submitted a proposal; the producers countered it December 2004; workshops were held in winter and spring 2005; from July 2005 until agreement on gas in February 2006 there were negotiations; and agreement on fiscal certainty on oil was completed May 24, 2006. Noting Dr. Pedro van Meurs was chief economist on this but couldn't be present, Mr. Clark commended Roger Marks for a terrific job as the petroleum economist during the process. ^Roger Marks, Department of Revenue ROGER MARKS, Petroleum Economist, Department of Revenue (DOR), noted he would discuss how the administration views the project, views the role of the Stranded Gas Act and will develop a contract in light of those. He identified size as the most prominent factor because size magnifies everything, good or bad. The biggest risks are price and cost. He emphasized that prices are unknowable over the next 35 years. Five years ago, forecasts by DOR and others for 2006 oil prices were at $17.00, whereas today's price is over $70.00. Thus a case could be made that over the next 35 years gas prices could be $2.00 or $45.00. In support of low prices are increasingly economic clean coal; ever-cheaper imports of liquefied natural gas (LNG) to the Lower 48; 6,000 trillion cubic feet (Tcf) of stranded gas reserves worldwide that Alaska has to compete with; and 17 new applications for nuclear power plants submitted to the U.S. Department of Energy because high prices are counteracting people's concerns about safety. 9:28:02 AM MR. MARKS also pointed out that low-probability events happen throughout history that can't be envisioned beforehand. Turning to cost, he cited a presentation by Independent Project Analysis (IPA) about the propensity for high cost overruns on mega- projects, sometimes by 50 percent - a big problem on a $25 billion project. Taken in total, the outcome of this project could be excellent or very bad, but shareholders tend to have an asymmetrical view: nervousness that bad things will happen outweighs optimism about good things. Prudent people tend to turn down a gamble that could have a very bad outcome, even if a very good outcome is possible. He highlighted fiscal stability. Mr. Marks explained that the producers are willing to take on the downside risks, but if the upside materializes, they aren't willing to have that taken away by higher taxes. That destroys risk-versus-reward symmetry. Thus the lack of fiscal stability is a problem in addition to risks from high costs and the size of the project. He said the Stranded Gas Act essentially directs the administration to negotiate a contract to instill fiscal stability, which was done, and to custom-tailor fiscal provisions of the state to the specific project that will be developed. The administration considers the gas "stranded" under that term's definition in the Act 1) because the outcome is unknowable and the "size risk" magnifies downside effects, and 2) because of fiscal instability. Mr. Marks indicated the producers are being given fiscal stability. Thus the question is what has been done to custom-tailor the fiscal system to suit the project per the directives in the Stranded Gas Act. MR. MARKS offered the analysis of the administration and Econ One, that this is a low-rate-of-return project relative to the producers' other investment opportunities because of high costs, great distance and long construction time. It is believed to have a high hurdle rate, Mr. Marks noted, which depends on how the producers perceive its unique risks. Improving the rate of return makes the project more viable. The main way is to take gas in kind; that is in contrast to the current in-value world, taking royalty and taxes. 9:36:19 AM MR. MARKS highlighted several scenarios, concluding if the state took its gas in kind without ownership, the producers would want a firm transportation (FT) commitment from the state, which would be an asset to them. While the producers would pay 100 percent of the costs, that FT commitment would offset 20 percent of those costs, thereby increasing the rate of return. Mr. Marks reported that because taking gas in kind causes the state to incur a long-term liability, it was a small additional step to take 20 percent ownership of the pipeline to match the state's gas share, with the following benefits: The state's interests would align with the producers, and the state would get a great deal of income from the return on equity and would get a seat at the table in order to formulate development decisions and to know what is going on. He cited the following economic result to the producers: The state would take the gas in kind, alleviating them from upfront costs, estimated to equate to 2.0 to 2.5 percent - which on a $25 billion project is significant, perhaps a $4 billion reduction in capital costs. It would have the same economic significance to the producers as if the state took no severance tax, royalty, corporate income tax or property tax under the status quo. The state would give up no revenue under this scenario. But it would have an increased rate of return. He acknowledged the state would incur risks related to marketing, reserves, depletion and force majeure by taking its gas in kind. Mr. Marks opined that those risks aren't huge, however, but are manageable. What is the reward in return? It is getting a gas line, with all it entails, which he opined is a very good tradeoff. He summarized that the contract does two things: 1) improves the rate of return by taking the gas in kind and 2) provides fiscal stability. MR. MARKS brought attention to an important result of taking gas in kind. The state's 20 percent is more than enough gas to satisfy all in-state needs. The state could develop terms and conditions for selling its gas in Alaska. Monetarily, the state would be indifferent whether its gas was sold at $5.30 in Chicago - which includes transportation costs - or $2.80 on the North Slope. In addition, the contract has mileage-based tariffs. If shipping costs were $0.25 to Fairbanks, at $3.05 Fairbanks could have the lowest-priced gas in the U.S. if the state chose to sell at that price. There, 70 percent of homes are heated with oil, now about $18.00 per million Btu. At $3.05 for gas, it would cost 80 percent less. Of course, the state could set a higher price - it is a matter of policy. He noted the irony that North Slope gas could be sold in Anchorage for about $1.00 less than Cook Inlet gas. Or Alaska's share of the liquid could be extracted, providing about 0.25 million gallons a day of propane. That could be shipped to Western Alaska, where residents are hurting from the energy crisis. Mr. Marks emphasized the great opportunity for selling gas in Alaska, under whatever terms the state deems best, if it takes its gas in kind. 9:44:04 AM MR. MARKS pointed out an overlooked benefit of the gas line: Prudhoe Bay oil production is declining, and at some point operating costs will overwhelm the field. Prudhoe Bay gas could absorb a lot of the operating costs, however, and thus oil could flow longer. In addition, there could be lots of exploration. As producers find gas, they'll also find oil. The lifespan of the North Slope without a gas line isn't known, but DOR's modeling has used the year 2030 as a guess. MR. CLARK added that the extended time for the Trans-Alaska Pipeline System (TAPS) is viewed as time for necessary research and development to tap into North Slope heavy oil, estimated at 10-13 billion barrels, equivalent to another Prudhoe Bay. The gas line estimate of 35 Tcf is equivalent to 6 billion barrels of oil. He expressed hope for at least 70 Tcf to put through the line, allowing expansion to 5.9 billion cubic feet (Bcf) a day; the 70 Tcf equals another 12 billion barrels of oil, and there is that amount of heavy oil. Because the equivalent of two Prudhoe Bays can be monetized for the benefit of future generations, Mr. Clark said the administration believes it is critical to the state that this gas line go forward. 9:47:51 AM ^Wendy King, ConocoPhillips WENDY KING, Director of External Strategies, ANS Gas Development Team, ConocoPhillips Alaska, Inc., pointed out that ConocoPhillips, the largest explorer in the state, has been actively exploring for both oil and gas. If gas is found on the North Slope, however, there is no way to get it to market and thus it is viewed as a dry hole. She predicted one of the most significant benefits of a gas pipeline would be additional exploration for both gas and oil on the North Slope. In trying to find one, a company likely would find the other. MR. CLARK agreed with Mr. Marks' point that the state, by taking gas in kind, is taking on capacity risk and marketing risk. He suggested addressing this after discussion of the general economic underpinning of the contract. REPRESENTATIVE NORM ROKEBERG, Alaska State Legislature, inquired about the costs of in-state tariffing, particularly with respect to Cook Inlet. MR. CLARK highlighted three policy choices, outside the contract, for the administration and the legislature. The first is how to price the gas at any of the four offtake points. One way is to have the netback price plus a transportation charge based on a mileage-sensitive rate to the point of offtake, giving Fairbanks cheap gas. Similarly, the mileage-sensitive rate from Glennallen into Cook Inlet would have charges to it, but not as expensive as going to the AECO Hub. He said a second policy choice is to combine the netback price plus a charge for transportation, putting it out to competitive bid. How else can it be allocated among the various commercial end-users, other than letting them bid on it and having the state realize the highest rate of return? Mr. Clark recalled doing this with royalty oil when made available, for example. He noted a third choice, done currently in Cook Inlet, is to use the Henry Hub price; thus the price paid in Cook Inlet is similar to prices paid elsewhere in the country. Mr. Clark said the administration is leaning toward a mileage-sensitive rate, the netback and some kind of competitive bidding. Obviously, this requires discussion with the legislature. He deferred to Mr. Marks for specific numbers. 9:53:01 AM MR. MARKS focused on an example where the Chicago price was $6.00, as at Henry Hub; the difference between these two over the last few years has been pennies. In his example involving ENSTAR and Unocal, the latter argued to the Regulatory Commission of Alaska (RCA) that it had alternative investment opportunities in Cook Inlet or the Gulf of Mexico and would take the higher-priced one; this compelled RCA to let ENSTAR get the Henry Hub price for Cook Inlet gas. While some economists think that makes sense, Mr. Marks said others don't. Companies such as Marathon are trying to get the same deal from RCA. Thus prices in Chicago, at Henry Hub and in Cook Inlet are all $6.00. MR. MARKS further explained that if the tariff to Chicago is $2.50, the netback price is $3.50. There are a lot of numbers out there for the cost of getting gas from the North Slope to Southcentral Alaska. It depends on the amount of gas and the pipeline size: the bigger it is, the lower the per-unit cost. It also depends on whether there is offtake in Delta Junction or Fairbanks. If the number were $1.50, the netback price at the North Slope would be $3.50, and there'd be a $1.50 tariff from the North Slope to Southcentral. That would give a price of $5.00 price - a dollar less than the Henry Hub price that consumers currently pay. REPRESENTATIVE ROKEBERG offered his understanding that RCA had approved the contract, but not Henry Hub prices in Anchorage. He highlighted the policy choices on how to incentivize development of this spur line. He recalled hearing estimates between $300 million and $500 million, surmising most players don't have balance sheets that allow financing it. Thus the state may have to take a more active role in developing this. 9:57:46 AM ^Bob Loeffler, Morrison & Foerster, Counsel to the Governor BOB LOEFFLER, Morrison & Foerster, Counsel to the Governor, added that a recent U.S. Department of Energy study indicates what tariff costs would be - at various pipe sizes, volumes and flow rates - from Fairbanks to Southcentral Alaska. It shows flow rates from 100 to 1,200 in 18-, 20-, 24- and 30-inch pipe that might illuminate the discussion. He emphasized that the state is proposing to make available, for some bidding process or otherwise, a portion of the state-owned gas to satisfy in- state needs. The precise mechanism is being worked on. 10:00:14 AM ^Dave Van Tuyl, BP DAVID VAN TUYL, Commercial Manager, Alaska Gas Group, noted BP said yesterday in Fairbanks that it would love to sell gas to Alaskans, rather than having to transport it thousands of miles to Chicago. In competing for that market, he noted, one competitive challenge is that the State of Alaska isn't subject to federal income tax. ^Bill McMahon, ExxonMobil S.A. (BILL) McMAHON JR., Commercial Manager, Alaska Gas Development, ExxonMobil Production Company, agreed. He added that competition among suppliers benefits the buyers. CHAIR SEEKINS noted later Mr. Heinze would discuss in-state consumption and transportation. He related his impression that there'll be competition to supply that market from the state and perhaps from the producers. It will be looked at in the free market. People would like to heat their homes at a savings, and this will respond to it. MR. VAN TUYL added that Article 9 of the contract addresses in- state use, including four offtake points. The state has identified where three are likely: on the Yukon River, in Fairbanks and in Delta Junction. The contract also requires mileage-sensitive service for in-state use. Those will facilitate getting gas to in-state consumers. He highlighted two other things that the mainline entity, the pipeline, is obligated to do during the first couple of years of the project: 1) complete a study of in-state consumption, characterizing what the market might be in Fairbanks and Southcentral Alaska, for example; and 2) complete a study of the potential for siting the natural gas liquids (NGLs) extraction facility in Alaska, and the business opportunity this might create. Clearly, Mr. Van Tuyl said, there is a recognition of the business potential for in-state sales, and there are specific commitments in the contract to address those. REPRESENTATIVE PAUL SEATON, Alaska State Legislature, returned to Mr. Marks' scenario of $5.30 in Chicago, subtracting a $2.50 tariff, leaving $2.80 as if sold in Chicago; if it went to Fairbanks, $0.25 would be added, for a price of $3.05. However, there was nothing about having to pay for the FT commitment, the $2.50 tariff. If that were subtracted because the gas wasn't shipped, it would be sold at $0.55 to the state. He asked: Is the basic assumption just that before we sell any in-state gas, we will meet our shipping commitment? Or are we just going to ignore that $2.50 price that we've guaranteed, even if we don't ship the gas, or if other gas doesn't come available at the beginning there? MR. LOEFFLER answered that the open season on the mainline provides two different bidding opportunities. The first is for in-state service, calculated on the cost of providing that service, not costs downstream. There would be an FT commitment for that, separate from the rest of the state's share. There are two different bidding tracks, by Federal Energy Regulatory Commission (FERC) order. A commitment in the open season for in-state use isn't a commitment for the long haul. 10:06:21 AM MR. CLARK listed needed actions: 1) Obtain the report mentioned; 2) get the state's house in order with respect to policy decisions on pricing that he'd mentioned; and 3) get this information out to deal with Alaskan companies that want to take gas, prior to the first open season. The planning must be arranged in time to do this. The producers will design the line based on the state's offtake before it moves to Canada and the Lower 48. The administration is eager to get a contract in order to have something to work from, Mr. Clark added, and then to get the other pieces in place in order to address these policy decisions in a systematic and orderly way. MR. LOEFFLER referred to discussion of balance sheets and the ability to bid in an open season. He emphasized no money is paid for in-state FT commitments until perhaps five years later, when it is up and running. This provides time to get arrangements in place, although the commitment to reserve that capacity in the open season must be made. 10:08:35 AM REPRESENTATIVE SEATON noted FT commitments increase the internal rate of return; it is a FT commitment of 20 percent to Chicago. He asked how it works if there is offtake for in-state use. MR. VAN TUYL replied the purpose of the open season is twofold: 1) to demonstrate the need for public convenience and necessity, the basis for the permit, and 2) to establish the design of the system, demonstrated by what customers want at the open season. If the state or the producers chose to take gas off in Fairbanks to serve Fairbanks and Southcentral Alaska, the pipeline downstream of that offtake point would be designed differently. Since there wouldn't be the need for that additional capacity downstream of Fairbanks, the state wouldn't be taking out the full share of the FT commitment to Chicago. MR. MARKS elaborated, posing an extreme situation in which the entire state share is taken off in Fairbanks, both for use there and to disseminate via spur lines. The state would have no FT commitment south of Fairbanks. While the producers would have 100 percent of that commitment, everything going down the line would be theirs; thus the rate of return would increase. While the contract says the state will own 20 percent of the pipeline, Mr. Marks said it would make sense at that point for the State of Alaska to divest that share of the pipeline; it would make sense for everyone to have about the same percentage share of both the pipeline and the gas itself. 10:12:21 AM MS. KING added that Article 10, the capacity-management provisions and specifically Article 10.1, envisioned the scenario Representative Seaton had mentioned, and a term was defined for "state export gas." During its initial-capacity notice, the state could send notice that it wanted to deliver 300 million a day within Alaska from its total 850 million a day. She indicated the company then would get long-haul capacity to Alberta, Canada, consistent with the 550 million a day that the state wanted to take to the Lower 48 market. REPRESENTATIVE RALPH SAMUELS, Alaska State Legislature, pointed out if ConocoPhillips' LNG plant and the Agrium plant were discounted, the actual amount of gas that Fairbanks or Anchorage would use is small compared with the total gas contemplated. MR. MARKS concurred, adding if the state's share of in-kind gas were to meet all in-state needs, there still would be some shipped to Alberta. SENATOR BEN STEVENS reported yesterday he'd called ENSTAR for estimates on in-state consumption. Including commercial use, it is 200 Bcf a year, though it varies by season. If every home in Fairbanks changes to gas, it might add 10 Bcf; power generation could add 15 Bcf. Thus it might rise to 225 Bcf a year. Multiplying 900 million cubic feet a day - the amount to be shipped - by 365 days equals 325 Bcf a year for state gas. He said the largest consumer is utilities, but Municipal Light & Power (ML&P) owns its own gas and won't buy from the North Slope. He opined that satisfying in-state demand doesn't justify transporting gas to the Southcentral market, but would only work if there were additional commercial use through export or large industrial operations. Highlighting the complexities, Senator Ben Stevens suggested in-state gas doesn't need to be addressed unless it is certain that gas will flow to an offtake point. 10:17:24 AM Ken Griffin, Deputy Commissioner, Department of Natural Resources KEN GRIFFIN, Deputy Commissioner, Department of Natural Resources (DNR), said in-state use has been a priority for the state negotiating team throughout, balanced with getting this project built. He proposed that four pieces need to come together to meet in-state needs. The first two are: 1) contract terms, including a commitment on the part of the Alaska gas pipeline to cooperate with respect to downstream in-state projects once they are viable; and 2) policy calls beyond the contract, which include a) ensuring this pipeline is built as soon as possible, on time and on budget, b) issues related to pricing such as the netback-pricing concept talked about by Mr. Marks and c) how the state will deal with issues relating to credit support. He cited the third and fourth pieces: 3) infrastructure, including a) offtake points and spur lines to Anchorage and Fairbanks, b) NGL processing for export or to provide fuel supplies to remote locations and c) FERC requirements such as regulations and rules the state must work with, as well as FT commitments and the credit requirements that go with those; and 4) in-state commercial interests, including public and private utilities of various capabilities as well as commercial and industrial users. Mr. Griffin said all these issues need to be dovetailed., and the interests must work together to produce an overall strategy for moving forward. However, the burden cannot be carried entirely in the contract or entirely by the state. 10:22:04 AM SENATOR BEN STEVENS encouraged reading the executive summary from the federal Minerals Management Service (MMS), provided by Mr. Griffin, about a royalty in kind (RIK) program initiated by the federal government in 2004. Managed by bid, it applies to perhaps 13,000 leases. He referred to part 4.1, suggesting the state could do something similar under an open-bid process. MR. GRIFFIN emphasized the MMS experience: There hasn't been a net cost to taking royalty in kind, whether for gas or oil; rather, MMS has seen a benefit. He highlighted the state's contrasting assumption, when converting from the status quo to taking gas in kind, of significant marketing costs built in to the economics. Also, MMS has rather small gas volumes for its program, distributed in different areas; nevertheless, it has seen rather high demand for its gas, with multiple bidders. He highlighted the potential for added value for the state because of the significant position it will have in its markets. 10:27:46 AM SENATOR JOHN COWDERY, Alaska State Legislature, gave his understanding that offtake shunts are proposed for the Yukon River, Fairbanks, perhaps Delta Junction and two in the Glennallen area. He asked about tariffs for those and whether such tariffs are set by FERC. MR. LOEFFLER responded that FERC's open-season orders say there will be a separate tariff for service in Alaska, based only on the cost of delivering that service. It is mileage-sensitive. Unlike for TAPS, FERC sets the rates on the main line for offtake in Alaska to the point where it joins a "lateral" to Cook Inlet. Thus the main line is all federal jurisdiction. If done in the open season, it won't be paid all the way to Chicago, but will be paid to Delta, for example. SENATOR COWDERY asked what effect there would be on tariffs or the cost of gas to Alaskans if the governor's proposed 20/20 system [20 percent tax on oil, with a 20 percent credit] were changed to a gross-based system. MR. LOEFFLER deferred to the production tax (PPT) team. MR. GRIFFIN surmised once the infrastructure is together, the price will tie to the North American market prices minus netbacks and so forth, and thus the PPT will have little effect on Alaskan gas prices off the main line. In this scenario he predicted there'd be a pricing mechanism that nets back to the North Slope and then adds the actual tariff - the cost to get the gas to Fairbanks, Anchorage or wherever it is going. "So I would think the answer would be none," he concluded. SENATOR ELTON asked how far upstream MMS takes its RIK gas. MR. GRIFFIN replied in most cases MMS appears to take it upstream and sell it there. He agreed it isn't clear in the document he'd provided. MR. VAN TUYL gave his understanding that the federal lease form is substantially similar to the State of Alaska form, which would imply the point of taking. SENATOR BEN STEVENS noted page 3 says 19 purchasers bought gas in 2005, with sales supported by 43 transportation, processing and miscellaneous service contracts. He interpreted it as a combination of all points. MS. KING conveyed her understanding that until recently the federal government didn't authorize MMS to take long-term shipping commitments. Thus she surmised MMS wouldn't have been the full transporter on the pipeline and would have delivered the gas upstream of the pipeline system. With the Rockies Express line, the new pipeline from Wyoming to Ohio, however, MMS just took out a FT commitment for more than ten years; she didn't know where the delivery on that pipeline would be. The committee took an at-ease from 10:34:36 AM to 10:46:31 AM. Harold Heinze, CEO, Alaska Natural Gas Development Authority HAROLD HEINZE, Chief Executive Officer, Alaska Natural Gas Development Authority (ANGDA), Department of Revenue, gave his background as a petroleum engineering graduate, in Alaska since 1969, who participated in developing the Prudhoe Bay field; was chief of staff in 1975-1977 for ARCO's negotiating team in the Prudhoe Bay Unit operating agreement; was an ARCO executive; and was the DNR commissioner. He explained that ANGDA, a public corporation of the state, has a mission to do anything it can to bring North Slope gas to market and to ensure benefits to Alaskans. Thus ANGDA has looked at issues of delivering gas to a spur line to the Cook Inlet area, while not insensitive to Fairbanks. His knowledge of the contract began May 10, before which he was outside the confidentiality fence. Since the state may live with it a long time, Mr. Heinze suggested thinking about possible future problems when reading the contract. MR. HEINZE recalled testimony that perhaps four items are in play for in-state use; the contract is just one. Not having the limited liability company (LLC) agreement creates a difficulty because it will discuss longer-term management and so on. While there are past state policies, a new direction may be desired. He acknowledged the aforementioned will be addressed. Although Mr. Heinze said he'd like less concern about industrial users in Alaska, they help pay the bills and are important. And though ANGDA has participated in the FERC process, it has interacted a lot with RCA, an important part of the process as well. He emphasized making in-state use of gas a reality. Mr. Heinze assured listeners that whatever he describes in the contract, he believes it is fixable. Without the contract and the main pipeline, a lot of other things cannot happen. Thus he would talk about how to make it work. 10:51:52 AM MR. HEINZE noted this is more complicated than what exists in the contract. For example, the commitment of consumers and utilities is significant, perhaps $40,000 per household. Boards of directors will make "bet your company" types of decisions with less-than-perfect information, in short timeframes. He suggested that carrying forward with only the contract makes this process difficult if not impossible. The state can play a major role in solving this, as can the contract. For example, the contract should recite all items in FERC's rulings that are important to the state. In portions dealing with regulation, RCA needs to be involved, placed up front; it is an integral part of the process, and the pledge of the utilities and customers cannot occur without RCA approval. 10:55:19 AM MR. HEINZE expressed concern about how "state" is defined in the definitions section, since there are items he wouldn't want ANGDA to be bound by. He asked whether the Alaska Permanent Fund Corporation or the Department of Law's public utility advocacy section would similarly want to be bound, for example. Assuming no intention by the parties for the contract to discourage the in-state process, he nevertheless urged eliminating unintended consequences to the extent possible. He highlighted disagreement about how quickly an open season might happen. Mr. Heinze pointed to the sponsor group's application and the state's fiscal interest finding (FIF), which have an open-season process starting six months after a deal is struck. However, a number of things in the contract must be done before an open season is begun; these have very short timeframes. Mr. Heinze suggested further efforts by all to determine what is needed to make this work. He mentioned threshold issues, reporting ANGDA has done its best to get utilities involved and interested. If in-state users don't come forward aggressively with commitments during the open-season process, they may lose current advantages through FERC rules and so forth. This also would make the situation difficult for the state as a manager of both its sales and capacity in the pipeline. Someone who waits to enter won't necessarily receive the same treatment as if there were initial participation, Mr. Heinze cautioned. MR. HEINZE noted of the 200 Bcf a day used in Alaska now, over half is by industrial customers. One is ConocoPhillips and Marathon's Kenai LNG plant; nothing on record indicates what they want to do with that, although it's half the volume. Agrium, a major player, has a project under study but may not be interested. That leaves the "power and heat people". He referred to testimony that ML&P may not be interested and has gas. Mr. Heinze said he'd like to talk to ML&P's board about fiduciary responsibility, since he'll be upset if that supply runs out in 2018 and his lights go out. Also, he asked who would speak up in Fairbanks or on the Yukon River, where ANGDA believes extraction of propane is extremely important and practical - although he wasn't sure how it would work under the contract. He asked: Will the state provide that voice somehow? 11:00:42 AM MR. HEINZE suggested state and U.S. policy makers need to think about long-run concerns. He mentioned tax agreements and the contract, which speaks to incentives and support for certain portions of the project, for instance, on the North Slope. He recommended they look at extending such support and incentives to the distribution system within Alaska as a fairness issue. Those will have a bigger impact on delivery costs than anything else, Mr. Heinze predicted. He cautioned that ANGDA considers studies of in-state needs and NGL processing highly important, and has participated and funded them. Mr. Heinze expressed concern that the contract has the state giving up a major portion of its say on this, in contrast to the current situation. Referring to discussion of possibly extracting all NGLs from the state's 20 percent of the gas stream, Mr. Heinze gave his "cold read" of the contract that it might be difficult to do - although it is a great idea and that flexibility is needed. He emphasized retaining the ability to actually make that happen. MR. HEINZE closed by recommending looking at some bigger aspects of the contract - recognizing there are implementation issues - and giving it a chance to be straightened out. He suggested the legislature doesn't need to make a decision on this right now, but it is something to acknowledge while interacting with the administration on bigger issues. Mr. Heinze added he would try to work in a positive way. 11:03:52 AM CHAIR SEEKINS asked about the $40,000-per-household commitment. MR. HEINZE replied if Chugach Electric wants North Slope gas, for instance, it would pay a price at the wellhead; would pay to transport it through the big pipe to somewhere in Alaska; and then would pay to transport it via smaller pipe to Anchorage. The total, based on numbers in the FIF, would be $5.50 per Mcf, which Chugach Electric would execute a take-or-pay or ship-or- pay contract; he mentioned 75 percent of the gas needed, noting it would be for 15 years, a term chosen because it seemed to strike the right balance. He predicted total commitments for all utilities in Alaska would exceed $6 billion. Many companies don't need 75 percent of their volumes on day one. There are issues in crossing the threshold. If volumes aren't up to a certain point, the Fairbanks hookup might not happen or the spur line or Yukon River facility might not get built. When the math is done for both ENSTAR, the gas-heating supplier, and for the area's electric utilities, it totals $40,000 per meter. If only one of those is used, it is $20,000 to $25,000. Mr. Heinze indicated ANGDA is developing a related table for all the companies. 11:06:43 AM MR. HEINZE, in response to Representative Rokeberg, clarified that the 200 Bcf a day is for all Alaska now; projected is 900 million cubic feet a day times 365 days, more than 300 Bcf a year. He estimated one-quarter of the state's share would satisfy in-state utility-type companies, but not industrial users. While those are big enough companies to probably take care of themselves, individual utilities aren't necessarily big enough to make the deal work. REPRESENTATIVE ROKEBERG mentioned alternative energy sources such as wind generation in the Cook Inlet region. He asked about the need to reach a critical mass of consumption in order to put together a project such as this. MR. HEINZE affirmed that, but said more fundamental is that people need to make decisions about alternatives. There isn't always control of timing. For example, people may install wind power over a short period of time, which won't solve the whole problem but likely is a reasonable step. Furthermore, higher prices are forcing conservation to happen already and will cause explorers in this area to be more active. He highlighted a cautionary book title: "Hope is Not a Strategy." Mr. Heinze noted in the intermediate term, coal will be a consideration in this area that some may opt for. However, ENSTAR needs gas in its system and Chugach has a huge gas-fired power plant that likely won't go away; thus gas will be needed in the area. He expressed great concern that companies won't make the aggressive commitment required to build a spur line. If the threshold isn't crossed, the opportunity may be lost. 11:11:05 AM MR. HEINZE, in further reply, said the Yukon River crossing will be right on the pipeline and will depend on wholesalers, others who move propane up and down the river system. He predicted the state won't have much of a role there, other than trying to help it come into being, since it might be a chancy investment for a company. If the state wants it to happen, it will need to provide a line of credit or something else will need to happen. He also noted Fairbanks is well located along the line. However, Golden Valley would have to make a substantial investment to bring gas to the new power-generation facility, for example. Mr. Heinze surmised that would be a solid investment, better than using oil associated with the refinery. It would be a major commitment, though. As for gas piping within Fairbanks, how it is done will be up to people. Whether in Fairbanks or Delta Junction, it's hundreds of miles from there to Cook Inlet, with a price tag estimated at $.75 billion. 11:13:49 AM CHAIR SEEKINS remarked that there'll be no spur line without a main line. MR. HEINZE said that's why he supports moving forward. He expressed appreciation for the time the participants are taking to understand the difficulties of making this work, and he said the state must be a player. In further reply to Representative Rokeberg, he said ANGDA has looked at the "rule of aggregate." He mentioned pooling, for instance, and whether a line of credit could be provided to back up financial guarantees if necessary. Many roles could be played. Mr. Heinze also indicated a right- of-way is the key to the physical step of building a spur line, but other things can be done, financially or with respect to FERC in Washington, D.C. and so forth. 11:15:56 AM SENATOR STEDMAN surmised whenever the gas industry penetrates a new area the infrastructure must be built from scratch. He asked whether there is a model to replicate or modify somewhat. MR. HEINZE answered that part of the difficulty is the size of the market in Alaska. A lot of stranded gas was found in Cook Inlet when looking for oil, providing a generation's worth of plentiful and cheap gas. Unfortunately, it is running out. If there were industrialization, fed by gas through this pipeline, it could be fairly attractive. But there isn't that commitment or announced intentions. The market is small for people who just want home use, compared with the size of the undertaking. SENATOR STEDMAN asked how much flexibility there is within the industry for modifying the length of FT commitments. MR. HEINZE replied that actual day-to-day workings differ from the upfront commitment during the open-season process. That process is like a sealed-bid auction; the bid can be rejected if it is believed it isn't backed up. In addition, whatever comes out of the open season becomes a major factor in the pipeline design. He noted the FERC order says if nobody comes forward in Alaska, it is under no obligation to design the pipeline to permit that to happen. "In other words, if we don't bid - we come up with a zero bid - we're done," Mr. Heinze said, noting this doesn't preclude trying to negotiate a deal in the future. There wouldn't be a deal under the favorable terms associated with the initial open season, however. 11:20:57 AM MR. LOEFFLER referred to his own testimony in Fairbanks yesterday. He concurred with Mr. Heinze that it's critical for in-state users to prepare to make commitments by the time of the open season. While there are some modifications possible, someone would be in a much worse position otherwise. Mr. Loeffler predicted timing would be much later than Mr. Heinze had indicated, though. He highlighted October 2004 federal legislation, saying there is no question RCA would regulate the spur line; it isn't affected by the proposed contract. However, the spur line conceivably could be financed like the main line, meaning there'd be an open season for it. An in-state user would have to bid for capacity on the main line to the offtake point and then have a coordinated, smaller bid for the spur line. As for how long those commitments would be, Mr. Loeffler said it wasn't known yet. Nor did he know whether RCA had established or contemplated an open-season process for an in-state line. Regardless, RCA would have to accomplish its part of the job and be lined up with FERC; otherwise, there could be capacity that connects to nowhere within the state. 11:23:28 AM SENATOR STEDMAN clarified his concern. The obstacles are so large, Alaskans could be without gas while it goes out of state. He asked how to work together with the state, the industry and small utilities to give them the opportunity. He'd like to see a gas-based petrochemical industry in Alaska, for instance. MR. CLARK drew a distinction between what is addressed in the contract and what isn't. The contract minimizes the state's risk from being an owner. Citing Article 10, he noted the state will ride the producers' coattails on such things as capacity. The state is partners with them in a business, and is minimizing and mitigating its risk because the producers won't want to do something stupid. Thus the state's 20 percent is safer because the capacity article gets the gas to market and then the state can hire aggregators who are experienced in this area to sell the gas on its behalf. In each case, the state is riding on the producers' coattails. He contrasted that with issues outside the contract. The state could enter into business by itself to get gas to in-state utilities; that policy discussion needs to occur. Pricing needs to be figured out, as well as other issues raised by Mr. Heinze. The contract leaves flexibility to the state to address such policy issues as it sees fit, Mr. Clark noted; that decision- making ability is part of the virtue of taking gas in kind. Because of the importance of bringing gas to Southcentral Alaska, the state might want to provide financing, for example, so other distributors don't have to take FT commitment risks. MR. CLARK clarified that the intention is to have these policy decisions enhanced, not hindered, by the contract. Such decisions need to be made by the legislature and the executive branch, working together, as a whole set of other policies. But the contract isn't intended to be the mechanism by which these policies are addressed. He agreed with Mr. Heinze and Mr. Loeffler that the state must figure out the order in which to make these decisions, trying to get it done prior to the open season. Mr. Clark also agreed with Mr. Loeffler on timing, predicting the open season will be perhaps two or two-and-a-half years down the road. While the state is retaining the ability to take on those decisions, it's a different deal if the state wants to take the risk of running a business that doesn't ride on the coattails of the producers. 11:28:42 AM MR. VAN TUYL followed up on timing of the open season. He indicated BP's application and Project Summary both contain a Gantt chart that simplifies the open-season process; he mentioned a starting time about six months after the ink dries on the contract, continuing about two years. The actual open- season event described by Mr. Heinze is at the tail end of that process. He noted there is much planning and development of the actual tariff and cost of service, for example, before the open season. People don't have to make a decision within six months, he emphasized. It could be two years or more. MR. HEINZE reported that ANGDA has worked with RCA and sent in a series of statutory changes intended to make the process work better. However, his experience is that such consideration takes up to a year. While it might help to open a docket with RCA well in advance, the problem is this: On the in-state part, it has to be brought to folks without knowing whether they'll pay $0.75 or $2.50, or if it will cost $1.00 or $3.00 from Glennallen to Anchorage. Boards have to make responsible fiduciary decisions, but there is a large range of uncertainty; this will present a doubly difficult problem for RCA to approve these charges as a direct pass-through to the customers - an essential step for any cooperative or board. 11:31:32 AM REPRESENTATIVE SAMUELS asked: If there is no main line, assuming Cook Inlet's decline continues, have you modeled what it would cost Southcentral consumers to import LNG, provided ConocoPhillips could turn its Nikiski facility around? MR. HEINZE indicated ANGDA had published a study exploring options for the Kenai LNG plant in the long run. It shows there probably are good economics in terms of turning the plant around. The charge associated with a regasification facility would likely be in the normal range for that type of service, perhaps $0.75 plus or minus; this would be added to the price for bringing in gas from Indonesia, for example. Though there would be some challenge in moving the gas to Anchorage under the existing system, it likely could be done with some investment in the long term. He emphasized that the problem is being at the mercy of the LNG source and a transportation system "that we ought to feel uncomfortable about." CHAIR SEEKINS acknowledged there may be conflicting interests among communities, but cautioned against arguing about these so hard that the main objective - building the project in the first place and providing gas to those lines - is forgotten. 11:37:41 AM MR. MARKS pointed out that the FT commitment faced by utilities on a gas-purchase contract is profoundly different from that a producer faces in building a pipeline. For the latter, all costs are laid out up front. On a purchase agreement, however, costs are streamed out over a number of years. The $5 billion reflects the purchase price for gas as if bought on day one. Timing is everything financially. If those gas-purchase agreements were put on a net-present-value basis, as a credit- rating agency would do, it would be much less than that. He noted as soon as a utility enters into a gas-purchase agreement, it has a liability plus a tremendous asset. The main risk is from buying too little or too much gas. In Cook Inlet, that risk will be alleviated to the degree there is an increase in storage facilities. Mr. Marks also noted Lower 48 utilities have such challenges all the time, and the market seems to figure it out just fine. If this is a big concern here, he recommended inviting the utilities for a discussion. MR. CLARK opined that the place to begin this discussion is in the FIF. It isn't a contract issue. The administration doesn't believe it is appropriate to pledge to have this contract enter into new business. Some decisions must be left to the legislature. He said the contract doesn't preclude such decisions, but enhances them and moves them forward. 11:41:15 AM MR. HEINZE reported hearing from people in relation to the gas line that they want jobs, a better economy and gas, whereas management of the resource appropriately focuses on revenues to the State of Alaska. He emphasized he wants his discussion to be viewed as reassurance that some people are honestly worried about this but believe it can be made to work. He highlighted getting the contract into a public-acceptance mode. MR. CLARK emphasized that the project - the gas line overall - has a number of steps including this fiscal contract, which sets fiscal terms between the State of Alaska and the producers. He indicated the administration's findings have been in line with ANGDA's, that in-state use is a key element. However, it involves legislative decisions that the administration doesn't have authority to make in this contract. SENATOR BEN STEVENS posed a positive hypothetical situation of a gas-processing facility being placed at the Yukon River to put condensed gas into the pipeline from the Chulitna Basin or Nenana Basin. Fairbanks would have the cheapest gas in North America. He emphasized the tremendous potential for hydrocarbons in Alaska that won't be marketable or monetized without a market destination with capacity to absorb the supplies. The committee took an at-ease from 11:45:24 AM to 1:21:00 PM and another brief at-ease until 1:23:41 PM. ^Roger Marks - Discussion of proposed reserves tax MR. MARKS discussed the proposed gas reserves tax (GRT), noting his analysis encompasses several contexts. He provided some history showing why North Slope gas hasn't been commercialized and thus why the gas line hasn't been built, and whether it is appropriate for the GRT to be used to punish the producers for not having built it yet. He began by saying Prudhoe Bay was discovered in 1967, when a large gas cap was found on top of the oil - about 26 trillion Tcf. It started up in 1977. Ever since, the producers and Alaska's citizens have been looking at a way to commercialize it, either in Asia or the Lower 48. In particular, Yukon Pacific Corporation (YPC) had been interested in the Asian LNG market, using a pipeline to Valdez, and was active in the 1980s and until a few years ago. He recalled that Asia initially made sense as a possible market, since prices were higher than in North America. It didn't work out for two reasons. First, Asia's gas market works on contracts, rather than an open market; generally, the low bidder wins. Alaska, which required an 800-mile pipeline, couldn't compete with closer jurisdictions or those with gas sitting at tidewater. Second, large economies of scale are needed for an Alaska pipeline to work - large enough to ship 4 Bcf a day in order to lower the per-unit price. However, gas demand in Asia was growing slowly, averaging about 0.4 Bcf a day from 1977 to present. Even if Alaska had captured 100 percent of that market, it would have taken ten years to fill the pipeline. Mr. Marks offered his belief that those problems still exist. MR. MARKS explained that until year 2000, North American gas prices were too low - between $1.50 and $2.50 - to justify the cost of a pipeline. Noting a handout contains a graph showing North American gas prices, Mr. Marks said with a $2.50 tariff, money would be lost in shipping gas to North America. Thus it didn't make sense to consider it as viable. Since then, however, prices have shot up due to market conditions. He reported in 1998 the sponsors formed an LNG sponsor group consisting of ARCO; Phillips; Marubeni; Foothills; and YPC, which withdrew because the group wanted to study Kenai as a terminus as well as Valdez, when YPC only had permits to Valdez. After YPC left, BP joined. In 1998, the group spent $12 million studying the Asian market. However, the basic landscape was unchanged. In 1998 the Stranded Gas Act was structured for LNG. Modified a few years ago to include a pipeline project, it sets out a process to try to commercialize the gas. MR. MARKS noted the gas reserves tax has been characterized as a way to take a 2x4 to the producers to get them to build a pipeline, with the assumption they're not interested. However, the producers have done quite a bit since 2000. In 2000-2001 they put together a $125 million engineering study. Primary, however, has been setting up government frameworks, establishing the rules so those are known when they spend $25 billion. Since 2000 the producers have obtained federal enabling legislation from Congress, which set out a regulatory regime; secured FERC regulations; received significant tax breaks; gotten the Stranded Gas Act reauthorized; put in the Stranded Gas Act application; and negotiated the Stranded Gas Act over the last two years. Thus they've done quite a bit. 1:30:56 PM MR. MARKS explained that meanwhile, since 1977, the gas has been hard at work at Prudhoe Bay. The Alaska Oil & Gas Conservation Commission (AOGCC) estimates use of gas in Prudhoe Bay has resulted in recovering another 3-5 billion barrels of oil; thus 25-50 percent of oil there is directly attributable to using gas. If 4 Bcf of gas a day had been vacated beginning in 1977, much less oil would have been produced. He opined that the project didn't begin to make sense until 2000. Thus a GRT would punish the producers for a "crime" they didn't commit or that doesn't even exist. He discussed how the GRT may affect the project and why it was addressed as it was in the contract. Starting January 1, 2007, any lease or unit with more than 1 Tcf of gas - in a state unit, on a lease in existence for at least ten years - would pay about $0.03 per Mcf. Leases that qualify are Prudhoe Bay and Point Thomson, and Kuparuk and Lisburne also have about 1 Tcf each. It is predicted to cost the producers $1 billion a year. The tax would stay in place until gas starts flowing into North America, perhaps 2016, after which there would be a credit for past reserves-tax payments, capped at 50 percent of the production tax; that goes until 2030, at which time about 45 percent of the reserves tax would have been recovered. He pointed out if the project were delayed, that percentage would be much less. The GRT would be front-end loaded, whereas recovery of the credit would be back-end loaded. Mr. Marks said even if the producers guaranteed 100 percent they'd build the pipeline - which it doesn't make sense to do because of contingencies relating to prices or costs - the GRT would be unavoidable. They'd even pay it while laying pipe. 1:35:19 PM MR. MARKS focused on how the gas reserves tax would affect the producers. If oil pays for it and prices go back down to $15 a barrel, they'd pay $1 billion in addition to the PPT tax that he expressed hope would pass soon. What if gas pays the tax? Taxes would be paid up front and, at most, 45 percent would be recovered later. Financially, the GRT would reduce the rate of return and the net present value of the project by about one- third. Financially, it equals a $2-per-million-Btu price reduction or a $14-billion cost increase for the project. He turned to how this would affect the investment climate. Leases in effect less than ten years wouldn't pay the gas reserves tax. But until gas actually starts flowing, when that would happen isn't known. There is a risk that an explorer for gas might find it and then be subject to the GRT if the project were delayed. Accordingly, Mr. Marks put forth the belief that exploration for gas would cease. The project needs about 50 Tcf to be viable, and about 35 Tcf has been discovered. If there cannot be exploration for the additional 15 Tcf before the open season, the pipeline might need to be scaled back, thereby increasing the unit costs. Thus Mr. Marks predicted there'd be no exploration for gas until the pipeline started. He also asked who'd look for oil, since gas might be found. Mr. Marks predicted a good chance that exploration would cease entirely if the GRT passed. He also warned if voters likewise imposed a reserves tax on heavy oil, investors could react to this; it would punish companies if gas prices were very low, for example. It also would create a disincentive for the gas line if the state could just sit back and collect $1 billion a year. Furthermore, it could force the producers to rush the project, with the incumbent risks of quality and cost control. MR. MARKS referred to testimony by Dr. Pedro van Meurs and Econ One that no other jurisdiction has had a structure like this proposed reserves tax, which will send a message internationally and hence could cut investment drastically. He said there are constitutional questions as well, which he wouldn't go into because he wasn't a constitutional attorney. He highlighted the Stranded Gas Act, reporting the contract immunizes the producers from paying it because of the effect on the project's forward movement as well as the necessity for fiscal certainty for this project - the correct balance of downside and upside risk and potential. If the upside is taken away with higher taxes, the symmetry is thrown off balance. If ballot measures can come in and raise taxes after the fact, Mr. Marks said, there isn't fiscal stability; that is why it was treated as it was in the contract. 1:40:30 PM SENATOR COWDERY surmised a GRT would result in a long delay and lawsuits. He also asked what the price of gas would be after the pipeline opens in eight or ten years and it brings large amounts of gas to the Midwest market. MR. VAN TUYL responded that the price is unknowable, even a year from now. The focus is on managing risks where possible, including capital costs. However, the biggest cost to investors like the producers is the government take, which requires a fiscal contract to manage. He recalled that was recognized by the legislature in passing the Stranded Gas Act, which establishes a stable framework on which those investments can be made. He predicted this Alaska gas pipeline project will come as no surprise; folks will manage their gas purchase-and-sale contracts to anticipate this gas, as when the last big pipeline, the Alliance pipeline, came to the upper Midwest a few years ago. He noted the North American market is the biggest in the world and growing. He turned to the proposed reserves tax. Saying BP is serious about going forward with an Alaska gas pipeline project, he highlighted BP's activities, mentioned by Mr. Marks, as well as attempts relating to LNG in the 1980s. He also brought attention to comments by BP chief executive office John Browne in the Wall Street Journal in May. Mr. Van Tuyl agreed it was good that BP wasn't selling gas when the market price was $2.00 or $2.50 but the cost to move it to market was greater than that. Only since about 2000 have those conditions changed. MR. VAN TUYL opined that a GRT is fundamentally bad policy, contrary to the spirit of the Stranded Gas Act, which recognized the need for fiscal stability to attract investment. It circumvents the process to modify lease contract; would penalize investors even when performing exactly as the state would want them to, advancing the project and spending billions of dollars to bring this gas to market; is unprecedented worldwide; would send a real chill to investors; would signal an unpredictable, unstable regime for investment; and may result in an early impairment of Alaskan assets. Mr. Van Tuyl reported having figured it would provide 40 percent possible recoupment, fairly close to what Mr. Marks came up with. He cautioned this could cripple the entire industry. 1:48:36 PM SENATOR HOLLIS FRENCH, Alaska State Legislature, asked about indemnification provisions in the contract with respect to the GRT. He surmised the state would be the guarantor or payor if such a reserves tax were instituted. ^Dan Dickinson, CPA, Consultant to the Governor DAN DICKINSON, CPA, Consultant to the Governor, suggested starting with the definitions in the contract. Noting "tax" is defined in the May 24 version of the contract on page 60, he said under (c) it is established to include a tax from an initiative, and under (i) it includes a reserves tax. Article 11.2(c), page 214, talks about payment obligations, saying each participant accepts all taxes levied by the state on its oil- and-gas-related business activities in Alaska, except for those six taxes identified in Article 11.2(a). It further says a participant may exercise its exemptions under Articles 11.2(a) by withholding payment to the state, or by paying the tax and obtaining reimbursement from the state under Article 22. 1:52:22 PM MR. CLARK asked whether Senator French was asking about the policy behind it, as well as the mechanism. SENATOR FRENCH answered it seems the contract exempts the participants from a GRT. But if one is imposed, it allows them to either not pay it or to ask the state to pay it instead. He remembered presentations indicating the GRT would take money out of the industry's pocket and put it in the state's. MR. DICKINSON recalled that Mr. Marks' discussion related to what happens if there is a reserves tax but no contract. This would be a tax, but with an exemption under the contract. SENATOR FRENCH asked whether the contract is viewed as providing an indemnification or nullification. MR. CLARK replied the administration sees it as an exemption. He noted Mr. Marks had described what will happen to the project if the GRT is in place. The contract protects the project from that result. The reason relates to timing. Once this gets unleashed, a long period of litigation is envisioned about what a reserves tax is or isn't, and the project would be harmed, including the economics and the investment climate. He specified if the contract is completed and the GRT passes, the effect is this: If the producers don't advance the project diligently, as prudent under the circumstances, and if the project is terminated, then the GRT can go into effect, since that exemption will no longer apply. The administration believes this project is so critical to Alaska's future - because a gas line would extend TAPS another 20 years, in addition to the gas provided - that exempting it from the devastating effects of the GRT is appropriate state policy. Mr. Clark surmised the producers would cite the exemption, rather than pay the tax and get reimbursed. 1:57:07 PM CHAIR SEEKINS expressed grave concern about the GRT, that the gas won't get to market but the reserves will be taxed forever. He asked what an additional $6.5 billion in costs would do to the economics of the project. MR. MARKS answered it would reduce the net present value by a third - a massive impact. MR. CLARK mentioned an analysis that the state would make more with a reserves tax than a gas line, $1 billion a year with the former and $400-500 million a year with the latter. 2:01:58 PM MS. KING noted many believe a reserves tax will help make the gas pipeline happen. She countered this by saying the fiscal contract, Article 5, is the mechanism by which all the parties have agreed to diligently advance the project. Also disagreeing the gas has been warehoused, she said gas at Prudhoe Bay has been put to valuable use over the years. Prudhoe Bay produces a lot of gas right now, as well as water. It is reinjected for pressure-maintenance purposes, which allows more oil production, and some is converted to NGLs and shipped south, generating revenue for the state. Prudhoe Bay owners have invested billions of dollars in gas handling over the years to enable additional oil. ConocoPhillips believes the GRT is unnecessary, is unfair and would likely lead to litigation. CHAIR SEEKINS opined that many legislators could support a reserves tax that stacked up over time if a gas line wasn't built but that would be deferred if reasonable progress was made and would disappear once gas flowed. This particular GRT, however, as structured, would make it almost impossible to build a delivery system so the tax could then be discontinued. 2:06:28 PM MR. VAN TYLE, in response to Representative Rokeberg's recollection of Dr. Pedro van Meurs' testimony, agreed the proposed GRT could be tantamount to nationalization, a taking. Mr. Van Tuyl cautioned that it not only jeopardizes the gas pipeline project, but also sends the message that this is an unstable regime. He predicted "forever" would be a very short time. The industry wants to keep oil flowing down the pipe, as does the state; it is important to stem the decline. A reserves tax creates an environment with so much uncertainty that even the base investment, year in and year out, would become suspect. SENATOR BEN STEVENS directed Mr. Marks to page 13 of the document presented this morning, which speaks about unintended consequences of a GRT, including the halting of oil exploration because an explorer who found gas would be subject to the tax. MR. MARKS replied he isn't a geologist, but believes explorers for hydrocarbons often don't know whether a prospect contains oil or gas. Someone drilling for oil who finds gas might be subject to this reserves tax. He surmised a prudent person wouldn't take that chance. SENATOR BEN STEVENS suggested asking those who explore for oil, noting there'd be AOGCC regulations about when a well is delineated, for instance. 2:10:17 PM MS. KING agreed sometime explorers get a good view of whether there is gas, but sometimes it isn't known. Clearly, there is a risk. Now if someone finds gas while exploring for oil, it is effectively a dry hole. The GRT would create a liability in that instance, putting additional risk on exploration. While noting she couldn't comment with respect to the AOGCC rules for exploration, Ms. King said Prudhoe Bay and Point Thomson owners are conversing now with AOGCC to start the process for getting approved gas-offtake rates, in preparation for a potential gas pipeline project. That process needs to be worked through. SENATOR BEN STEVENS remarked this is the first time he has seen documentation that a GRT would penalize further exploration for oil. The state is so dependent on oil for revenues and employment, it is important for people to understand. MR. CLARK agreed with a previous characterization from Dr. van Meurs, that a GRT would be a self-inflicted wound, considering what it would do to oil production. MR. GRIFFIN corroborated Mr. Marks' testimony, noting his own background includes 25 years in Alaska's oil and gas industry, much spent in exploration and exploration analysis trying to find prospects and bring them to the drawing board. He agreed that with a GRT in place, explorers would be much less likely to drill gas-prone prospects. The effect on oil would cascade backwards to when a lease was first put on the table. CHAIR SEEKINS welcomed U.S. Senator Ted Stevens. 2:15:21 PM ^U.S. Senator Ted Stevens U.S. SENATOR TED STEVENS began with an historical perspective and then highlighted the enormous gas potential in Alaska, including gas concentrates beneath the permafrost in the Prudhoe Bay area and well as exploration in other areas such as the National Petroleum Reserve-Alaska (NPR-A). He cautioned against delays, saying the question is whether Alaska's gas gets to the Midwest first with long-term contracts, ahead of imported LNG. U.S. SENATOR TED STEVENS questioned how many people would consider investing in Alaska if the climate for investment were further confused by issues before the legislature now. He said there is a national energy crisis, and the basic economic future is related to the availability of gas for increasing needs. At the national level, the Alaska Natural Gas Pipeline Act of 2004 (ANGPA) was passed. Noting the federal government has studied the feasibility of building that pipeline, he said the bulk of gas to be produced will be on federal lands. 2:24:55 PM U.S. SENATOR TED STEVENS recalled when ANGPA passed, federal agencies contacted him about a 44-month pre-permitting period; added to the 18 months, it would be five years before they could finish with an application for interstate transportation of the gas. Until the owner of the property is willing to have a transportation mechanism, the federal government doesn't have jurisdiction; it has jurisdiction over interstate movement. Thus a group was convened and a memorandum of agreement drafted to coordinate activities and substantially reduce the time, although the actual time hasn't been determined yet. He added if the legislature doesn't act this year, it will be another two years before that period can start, and seven years after that to build the pipeline. At 83 years of age, he expressed hope of seeing the pipeline constructed in his lifetime. He proposed commercializing gas concentrates as well, but predicted unwillingness to put money into that without a pipeline. U.S. SENATOR TED STEVENS reported Qatar has the largest known supply of gas close to tidewater, and Russia has a great deal as well; he'd hate to see the U.S. rely on Russia because its pipeline was shut off in the Ukraine during a political dispute. A supply of energy from Alaska is the safest for the U.S. He predicted if Alaska doesn't act, the federal government might someday, with Congress taking over and telling the state how the gas will be produced and delivered. He urged the state to finish its work on the pipeline. U.S. SENATOR TED STEVENS suggested putting aside politics and deciding what's best for the state. Although the state has a role beyond all others in terms of energy, he cautioned that there is a timeframe for resources. They won't be as valuable someday. The future for Alaska's energy is the next 50 years, he predicted, urging legislators to come together now for this project. He again proposed that the federal government will take action if this doesn't happen. 2:36:47 PM CHAIR SEEKINS recapped today's discussion of the GRT initiative. He requested an opinion on its effect on exploration, development and the potential for building a pipeline. U.S SENATOR TED STEVENS questioned how realistic the $1 billion is. He agreed there would be extended litigation. Why add a delay? And why do it now, when the producers say they're ready to move forward? He again expressed concern that investors might leave if burdens are added. He also recalled California's gas had been flared, whereas in Alaska a law was passed and so the gas was put back into the ground and stored. As for the state's building the pipeline by itself, it would cost more than the permanent fund. Why do that if others are willing to put up capital? He acknowledged this should be regulated to protect the environment and assure a fair rate of return. He reiterated that the future is mainly on federal lands, not state lands. 2:40:28 PM REPRESENTATIVE SAMUELS reported having received figures that show the following: All other things equal, a two-year delay requires a tax rate of 9.25 percent, 25 percent above the 7.25 percent Governor Murkowski negotiated, to obtain the same amount of money. A three-year delay requires an 11 percent rate, almost 50 percent more. This is the cost of delay on a net-present-value basis. U.S. SENATOR TED STEVENS responded that one thing in the works would allow states a portion of revenue from the Outer Continental Shelf (OCS). That hasn't been the case so far, although Alaska gets a portion of royalties from some lease bonuses. The bulk of future revenue will be from royalties. The sooner that starts, the more it accumulates. He expressed commitment to reducing the federal-related time as much as possible, as was done with TAPS for oil. 2:44:02 PM SENATOR BEN STEVENS reported having recently learned FERC has issued permits for two new LNG terminals and the reconstruction of three more, and there are other applications. He asked: What does Congress anticipate with respect to additional LNG terminals? And with increasing movement of LNG using tankers, will Congress seek to modify the Jones Act or provide exemptions to allow the carrying of LNG? U.S. SENATOR TED STEVENS answered that the Jones Act was perhaps the second Act ever passed by Congress. He didn't foresee a permanent waiver for anyone, although he recalled a temporary one. The basis of the Jones Act was to ensure that the country can build its own ships as a matter of defense. He surmised that Act would be maintained. As for problems relating to LNG, he said those have been acute, and an offshore super port concept had been proposed. He highlighted problems with locating regasification facilities onshore and construction of cryogenic tankers. He said LNG can come in easily from other countries on foreign-built ships, but cannot be transported within the country on such ships. Thus LNG from other countries will come in easily and won't require cryogenic tankers. 2:48:30 PM CHAIR SEEKINS asked whether the federal government had concerns about its taking gas in kind. U.S. SENATOR TED STEVENS noted taxes cannot be taken in kind, whereas royalties can. It is a good option that enhances a state's ability to ensure development of facilities within the state that could utilize the gas. He predicted with Alaska's gas potential there will be a substantial industrial base in the state. Current markets are for consumption and agriculture, for example. It is a very good market. He said gas prices will follow oil prices, which he surmised would continue to rise. 2:51:03 PM SENATOR BEN STEVENS asked how Congress views an "over the top" pipeline route that could tie in with the Mackenzie Delta project in Canada. U.S. SENATOR TED STEVENS recalled having commented that building a pipeline across ANWR would be like putting something across the Mona Lisa - it wouldn't be allowed unless offshore, which he believed was explored once. He reported having talked last week to Canadians, including officials and members of parliament, who'd assured him they were ready to build a connective pipeline to Alaska, although they were having some difficulty with respect to the Mackenzie line. He noted it still hasn't been resolved as to whether the Mackenzie pipeline will be built before Alaska's. He concluded that he didn't see any reason for using that route. With Alaska's gas potential, he opined a line should come down near the Railbelt, and ultimately there should be a line to this area. Furthermore, he predicted a gas line would turn some community into an industrial community. Urging legislators to consider the tremendous volume of gas, he highlighted developing the technology to commercialize it. 2:54:10 PM REPRESENTATIVE SAMUELS asked: If there is a delay by the legislature, how will that affect support on other Alaskan issues relating to fish and game or ANWR when Midwestern Senators have to talk to their constituents about the price of fertilizer, for instance? U.S. SENATOR TED STEVENS replied the feeling already exists that there is a delay. He surmised there'd be substantial money received for developing oil and gas in the next 50 years. Now that prices are good, he surmised the state will be held to answer if there is delay. He also surmised any federal Act proposed to take control of this gas would end up in court. He pointed out that this gas has already been produced and then stored. It's only stranded because there isn't a pipeline. Thus it isn't the same question normally faced by Congress. He reiterated his belief that the federal government has the power to demand that this gas be moved in the national interest. 2:57:42 PM MR. CLARK agreed. Recapping discussion of the proposed GRT, he said developing the gas line is the single most important thing to do for the state, since it allows extending the life of the oil field, giving time to develop technology for heavy oil as well as fill the gas line. U.S. SENATOR TED STEVENS characterized the GRT as a fine that is unconstitutional and unsound, since the gas has been stored and this would put a penalty on it because it hasn't been moved. MR. CLARK said the administration has a signable deal as far as the producers and the state are concerned, except for possible adjustments because of concerns raised by the public and the legislature. There needs to be legislative approval to realize that deal. He said the prize is so big, equivalent to 25 billion barrels of oil. He agreed with the need to set aside other considerations and realize this is for the future. 3:02:06 PM U.S. SENATOR TED STEVENS highlighted the state constitutional question of contract approval by the legislature. He noted Congress, according to Supreme Court opinion, cannot interfere with signing of a contract by the executive branch. He said he'd rather there be compliance with current law than have it challenged, however. He cautioned that in a climate like Alaska's, where costs are high and unpredictable, the ultimate cost of the gas pipeline isn't known. Whether future development involves NPR-A, ANWR, gas concentrates, the total OCS and so on, it will require a tremendous investment. If actions cool the investment climate, he predicted such development won't be seen in legislators' lifetimes. 3:04:39 PM CHAIR SEEKINS indicated the Senate Judiciary Standing Committee, which he chairs, had targeted the constitutionality of legislative approval of the contract, and nothing could be determined with respect to the state law. The question remains. SENATOR COWDERY related a conversation with someone in Kentucky who'd said much of the pipe for TAPS came from there. He also recalled discussions about a shortage of steel. U.S. SENATOR TED STEVENS highlighted planned pipelines, including one from Russia to China. As for flat steel, he opined that rolling the pipe in Alaska is being looked at. Furthermore, while it is possible to get in line now for pipe in eight years, a two-year delay might preclude it, since nobody will put money down for pipe until the administrative process is over, federally and in Alaska. He reiterated the need to shorten that time, adding he isn't critical of the delay so far. He noted Congress will demand the same kinds of information demanded thus far by legislators. SENATOR BEN STEVENS asked if the Canadians are waiting for execution of the contract so negotiations between Canada and Alaska can begin. U.S. SENATOR TED STEVENS said he'd interpreted the message as readiness and willingness to make the commitments necessary, and that, barring a delay, its pipeline would be ready to take the gas whenever Alaska's pipeline reached the border. SENATOR BEN STEVENS asked the producers if the next step after execution of the contract is negotiations with Canada. MR. McMAHON, ExxonMobil, responded that the next step is the beginning of the project plan, which will have myriad activities such as engineering and access to lands, including regulatory permits for Canada and Alaska. Interfacing with the Canadians will begin soon after the contract is executed. They will get the applications to FERC and to Canada's National Energy Board (NEB) ready at the same time. U.S. SENATOR TED STEVENS said the Canadians are willing to talk about timeframes and specific dates for completion. 3:10:54 PM SENATOR BEN STEVENS suggested differentiating between the Canadian officials or regulatory agencies just discussed and a Canadian partner. For instance, TransCanada had submitted an application and stated readiness to begin negotiations. MR. McMAHON noted the current proposal is for ExxonMobil, BP, ConocoPhillips and the State of Alaska to construct this pipeline in Alaska and Canada. It will go from Alaska to Alberta and as far as needed to get to a petroleum market. He expressed openness to talking with TransCanada if that company can demonstrate it will add value to the process. SENATOR BEN STEVENS summarized that negotiations need to take place between the governments and their regulatory agencies. But if a commercial Canadian proposal will add value, it will be entertained but isn't necessary for FERC sanctioning. MR. McMAHON agreed, stating his belief that NEB's process is open and available to all who want to propose a pipeline. 3:14:40 PM SENATOR WAGONER recalled that TransCanada claimed it has rights- of-way, except in a few areas, through the First Nations. He asked whether the line would be built without TransCanada's cooperation or if the rights would be purchased from them. MR. VAN TUYL replied under the NEB process it's market-based. Any project sponsor that can demonstrate public need of convenience and necessity can permit a project. He noted BP meets regularly with TransCanada. He agreed any party that could add value and assume its share of the risk would be welcome. He opined that in the NEB regulatory process there isn't a problem with obtaining a right-of-way. The Canadian government has formed a federal working group to coordinate with various entities; NEB is part of that, along with First Nations representatives, to ensure the process can be completed within the same window - about 20 months - as the U.S. federal process. 3:16:43 PM CHAIR SEEKINS highlighted discussions about whether an independent owner of the gas pipeline would provide better access to independent companies, and the possibility that producer-and-state ownership lends itself to "basin control." U.S. SENATOR TED STEVENS replied there are no independent producers right now. Some are exploring. As for the charge to transport gas from another source through that pipeline, he opined that during the period when the cost of the pipeline is being repaid, the difficulty is giving up a portion of that capacity and getting payment for transporting gas that won't be contributing to the repayment of the cost. Surmising this is a subject for negotiation, he reported having had discussions with independents and the producers about it. He opined that a contract provision discusses this, but doesn't solve the question if an independent producer has substantial quantities of gas that come on board. Noting it will have to be worked out, he said there is a FERC mechanism; he surmised FERC would have jurisdiction to determine that. This isn't a common- carrier pipeline per se, but there would have to be provisions for transporting gas that was available. MR. CLARK agreed. He added at an appropriate point the administration wants to put before the legislature an upstream contract which provides that any explorer who finds gas and takes an FT commitment in any open season - and thus is willing to take a reserve charge to get the gas to market - will get the same fiscal stability terms as the producers. Furthermore, legislation that the administration proposes would offer fiscal certainty, so there'd be the same certainty about upstream costs or taxes as the producers would get. This is what the administration is proposing to address the point U.S. Senator Ted Stevens just made. U.S. SENATOR TED STEVENS concluded by saying time is of the essence. He suggested reading the U.S. Vice President's letter to the House and Senate, especially the last paragraph, which talks about securing cooperation from Canadian counterparts and conveys the urgency; he said this reflects the feeling received from everyone he has dealt with at the federal level. He then read a note from his own assistant that said FERC has been meeting with NEB, and that the producers are pushing to use NEB, since Canada wants the process under the Northern Pipeline Act. The concern is whether there'd be a delay under the NEB process. He surmised the federal agencies would work this out along with the producers as the pipeline moves through Canada. He surmised the interest shown by the Canadian parliament in taking the trip last week indicates a sense of urgency in Canada as well. The committee took an at-ease from 3:23:29 PM to 3:52:07 PM. ^Dan Dickinson - Discussion of fiscal certainty for oil MR. DICKINSON discussed fiscal certainty for oil. He suggested looking at 1973-1981, when Alaska's oil economy changed from being based in Cook Inlet to the North Slope. In 1973 a statewide property tax was enacted for oil and gas property. For the oil and gas production tax, in 1977 the maximum rate was 12.25 percent, raised to 15 percent in 1981. For income tax, Alaska switched in 1978 to become a separate-accounting state and in 1981 switched back. In 1980 Alaska also repealed the personal income tax. Thus the main source of revenue within the state's fiscal system was changed to be oil and gas. He addressed the question of a 30-year period of fiscal stability for oil, the time agreed to during negotiations. Mr. Dickinson explained that 30 years approximates the first two phases of the gas project: 1) the time to put the pipeline together before commercial operations commence; and 2) the period of the first FT commitments, which underwrite the project and could be as short as 15-20 years. While in 1988 oil was at 200 million barrels, today it is about 875,000 barrels a day and may decline to half that in 30 years. The desire was to avoid having oil-related rules changed later on. The first 30 years of the gas project would be the most crucial for this stability. MR. DICKINSON highlighted compounding interest, giving details on the calculations and saying the number of years is critical. One legislative directive in the Stranded Gas Act was to back- end load when possible, moving payments from the front years to the end. A shorter fiscal-stability period changes the effects of this. Production facilities would produce both gas and oil, with the same fiscal-stability period as the gas line, 35 years. For an oil facility like TAPS, fiscal stability has been proposed at 30 years, with an inflator built in. He recalled when he asked to become the division's director eight years ago, the emphasis was that conflicts shouldn't build to the size they had. Mr. Dickinson said the fiscal contract tries to resolve problems up front, recognizing some conflicts may be arbitrated. He emphasized that the state will be getting the percentage it believes it should get; opined that 30 years is appropriate; expressed the administration's commitment to the fiscal terms negotiated; and conveyed the intention not only to educate the public about the 30 years, but also to hear the public's concerns, which requires a lot of back and forth. 4:04:35 PM MR. DICKINSON referred to yesterday's discussion of a state Senate proposal during the first special session. It sets up three periods. The first is prior to project sanctioning, during which the rule of law remains and the contract doesn't dictate the fiscal terms, but just refers to the PPT, AS 43.55. There is no overriding fiscal stability. The second is from the start of sanctioning, 14 years during which the gas line is built as well as early years of shipping gas. During this time, the contract dictates terms for oil under AS 43.56 and more general terms for the gas line. He noted the third period still has stability for oil, but focuses on the outcome. The purpose isn't to allow changes in the tax system to derail the project. If a change in this period alters the economic value, arbitration can be used to renegotiate. As long as the original deal is preserved, other changes can occur within the fiscal structure. Thus it is an alternative suggestion for providing fiscal stability. MR. DICKINSON highlighted the issue of a payment in lieu of taxes (PILT) to replace the corporate income tax. He said it seems there are areas where the state could get aggressive and that lots of money could turn on it. Providing details, he characterized this as a new way of interpreting fiscal stability, using different tools to achieve the same result. 4:10:56 PM MR. VAN TUYL agreed fiscal stability is critical to the contract. It's the core principle behind the Stranded Gas Act, and BP believes it extends to both oil and gas, from not only the Act, but the nature of business on the North Slope, given that oil and gas are inextricably linked. Commitment to a gas pipeline project necessarily means committing to maintain all those facilities and to produce oil and gas for decades. His company is keen to do that, but knowing the rules. This concept of long-term fiscal stability on both oil and gas is used in agreements worldwide to support mega-projects. Thus BP believes the contract language is appropriate and essential to allow the project to move forward and to attract the investment. 4:12:41 PM SENATOR STEDMAN noted page 73 of the FIF shows cash flows for oil and gas, with oil seemingly favored in terms of value. He said he could understand wanting a stable tax regime for oil, even though the objective is a gas line. AN UNIDENTIFIED SPEAKER predicted gas revenues will be more than oil revenues on a discounted basis. SENATOR STEDMAN suggested someday people will look at huge cash flows from the gas line, wondering about the government share. Similarly, today's government take from Prudhoe Bay might be thought too low, whereas in the late 1960s there would have been a whole different risk profile. CHAIR SEEKINS confirmed that Donald Shepler and Jim Eason, who were on teleconference, had no comments to add. He noted Rick Harper and Steve Porter had been on teleconference as well. He discussed the committee's schedule and thanked participants. There being no further business to come before the committee, Chair Seekins adjourned the Senate Special Committee on Natural Gas Development meeting at 4:24:09 PM.