ALASKA STATE LEGISLATURE  HOUSE SPECIAL COMMITTEE ON ENERGY  March 17, 2009 3:06 p.m. MEMBERS PRESENT Representative Bryce Edgmon, Co-Chair Representative Charisse Millett, Co-Chair Representative Nancy Dahlstrom Representative Jay Ramras Representative Pete Petersen Representative Chris Tuck MEMBERS ABSENT  Representative Kyle Johansen COMMITTEE CALENDAR  Overview: Cook Inlet Natural Gas Presentations by Kevin Banks, Director, Alaska Division of Oil & Gas; Jim Posey, General Manager, Anchorage Municipal Light and Power; Brad Evans, CEO, Chugach Electric Association. - HEARD PREVIOUS COMMITTEE ACTION  No previous action to record WITNESS REGISTER KEVIN BANKS, Director Central Office Division of Oil & Gas Department of Natural Resources (DNR) Anchorage, Alaska POSITION STATEMENT: Presented an overview of Cook Inlet natural gas. JULIE HOULE, Resource Evaluation Section Chief Central Office Division of Oil & Gas Department of Natural Resources Anchorage, Alaska POSITION STATEMENT: Participated in the PowerPoint presentation on Cook Inlet natural gas. BRADLEY EVANS, CEO Chugach Electric Association Anchorage, Alaska POSITION STATEMENT: Testified during the hearing on Cook Inlet natural gas. JAMES POSEY, General Manager Anchorage Municipal Light and Power Anchorage, Alaska POSITION STATEMENT: Testified during the hearing on Cook Inlet natural gas. ACTION NARRATIVE CO-CHAIR CHARISSE MILLETT called the House Special Committee on Energy meeting to order at 3:06 p.m. Representatives Petersen, Tuck, Edgmon, and Millett were present at the call to order. Representatives Ramras and Dahlstrom arrived as the meeting was in progress. ^OVERVIEW(S): COOK INLET NATURAL GAS 3:06:56 PM CO-CHAIR MILLETT announced that the first order of business would be an overview of Cook Inlet natural gas with presentations by Kevin Banks, Director, Alaska Division of Oil & Gas, Department of Natural Resources; Jim Posey, General Manager, Anchorage Municipal Light & Power; and Brad Evans, CEO, Chugach Electric Association. 3:07:26 PM KEVIN BANKS, Director, Central Office, Division of Oil & Gas, Department of Natural Resources (DNR), described the scope of the PowerPoint presentation that followed. 3:08:55 PM MS. HOULE, Resource Evaluation Section Chief, Central Office, Division of Oil & Gas, Department of Natural Resources, informed the committee she would present the geology of Cook Inlet from an exploration geologist's point of view for future gas potential. She stated there is more gas to be found in Cook Inlet's existing gas fields and in new exploration play types. Most of the developed fields are in the major structures that were found during the '60s by using 2-D seismic; however, new exploration will utilize stratigraphic plays and 3-D seismic. Ms. Houle said she would address hurdles to future development such as land access, data gathering, and drilling costs. 3:10:57 PM MS. HOULE displayed slide 42 "Cook Inlet Gas Exploration Statistics" that indicated 85 percent of the gas discovered in Cook Inlet was discovered while drilling for oil early in the exploration cycle. She explained the gas "sits on top of the oil," thus the gas was encountered on route to drilling for oil prospects on large structures. However, present day 3-D seismic [technology] is expected to reveal undeveloped resources from stratigraphic trap potential. She said the major gas field producers are the biggest fields; in fact, four of the largest fields in Cook Inlet hold 86 percent of the gas reserves. Ms. Houle then displayed slide 17 "Cook Inlet Industry Activity" and said the first of the five largest producing fields is the Beluga River Unit, with an annual production of 43 billion cubic feet (bcf). The highest producing wells in the Beluga River were drilled prior to 2005; however, ConocoPhillips Alaska, Inc. drilled two new wells that are not online at this time. The second largest field is the North Cook Inlet Unit, with a 2008 annual production of about 23 bcf; again, most of the producing wells were drilled prior to 2005, and three new wells are not yet online. The Trading Bay Unit produced 23 bcf, also from wells drilled prior to 2005. Additionally, the Ninilchik Unit produced 19 bcf last year, and 46 percent of its wells were drilled between 2005 and 2008. Ms. Houle pointed out that the area of the Ninilchik Unit is an anticline with a surface structure. Marathon Oil Corporation and Chevron/Unocal have "gone through" this area, combined with the neighboring fields of the Grassim Oskolkoff (GO)/Susan Dionne/Paxton Participating Area, and the new drilling by Marathon and Chevron/Unocal is adding to the reserves. This well-by-well, additional drilling within an existing field does a good job of incrementally adding to the reserves. For clarification, she explained the department uses the following Alaska Oil and Gas Conservation Commission (AOGCC) regulatory definition of an exploratory well: An exploratory well means a well drilled to discover or delineate a pool. Ms. Houle remarked: When you drill one well, say in the '60s and you had a discovery of gas or oil, then, but nobody did anything because it wasn't economic, later when another company came in and they drilled another well, to delineate it, to see how big it was, because the sands are discontinuous. ... Then maybe it was commercially brought online, but it you look at some of these discovery dates, they're way earlier then the field came online, and [the Cosmopolitan Unit] is an example of that. MS. HOULE, returning to the producing gas fields in Cook Inlet, said the fifth largest producing area is the Kenai Unit located on federal land. Forty-six percent of its producing wells were drilled between 2005 and 2008, and its annual production is about 19 bcf. 3:16:34 PM MS. HOULE presented slide 4 that showed the volcanic activity on the Kenai Peninsula and the Aleutian Chain islands known as the "ring of fire." Cook Inlet is unique in that active volcanism and sandstone formed from volcanic rocks are not usually a good reservoir for gas and oil. Slide 5 "Upper Cook Inlet Basin, Basin/Reservoir Origins" indicated that Cook Inlet Basin is located in an active subduction zone. The subduction zone is a slab of mineral-laden earth that slides down under the lighter continental crust. Slide 6 showed the volcanic area next to Cook Inlet Basin and the Forearc Basin, where sediments are deposited. The primary depositional fabrics in Cook Inlet are fluvial, or rivers, and the area coming off of the Volcanic Arc is a very coarse-grained alluvial fan, that is coming from the west and is deposited to the east. Further, there is a meandering river system along the basin axis, and there is evidence of tectonics with active faulting and subsidence. She said that the "take home message" is that the sandstones in Cook Inlet are very discontinuous and are at about 150 feet, which is generally below seismic resolution, although 3-D seismic will have improved resolution. 3:20:44 PM CO-CHAIR EDGMON asked whether most of the gas developed today was the product of 2-D seismic activity. MS. HOULE indicated yes. She added that 2-D seismic mapping done in the 1960s showed the anticlinal structures because they are very large structures that run along Cook Inlet. In further response to Co-Chair Edgmon, she explained 3-D seismic is more of a tool in the North Slope; however, there were three 3-D surveys completed in Cook Inlet: in the Beluga Field, in the Ninilchik Area, and in north Cook Inlet. These surveys were of existing fields and "the advantage there is they have a lot of well control, in order to look at their seismic, and see the correlation between the sands and the wells, because they are very closely spaced ...." She said the department would like to see 3-D seismic shot in the Cook Inlet in a similar manner to Chevron's activity at the White Hills on the North Slope. Slide 7 "Tertiary Basin Depositional Systems" showed an aerial view of the meandering rivers of the Susitna Valley. She explained how this geology leads to the discontinuous nature of sand deposits. In fact, linear sand deposits left on top of each other during different periods in history are called amalgamated, and are better reservoirs than isolated sands. She also noted there are a lot of coals in Cook Inlet, and "coals reek havoc on seismic interpretation." Slide 8 "Sand Distribution in a Fluvial system" illustrated five wells and the reservoir correlation along the structural crest. If the pressure in the sand is the same at different wells, this is an indication that the sand reservoirs are connected; however, the illustration clearly showed that all of the sands do not hit all of the wells. 3:25:01 PM CO-CHAIR EDGMON asked whether 3-D seismic activities "play out with the "beluga [whale habitat] issue." MS. HOULE agreed that there is an issue with the designated beluga habitat area. In addition, the problem with shooting seismic is not only the habitat issue, but also the time constraints dictated by the extreme tides. She presented slide 9 and said the most producing stratigraphies in the Cook Inlet are the Sterling, the Beluga, the Tyonek, and the Hemlock. The Hemlock is oil-prone, the Tyonek has oil in the lower [section] and gas in the upper, and the Beluga and Sterling are exclusively gas. The one reflector seen well in Cook Inlet is the Sterling to Beluga transition, because the Sterling sands are thicker and the sandstone packages of the rivers are accreted. The Sterling reservoir also does not have a lot of coal. The Beluga is thinner-bedded and has more coal, but is still a good gas reservoir. The Tyonek also has coals and varied thicknesses of sand. Slide 10 illustrated the discontinuous nature of sands and that one well would not necessarily penetrate every [layer of] sand on a structure; therefore, it is necessary to drill delineation wells. Additional wells drilled between existing wells, if successful, are called "bypass pay." Two common problems with older wells are plugged up perforations and wells that can not be restarted due to water. 3:28:21 PM MS. HOULE presented slide 11 "EW-1 Granite pt" that showed large structures revealed by early seismic data. Slide 12, "NCI field, Low Hanging Fruit" showed the fields located on the sides of structures and that have three-way closure; she opined these are a good target for exploration. Slide 13, "NCI field flat- spots" showed an area that "slows down your seismic ... [and] that can be an indicator of gas." Slide 14 "New Gas from New Exploration Play Types; Oil and Gas Trapping Mechanisms" illustrated the following: Anticline structures have been discovered; some fault traps have been discovered; and stratigraphic traps are more elusive, but promise gas in Cook Inlet. Slide 15 was a seismic picture of subtle stratigraphic traps. Slide 16 "Tight Gas Sands" indicated that the sands in the Tyonek and the Beluga look good because they have a lot of volcanics, they are less than 65 million years old, and they are less than 10,000 feet deep, thus have not been compacted. 3:31:57 PM REPRESENTATIVE TUCK asked for clarification of slide 16. MS. HOULE explained slide 16 is a picture of two pieces of sandstone rock fragments that were cut into slabs and put under a microscope. The "blue areas in here are porosity, so that would be where your oil would move through or your gas would be stored." Slide 18 showed that the thickest sediment in Cook Inlet Basin is 25,000 feet. Slides 20 through 25 showed the location of federal land, CIRI land, Mental Health Land Trust land, Beluga Habitat, and the areas under lease sales. She pointed out the "sweet spot" of Cook Inlet is leased; furthermore, other land that is a potential resource in the inlet is not available. 3:37:03 PM MR. BANKS presented slide 27 "Oil & Gas Cook Inlet Milestones: 1800s-1040s" that indicated the location and date of oil discoveries up to 1949. Interest in oil development in the Cook Inlet began in the late 19th century and accelerated with the discovery at Swanson River in 1955. By 1958, Swanson Oil Field production began. Slide 38 showed the wells drilled from 1950 to 2008, and indicated the greatest activity took place during the mid '60s; in fact, the largest oil discovery was at the McArthur River field in 1965, and gas was found there as a by- product of oil exploration. Consequently, in the late '60s, producers in the Cook Inlet had to monetize gas resources and developed the Agrium, Inc., fertilizer plant and the liquefied natural gas (LNG) facility. The slide also indicated that the new activity beginning in1995 includes wells drilled for gas exploration and delineation. Slide 39 showed that a steady number of Cook Inlet development wells were drilled after the highest peak in the late '60s. Slide 40 showed the number and dates of the installation of offshore oil and gas platforms in Cook Inlet, ending with the Osprey oil platform in 2000. Slide 41 "Cook Inlet - State Acres Leased" was a bar graph that indicated a steady number of acres were purchased by potential production and exploration companies; in fact, about 25 percent of the available land in Cook Inlet is under lease, and Mr. Banks opined there is a need to get greater access to land in the Kenai National Wildlife Refuge or to land owned by others. 3:41:53 PM REPRESENTATIVE EDGMON asked when the Beluga Habitat was established. MR. BANKS said U.S. Fish and Wildlife Service has laid out critical habitat areas, with certain restrictions, within the last two years; in addition, the beluga whale was listed as an endangered species, which may change how the critical habitat is managed. REPRESENTATIVE EDGMON asked what the restrictions mean to gas exploration and seismic activity in the Cook Inlet. MR. BANKS responded access to those areas will be, in some instances, completely prohibited north of the North Cook Inlet Unit; in other areas access may be seasonally restricted for "conflict avoidance" and activity offshore will have to be "worked around" the presence of whales. In response to Co-Chair Millett, he said 3-D seismic was shot at North Cook Inlet, the Beluga River, and Ninilchik last year. 3:44:26 PM MR. BANKS continued to slide 43 "Gas Field Size Distribution Cook Inlet." As expected, there are many small fields and fewer big fields found in an oil and gas basin; therefore, the department expects more gas to be found in fields similar to the Ninilchik Unit and its participating areas. Therefore, drilling and exploration in the future should yield more gas fields that produce in the range of 300 bcf to 1,300 bcf. Referring again to land access, he noted the Cosmopolitan Unit is an oil field with a gas cap; however, because of restrictions to access from the surface, the wells are being drilled directionally from onshore. This means the wells will traverse under the gas cap and only oil will be produced. 3:47:13 PM MR. BANKS presented slide 46 "Cook Inlet Demand and Deliverability Forecast" that was a graph showing the theoretical capacity of the production of gas within the existing units. This production capacity declines dramatically, beginning about 2009. This prediction is based on an assumption that no further investments are made in Cook Inlet and that gas is produced only from existing wells. The "history" line on the graph represents an annual average production of gas; the "capacity" line at any given point on the graph is greater than the history line because the production can be much greater than the average on very cold days. Mr. Banks continued to slide 47 "Historic Deliverability" that indicated on 2/3/99, one of the coldest days of the year, 763 million cubic feet (mcf) was delivered to the market. On 1/3/09, 380 mcf was delivered to the market; however, in 2009, average production was 150 bcf per day. Returning to slide 46, he pointed out that from 2009-2011, LNG exports in the amount of about 49-50 bcf per year will be allowed. After 2011, the graph assumes that no exports will be allowed and the forecasted demand levels out at just below 100 bcf per year. Shown on the graph in yellow are the P-2 reserves, known as "behind the pipe reserves." This is gas in the discontinuous sands that has not been reached by the existing wells. The graph estimates that more drilling in existing fields could produce as much as another 470 bcf of gas. Mr. Banks noted that this additional capacity includes gas that is expected from two new wells in the Beluga River Unit and three new wells in the North Cook Inlet Unit; in addition, there is the potential for new gas from continued development drilling in existing fields. This potential increase in gas would supply the utility and electricity demand from Cook Inlet until 2019. Mr. Banks stated the department will continue to refine these projections. He then explained the area to the left of the yellow on the graph will come from brand new exploration. 3:52:32 PM REPRESENTATIVE PETERSEN asked whether directional drilling was being used in Cook Inlet. MR. BANKS said yes. For example, any platform has wells "are literally feet apart" thus in order to reach the fields, wells are drilled directionally. Horizontal wells are not as common, because the wells attempt to hit as many sand bodies as possible as they travel through the resource. He pointed out the 470 bcf to 500 bcf of gas reserves will only be drilled for if there is a market waiting for it. He opined a producer will not drill a well if the market is unknown; in fact, producers usually enter into a supply contract with a customer intending to meet the supply requirements by additional drilling - exploration will not happen before the market exists. If there were the assumption that LNG exports will be allowed beyond the next license period, some of the gas to supply the LNG might come from gas reserves, at the expense of local demand. Mr. Banks recommended that discussions with exporters should elicit commitments to replacing and augmenting the reserves. 3:55:08 PM MR. BANKS continued to slide 48 "Cook Inlet Daily Gas Demand" and explained one issue for Cook Inlet is, because of the climate, there is almost 14 times as much gas delivered into the market on "needle-peaking days" than on warm summer days. In the past, there was sufficient capacity to adjust for this increase in demand; however, it is more difficult to make this adjustment now that the productivity of the wells and the fields has declined. For example, in anticipation of an increase in demand, ENSTAR has begun to pump gas into the pipeline for additional storage; this is called a "line pack." Other methods to address peak demands are: storing gas in three exhausted gas pools in the summer; adding compression; adding more wells; and "swinging the load of gas taken up by LNG exports." He stated the market creates a different challenge; for example, gas storage can be offered to third parties, as is common in the Lower 48. Mr. Banks presented slide 49 "Industrial Base Load" that showed the industrial base load peak swing from a warm day to a cold day is now 200 percent. This is an increase from a peak swing of 50 percent when gas was also marketed to the LNG plant and to the Agrium fertilizer plant. He stressed the advantage of reducing the peak swing by having an industrial or export market for gas; for example, the additional market would keep the wells online year around and prevent the problem of "watering out" wells from temporary closures. 3:58:37 PM REPRESENTATIVE RAMRAS thanked Mr. Banks for his assistance. He then asked whether Cook Inlet production is down from 200,000 barrels of oil per day at its maximum, to 10,000 to 20,000 barrels per day. MR. BANKS agreed production is down to about 20,000 to 25,000 barrels per day. In further response to Representative Ramras, he agreed that in the '70s the price of gas was probably 15 cents per mcf and oil production taxes were 10 percent of production. REPRESENTATIVE RAMRAS recalled testimony from the Armstrong Oil company that it found gas in Cook Inlet and the price of "lifting" that gas is estimated to be $7 to $10. He pointed out the RCA issues permits for gas sales tied to the Henry Hub [index] and other indices in the $3.85 to $4 range. He concluded that there is the ability to find more gas, but not at the historically attractive prices Cook Inlet gas has yielded in the past. MR. BANKS opined exploration in Cook Inlet will be an expensive enterprise. He expressed his intent to "provide you with much better information ... perhaps [by] looking at some of the tax information that we're acquiring through [Alaska's Clear and Equitable Share (ACES) legislation] to get a handle on what onshore drilling costs are like ... [and] working with our lessees or hiring in folks to look at what it would take to do drilling offshore." The expense will be higher than in the past, particularly to move forward in developing a stratographic play, even if the initial wells are not as successful as hoped. In addition, access is an issue, as state lands have been "picked over" and the state must engage the federal government, and others, for access to their land. REPRESENTATIVE RAMRAS recalled Drue Pearce suggested that ConocoPhillips Alaska, Inc. should approach the Federal Energy Regulatory Commission (FERC) for a re-gas permit to import LNG for its Cook Inlet plant. He asked Mr. Banks to discuss the ramifications of how a re-gas facility would change the basin and the flow of the LNG facility. "I will say for the record that I'm not in favor of that, I'm a bullet line person," he said. There is a possibility, however, that $3 or $4 gas may be available through LNG, while the cost of lifting gas from the basin may be $7 to $10. 4:05:01 PM MR. BANKS said the situation with LNG exports is that the market for gas from Cook Inlet is attached to some other market in the world. This occurs because the pricing for gas for export should have some influence on the price of gas within the basin. Also, there is the question of the cost of drilling for gas. Depending on how transparent the market is, in terms of sending price signals to producers and consumers, the Cook Inlet market is "hooked into" an export, or a world, LNG market. If gasification were permitted, it would be just another way for that connection to the world market to be established, depending on the transparency of the pricing to the world marketplace. Mr. Banks suggested if the imported LNG is cheaper for Alaska consumers, it would be wrong to not consider importing; however, before that happens there are a lot of other options including gas from the North Slope and successful exploration in Cook Inlet at a competitive price. 4:07:45 PM CO-CHAIR MILLETT asked for suggestions for the state's role in helping sustain a lower price in Cook Inlet outside of the aggressive incentives for exploration that are already in place. MR. BANKS pointed out the state's very attractive tax provisions and the mechanisms in royalty [taxes] to protect the way utilities are treated. Aside from an "out-right subsidy," he suggested the state should first find out the potential for gas development and compare that to other options. This information would allow the legislature to determine the most cost-effective new gas alternative for Cook Inlet. 4:09:45 PM MR. BANKS, in response to Co-Chair Millett's request for information related to the joint meeting of the House Resources Standing Committee and the House Judiciary Standing Committee of December 1, 2008, informed the committee DNR met with representatives from Renaissance Energy Ltd., Escopeta Oil Company, Pacific Energy Resources, Ltd., and ConocoPhillips, shortly after the meeting. At that time, DNR asked the parties to consider that forming a unit on a piece of land where there is one owner and an amorphous potential for gas "doesn't really satisfy the point." What a unit should do, in addition to taking care of the rights of the various partners, is to limit the requirements for facilities on the surface. The department requested the parties to submit an agreement on how a drilling agreement would be organized. However, last week Pacific Energy went into Chapter 11 [reorganization under the Bankruptcy Code], and recently Escopeta, the operator at the Kitchen Unit, structured a deal in which it acquired an ownership interest in the leases and came forward with a commitment to provide a plan of exploration for the area. In fact, Escopeta has committed to meet certain due dates or relinquish the leases. 4:12:23 PM REPRESENTATIVE RAMRAS referred to slide 46 and suggested the information on the slide shows the state continuing to go to Cook Inlet for gas and that the Conoco export case "goes away." He presented a scenario whereby in 2014, natural gas is coming down from the North Slope to supply the need in Alaska, and Conoco is continuing to export LNG from the Cook Inlet gas fields at 75 bcf per year. He asked, "Can you articulate what that future would look like ... [for] the depleting, mature Cook Inlet? 4:13:43 PM MR. BANKS surmised Representative Ramras was asking him for a prediction. He speculated that a bullet line has the possible impact of using the existing [LNG] facility to export gas, which would limit the market for future gas from Cook Inlet. Therefore, the question would be whether Cook Inlet can complete with gas from the North Slope. He stressed that the unknown is how much it will cost to get gas into the Southcentral region and how the North Slope gas will compare. REPRESENTATIVE RAMRAS re-stated his question. MR. BANKS responded that it behooves the state to research all of the options before participating in various solutions. Furthermore, a better understanding of the resource potential and the cost of the development of gas in Cook Inlet is part of that research. CO-CHAIR MILLETT turned the gavel over to Co-Chair Edgmon. 4:16:28 PM REPRESENTATIVE PETERSEN asked about gas storage expansion plans. MR. BANKS responded there are three facilities operated by producers who own the gas they are putting in storage. Discussions are underway with an applicant for a gas storage lease and indications are that the applicant is interested in creating storage for third party use. There are five to seven other exhausted gas pools that could serve as storage; however, their locations are not ideal. CO-CHAIR EDGMON returned the gavel to Co-Chair Millett. 4:19:10 PM CO-CHAIR EDGMON recalled previous testimony from a representative of the Armstrong Oil company who concluded Cook Inlet is underexplored, but that it has potential for gas development even though costs are high. He asked Mr. Banks if he agreed that today's presentation focused on the challenges to be overcome for further development in Cook Inlet. 4:20:27 PM MR. BANKS opined the Armstrong representative was "probably more right than I am about the potential for gas development in Cook Inlet." 4:21:21 PM BRADLEY EVANS, CEO, Chugach Electric Association (Chugach), informed the committee his family has been in Alaska since 1960 and he has an electrical engineering degree from the University of Alaska Fairbanks. Mr. Evans has worked for the Department of Transportation (DOTPF), Golden Valley Electric Association, and Chugach Electric. He said he would portray Cook Inlet natural gas through the "lens of a consumer." He expressed his belief that the state has taken an abundant resource in Cook Inlet and created an economic engine that powered Southcentral, Fairbanks, and Fort Knox. This resource is also critically important to Chugach Electric. However, historically, information about the inlet has not been shared by all of the interested parties and that is one of the recommendations made by his company. He presented slide 3 "Chugach's fuel mix" that illustrated the fuel mix today is 90 percent gas and 10 percent hydroelectric (hydro); the vision for the future is for power generation from 10 percent gas and 90 percent renewable sources. He presented slide 4 "Cook Inlet Supply Demand Situation Today" that illustrated: Supply from reservoir harvesting and limited exploration; supply management by diverting LNG back to retail use in the inlet; demand from LNG exports, gas utilities, electric utilities, and military bases; and demand management by conservation and load interruptions. Slide 5, "Where will future gas supply come from?," listed Cook Inlet exploration; spur line; bullet line; LNG import; and alternative fuels. He noted that some of these choices are not popular and have commercial issues; however, the utilities' consumers want "affordable power over pride of developing a resource that is more expensive." Slide 6, "Without reserves growth, supply will not meet gas demand for utility needs" was a graph that indicated the base supply, base supply with reserves growth and use for power generation and gas utility from 2003 to 2025. Mr. Evans stated his company's intent to lower the use of gas for power generation as "part of the solution, as well." 4:26:48 PM MR. EVANS presented slide 7 that showed Chugach Electric's recommendations for the establishment of a Cook Inlet Resource Management Plan and a Cook Inlet Public Gas Authority. Regarding the management plan, he agreed that "homework" needed to be done to find out what was in the resource and where to spend capital on exploration, storage, and resource management activities. He opined doing the right homework will meet and protect consumer needs. The management plan should also address fuel supply security, increase transparency and information sharing, and provide input for a Railbelt integrated resource plan. Furthermore, the resource plan would provide guidance for the utilities' investment decisions about storage options, would optimize resource management in Cook Inlet, and would provide information for rational policy decisions. He suggested the aforementioned are the goals and objectives of the Cook Inlet Resource Management Plan, but not the scope of the plan. 4:28:53 PM MR. EVANS presented slide 9, "Next Steps." Chugach Electric has a good working relationship with the administration and supports the administration taking the lead on this situation. He encouraged the development of a steering committee, similar to the one on the Railbelt Electrical Grid Authority (REGA), to assure all of the parties of the quality of the shared information and, through better understanding, to formulate better decisions. He said he was unsure whether there was a need for funding support from the legislature until the administration issues a request. The last step would be reporting to the legislature by date certain to assure transparency in the process. 4:30:30 PM MR. EVANS presented slide 10, "Cook Inlet Public Gas Authority" and stated Chugach Electric, from the consumer side, is interested in looking at organizations that combine the interest of consumers, such as a large nonprofit agency that engages in wholesale contracts and activities for end-users. He proposed that members of this agency would include electric and gas utilities. Mr. Evans clarified, "I'm not here to say that everybody needs to join this, I'm saying it's a model that we might want to look at to make sure that ... the interest of the consumer is aligned ...." He stressed the wisdom of having a balance of the interests of the consumer, the producer, and the state. 4:31:53 PM MR. EVANS expressed his support of the presentation by the DNR. He summarized that the utilities are dependent on Cook Inlet natural gas for their supply of electricity and that they would like to keep rates affordable. He assured the committee, although the gas demand is outpacing the supply of natural gas, Chugach Electric is pursuing many demand reduction policies. He said he was glad that the committee is focused on the "sense of urgency" about this topic, even though the economics have changed somewhat since last summer. 4:33:02 PM CO-CHAIR EDGMON applauded Chugach Electric's efforts to keep this topic "a front-burner issue." He asked how many customers Chugach has compared to the other big utilities. MR. EVANS said it has around 80,000 meters. He estimated Chugach Electric represents about 60 percent of the energy produced in the Railbelt. In further response to Co-Chair Edgmon, he said its retail, wholesale, and customer base is about 200,000 meters; including meters that receive intermittent power. The peak load for Golden Valley Electric Association is about 200 megawatts for 40,000 meters. He explained the number of meters does not equal the "customer count" as some customers have more than one meter. 4:36:09 PM JAMES POSEY, General Manager, Anchorage Municipal Light and Power, indicated his appreciation for the presentation by DNR; however, he stressed that "the process [of] ... looking at the Cook Inlet, needs to be turbo-charged." Mr. Posey opined the problem must be resolved within three years by finding new gas, not by harvesting the old fields. At this time, the [oil and gas] companies are spending $40 million to $80 million per year trying to do that, but the state must ensure that another [trillion cubic feet] of gas is located. This would support the region during the period between 2014 and 2020, until the development of the bullet line or LNG imports. Mr. Posey noted his experience in the oil and gas business for over 40 years and recalled his expectation that the gas pipe line would have been built by 1987. He stressed the importance for the state to play a role in Cook Inlet exploration and that role will require an allocation of resources. Furthermore, legislative action this year and next will forestall "tight times" and ensure that the industrial base and population are secure. 4:39:04 PM MR. POSEY concluded that there are some areas of federal lands that are prospective; however, the state and private interests need to work to open this land and to ensure that a jack up rig is drilling offshore to find the gas that is still left in the inlet until the pipelines bring gas from the north. He predicted finding gas from the inlet would not cost as much. 4:40:07 PM CO-CHAIR MILLETT asked whether Mr. Posey supported a comprehensive Cook Inlet Resource Management Plan. MR. POSEY said he and Mr. Evans share the idea; however, it is necessary to dedicate $10 million to $20 million to ensure the supply of gas for domestic use and for the continued function of the economic engines in Southcentral. 4:41:18 PM ADJOURNMENT  There being no further business before the committee, the House Special Committee on Energy meeting was adjourned at 4:41 p.m.