ALASKA STATE LEGISLATURE  SENATE RESOURCES STANDING COMMITTEE  February 14, 2007 3:33 p.m. MEMBERS PRESENT Senator Charlie Huggins, Chair Senator Bert Stedman, Vice Chair Senator Lyda Green Senator Gary Stevens Senator Bill Wielechowski Senator Thomas Wagoner MEMBERS ABSENT  Senator Lesil McGuire COMMITTEE CALENDAR  Presentation: After the pipeline shutdown: update on corrosion BP Alaska Department of Environmental Conservation Department of Natural Resources Department of Law Alaska Oil and Gas Conservation Commission HOUSE BILL NO. 37 "An Act establishing the first Saturday of every March as Susan Butcher Day." SCHEDULED BUT NOT HEARD   PREVIOUS COMMITTEE ACTION    No action to report WITNESS REGISTER MIKE UTSLER, Senior Vice President Prudhoe Bay Operations BP Alaska Anchorage, Alaska POSITION STATEMENT: Described BP's response to pipeline corrosion and spill incidents. TONY BROCK, Technical Director BP Alaska Anchorage, Alaska POSITION STATEMENT: Described BP's response to pipeline corrosion and spill incidents. JONNE SLEMONS, Acting Coordinator Petroleum System Integrity Office Department of Natural Resources (DNR) POSITION STATEMENT: Introduced speakers from state agencies. LARRY DIETRICK, Director Division of Spill Prevention and Response Department of Environmental Conservation (DEC) POSITION STATEMENT: Presented information on BP's pipeline corrosion and spill incident and state response to it. CATHY FOERSTER, Commissioner Alaska Oil and Gas Conservation Commission Anchorage, Alaska POSITION STATEMENT: Answered question on pipeline oversight. ACTION NARRATIVE CHAIR CHARLIE HUGGINS called the Senate Resources Standing Committee meeting to order at 3:33:22 PM. Senators Wielechowski, Stedman, Green, Stevens, Wagoner, and Chair Huggins were present at the call to order. Overview: ^BP Pipeline Corrosion 3:34:57 PM MIKE UTSLER, Senior Vice President, Prudhoe Bay Operations, BP Alaska, said he has been in his role for six weeks, and he came from the North Sea after five years with BP. He has 30 years in the industry, focusing on how to optimize and improve the performance of mature, declining fields around the globe. He said the scale and the scope of the challenges on the North Slope are quite impressive. 3:36:39 PM MR. UTSLER said he has two responsibilities: to timely and efficiently develop resources and to operate safely, reliably, and in a sustainable way. He will provide an update on the commitments BP has made and give the committee a more detailed, technical look at the efforts on assuring that the existing systems are safe and what the plan is for rebuilding and renewing the systems for a 50-year future. 3:39:16 PM MR. UTSLER said he will update the committee on the seven commitments BP made in August. The first was to contain and cleanup the oil spill, which was 23 barrels of oil and 300 barrels of surface water. With large numbers of people and in cooperation with the agencies, BP has reclaimed and recovered with the minimum of impact. Also recovered were 176 barrels of product that was not spilled to the tundra. In the 100 days after the spill, BP did extensive work on existing transit lines. The lines were pigged and inspected to insure operational integrity. BP built a number of bypasses, five of which are pipeline bypasses in service today to enable BP to quickly restore production to the pre-spill rates. In January, BP delivered over 430,000 barrels of gross oil a day through the system, which is equal to the rates prior to the shutdown. MR. UTSLER said the second commitment was to understand what happened with the corrosion. BP has detailed that mechanism with a number of agencies and third party specialists. BP also committed to initiate a maintenance and smart pigging program for all transit lines across Prudhoe Bay, and it has delivered on its smart pigging expectations and weekly maintenance pigging. The smart pigging is done on the agency-recommended schedule. BP also committed to include all BP-operated transit lines under the Department of Transportation and Public Facilities (DOT) pipeline integrity management program. It has implemented all phase-one commitments, except for one, which will be completed at a later time. A second phase will bring the entire system under the program. 3:42:55 PM MR. UTSLER said the fifth commitment was "that we would create a clear and distinct separation of the responsibilities and accountabilities for the fields operations versus the technical assurance being independent of how we operate the field operated day to day in the BP organization." To do that BP created the technical directorate under Tony Brock, which will provide BP with the strategic planning, technical detail, and the action plans that BP is responsible to execute against everyday. The sixth commitment was that, with partners, BP would continue to identify and approach its major maintenance activities. He said that this year BP plans to spend over $195 million in maintenance repair operations, and this is four times the level of spending in 2004. The seventh commitment was that BP will be extremely open and transparent and work with regulators to look at industry standards and best practices in order "to insure that together we develop, where necessary, the right regulatory expectations and guidelines for how we can manage this process for the future and hopefully ensure with absolute certainty that we can continue to deliver on that promise we're making, which is for the next fifty-plus years keep the product in the pipe, deliver it day in and day out to our customer base for the benefit of the state of Alaskans, certainly our company, and the working-interest owners that are participating with us." 3:45:44 PM MR. UTSLER said BP has made amazing progress. He spoke of the impressive, world-class response from BP, contractors, service providers, agency personnel, and technical experts. 3:47:06 PM SENATOR WAGONER asked how many feet of pipe were bypassed. MR. UTSLER said three miles on the west end and three miles on the east end. He said what BP calls the "gathering center two to one" pipe to the flow station have been bypassed. There are other bypasses installed but not used, which would allow for a short response to a future event while retaining the majority of the production flow in the field. SENATOR WAGONER asked about the size of the bypass pipe. 3:48:18 PM MR. UTSLER said BP downsized in the temporary bypasses, "which are…able to be operated for an extended period of the field's life." They have smaller capacity and "have had minor impacts to our abilities to flow the west side of the field. But these are very small impacts at this stage." SENATOR WAGONER said his staff reviewed Steve Marshall's testimony, and he asked how often BP will smart pig. 3:49:23 PM MR. UTSLER said it will be discussed in detail, but briefly, BP is working with agencies on a planned scheduled. Mechanical pigging is weekly, and ultrasonic testing is ongoing, which is the most accurate way to measure the thickness of the wall of the pipe. The intent is to smart pig yearly. BP has pigged the line twice with intelligent pigs after August 2006 and will repeat it in 2007. SENATOR STEDMAN asked Mr. Utsler to compare historical expenditures against the projected ones and what impact the PPT [profit-based petroleum tax of 2006] has on that change. MR. UTSLER said he cannot answer the second part of the question because he doesn't have that knowledge, and it's not his area of responsibility. His job is to develop the resources, and others work on taxes. The company is undergoing a massive redevelopment of maintenance strategies. He expects that expenses will stay at the current level or increase, and they will depend on what needs to be spent to keep the product in the pipe. CHAIR HUGGINS asked Mr. Utsler what "field" really means and the things that are under that designation. MR. UTSLER said his day to day responsibilities are "drilling and development of new wells, the repairing of existing wells as they need additional repairs or require stimulation to improve productivity performance, through the physical operation of producing from the reservoir, through the well bores, through the surface facilities and into the pipeline systems taking it to the customer. I'm responsible, and my organization, for that day-to-day activity set that not only delivers today's product but also is planning for the future, for this 50 years and what's required in terms of new infrastructure, new facilities, and how that works." MR. UTSLER said Mr. Brock's responsibility is to report independently to BP Alaska's president and "to create the strategic planning and technical evaluation of what do we need to do and what should we be doing to create that assurance in our operations my teams execute against that plan." 3:53:40 PM CHAIR HUGGINS asked if Mr. Brock just gives Mr. Utsler a copy and doesn't coordinate with Mr. Utsler. MR. UTSLER said it is totally independent, and under the commitment that BP made in August, "if his team and his technical experts say that we are not operating within those guidelines, he shuts us down, not me." CHAIR HUGGINS asked how the $195 million is apportioned. 3:54:19 PM MR. UTSLER said the budgets are broken down into different activity sets. BP works with its partners to approve the levels of activity. The field is the big expense, he said, and Mr. Brock's team "is working to deliver the plans that we then need to execute. The execution is where the operations are, at the end of the day, accountable in the line for delivering on those plans. But his challenge is to ensure that I'm informed and that our organization understands what it means to comply with the law and the requirements associated with that, conform with the standards of both industry, state, and BP's own technical standards." CHAIR HUGGINS asked if both positions existed before [the spill]. MR. UTSLER said his position did exist and that person "had the totality of our technical, as well as our operational, experiences. Post August, the organization was created, called the technical directorate, in which Tony is responsible for his team's efforts on what I've described previously." 3:55:51 PM SENATOR WIELECHOWSKI asked if the past practices were deficient. MR. UTSLER said he can't respond to past practices, but his job is to learn from all past experiences and apply them to the future in order to keep the product in the line. SENATOR WIELECHOWSKI asked for Mr. Utsler's evaluation of the program before the new policies and procedures were implemented. He asked if they were comparable with industry standards. "Were they adequate, in you opinion?" MR. UTSLER said, "My initial learnings over the first six weeks of our businesses is that this is a remarkable piece of operations with some remarkable peoples doing their very best to do a great job. I think that my own personal evaluations of our practices and processes--I'm still learning to understand what we've done in the past, where do we need to go in the future, and working with Tony and the technical directorate to ensure that we've taken those lessons learned and, again, apply them to the future in our operations." He said it is the only answer that he can offer after six weeks on the job. 3:57:35 PM SENATOR STEDMAN noted that there have been discussions recently on the status of Prudhoe Bay and that there may be a lot of life left in the oil fields. "If that's…true, with your maintenance schedule that you're going to put forward and changing pipe size--lowering the capacity, I assume, by running smaller pipe, is the structure of the basin going to be capable of expanding if the PPT is successful and we get more drilling and exploration…Or are we going to be in a position where the field has been restructured to size, volumes, that are expected today, without a positive impact from PPT?" MR. UTSLER said he has worked many mature basins, and some produce after 100 years. Prudhoe Bay is mature in terms of the existing reservoirs to be developed, but it has a huge life remaining. "It has years and years and years of forward potential." He said BP is looking at how to optimize the light oil recovery component of greater Prudhoe Bay and to expand viscous crude production from the western sides of the fields. He said BP wants to get into heavy oil, which is a significant resource for the long term, and then "the gas blow-down phases of the ultimate field depletion strategy." There are over 50 years in the mature basin environment. "We're building that future of those four differing phases of potential upside and ongoing operations into that plan." Prudhoe Bay is a phenomenal resource and opportunity, "and it's our job to steward that development in a safe, efficient, and effective way." 4:01:02 PM TONY BROCK, Technical Director, BP Alaska, said he had his position since August 2006, and he has worked 20 years for BP in Southeast Asia, the North Sea, and the Gulf of Mexico. He said he is aware of and excited about the challenges of Alaska's mature fields. The technical directorate is a new organization that reports to the president of BP Alaska. Its role is "to develop our petrochemical capability and manage that shared resource across BP's assets in the North Slope." It is also "to provide and drive strategic plans and direction for the development of our operating systems, our practices, our codes and our organizational construct." And the most important role is to provide independent verification that operations are done under codes and regulations, he stated. 4:02:56 PM CHAIR HUGGINS suggested he is an "inspector general." MR. BROCK said that is correct in principle. Mr. Brock did a slide presentation and showed a map of transit lines. He noted that GC stands for gathering center in the western part of the field, and FS means field station for the eastern side. He said that the line is 16 miles from GC2 to FS2. The east and west come at skid50, where the crude comes together from the greater Prudhoe Bay field before going to pump station one, which is at the start of the TAPS system. A leak occurred between GC2 and GC1 in March, he stated, and in August, a leak was identified between FS2 and FS1. Those two sections of line are now out of service, and the section between GC2 and GC1 is being decommissioned. The other will be decommissioned in 2008. 4:05:31 PM MR. BROCK spoke of BP's activities within 100 days after the spill. It stripped over 43,000 feet of pipe to get access to lines to carry out 22,000 ultrasonic inspections. The company installed five new pipeline bypass systems to reestablish production. BP also de-canted and de-oiled the suspended sections of line between FS2-1 and GC2-1, which allowed it to do 34 hot taps and decant the oil into tankers and then into the export system. It installed a new pig launcher at GC1, and ran six cleaning pigs, including two smart pigs from FS1 to skid50. The two smart pigs provided 100 percent data recovery, he said. In the western operating area, BP ran six cleaning pigs, one gauge pig, and two smart pigs. He said BP restarted FS2 through a bypass to the Endicott pipeline system. He said the support from the regulatory agencies was appreciated, and BP was allowed to put forward its permits and commercial agreements with its partners to deliver the bypasses in a timely manner. As part of the investigation into the root cause of the failure, BP recovered two 40-foot sections of 34-inch pipe--one from each area--and underwent in-depth analyses to determine the specific mechanism associated with the corrosion. 4:08:22 PM MR. BROCK said BP shut down and restarted seven major production facilities, and in October had reestablished production numbers to the numbers prior to the August shut down. He showed a diagram illustrating the transit line system and the bypass lines, some of which are not commissioned but can be put in place in a matter of days rather than weeks. 4:10:01 PM MR. BROCK said BP is still trying to determine the actual cause of the leaks. There are three causal factors: water in the system, sediment, and bacteria. The fourth factor is reduced velocities. The lines were designed for a much greater flow rate, so the reduced velocity allows for sediment to fall out and contribute to the corrosion. BP will add a corrosion inhibitor to mitigate the effects of carbon dioxide. To address stagnant water or sediment buildup in the lines, BP is running weekly maintenance pigs and looking at the solids for bacteria growth, scale, and metallurgy. He said there has been little or no solids returned from the weekly pigging, but they are beneficial because they actually clean the inside of the pipe, remove any residual water, and provide a clean surface for the biocides that interface with the pipe. Those activities allow BP to notice any changes in the pipe and intervene as needed. The company has run over 22,000 ultrasonic inspections, and they are repeated every three months at known areas of corrosion. He said a new smart pig will be run within a year. 4:12:46 PM MR. BROCK showed a picture of ultrasonic inspection work on the 34-inch line during the summer. The work is conducted in the winter too, but it is challenging because most lines are under two or three feet of snow. He showed a picture of a sophisticated, smart pig. Maintenance pigs clean debris from the system, but smart pigs are electromagnetic sensor tools that touch 100 percent of the pipe and give an indication of where corrosion is. It works best in conjunction with ultrasonic inspections, an operation unique to Prudhoe Bay. Most pipelines are buried and inaccessible, but Prudhoe Bay pipe is above the tundra, so the ultrasonic follow-up can be done. 4:14:41 PM MR. BROCK showed an illustration of the removal of pipe to determine the root cause of the corrosion. As BP replaces the OTL [oil transit line] system, causes of corrosion need to be understood in order to design and manage the system. He said BP has an extensive surveillance program with four daily infrared inspections of the lines, and every day BP covers 80 miles of lines. There are daily infrared flights, and BP has added two 25-person shifts since August. The company has trained personnel in forward looking infrared with rigorous reporting procedures. 4:16:09 PM MR. BROCK showed an overview of the system, and BP's plans are to replace the system with a brand new, totally redesigned, transit line system for the 40 to 50-year life of the field. CHAIR HUGGINS asked the total miles that BP is monitoring. MR. BROCK said 60 miles are monitored in this section. Each transit line system will be sized for the projected growth of the field. BP has incorporated the production profiles with the life of the field and has actually sized the pipe for optimum production and management of flow conditions. There will be the capability to regularly launch pigs, corrosion inhibitor will be added continuously, 20 new modules and skids will be added, and the best available leak detection system will be added. 4:19:19 PM MR. BROCK said the leak detection system will be more reliable and incorporate new turbine flow meters, ultrasonic meters, and new "ATMOS" software to manage the readouts. He said BP will add a new "LEOS" pilot between GC2 and GC1, allowing detection of small leaks similar to the leaks from last summer. The pipeline will be designed to the specifications of DOT 49 CFR 95 and a 30-year life. "In addition we will be designing out of the system some of the characteristics that we feel contributed to the corrosion during 2006, namely we'll try and avoid, where possible, caribou crossings that cause dips in the line." The line will be elevated to four feet for access, he said. CHAIR HUGGINS said TAPS staff said the difficulty is the rate of flow, and he asked if that caused some of the problems. MR. BROCK said low velocities allowed sediment to fall out, and he thinks that was a contributing factor. CHAIR HUGGINS asked what the optimum velocity is. MR. BROCK said three feet per second, so BP is sizing the pipe for the forecasted declining production rates. 4:21:58 PM CHAIR HUGGINS asked if different pigs are used for small pipes. MR. BROCK said yes, and he showed a typical pig launcher module to be designed and constructed using Alaskans and installed next winter. They have to be accessible and operated year round. 4:23:01 PM MR. BROCK said the renewal program includes replacing two segments in 2007 and two in 2008. The module work will take longer, but the current goal is installing the entire system by the end of 2008. BP got assistance from the agencies and he thanked their efforts. There have been over 22 permits approved, he noted. He showed a detailed overview of the "ATMOS" leak detection system. It is a gas chromatograph system to be attached underneath the pipeline, and it can pick up a hydrocarbon trace. It is new technology. He said the crew is 250 people in addition to slope staff. 4:25:48 PM CHAIR HUGGINS asked about the status of the 250 people. MR. BROCK said the crew that will install the pipelines is about 250 people, and BP has added a 150-person camp to the North Slope facilities and procured 100 extra beds in Deadhorse. They are "cutting their teeth" on the simpler project of replacing a line on the Milne Point oil field. CHAIR HUGGINS asked if it is skilled Alaskan labor. MR. BROCK said yes. 4:26:51 PM CHAIR HUGGINS asked if that system had been in place, would it have detected the difficulties. MR. BROCK said he has only been here for six months and the technical directorate is a new organization. His role is to act as an independent verification body to provide assurance to BP senior management that things are up to BP standards. That independent process is still being established. He said he couldn't answer the question. 4:27:59 PM SENATOR STEVENS asked if the LEOS system could be used in a gas pipeline. MR. BROCK said BP's goal is to test the technology. There is a similar technology on the North Star pipeline, but it is not proven it in the arctic environment. If it is proven, then there may be wider applications for it. SENATOR WIELECHOWSKI asked if the system was up to BP standards before the leak occurred. MR. BROCK said there were robust procedures in place and BP was surprised at the events of 2006, and it is trying to learn from those. "And I think we need to learn from those and put in place additional standards to ensure they don't happen again, but my belief is that we were working within BP standards at the time." 4:29:34 PM CHAIR HUGGINS asked about temperatures and wax. MR. BROCK said there is not much wax buildup in Prudhoe Bay crude. There will be more viscous oil, so it is important to maintain a minimum temperature within the transit line system. The pipe will be insulated, he noted. CHAIR HUGGINS asked if viscous oil is heavy oil. MR. BROCK said viscous if different from heavy. Viscous is moveable, and heavy oil will need different technologies. CHAIR HUGGINS said he hears that Alaska's destiny is heavy oil. Some people in the industry probably have experience in it, and he wants that topic discussed in the future. 4:31:25 PM MR. BROCK said his job is to manage the technology program for the strategic performance unit, and there is a team working on heavy oil technology. CHAIR HUGGINS said the destiny of state revenue is a serious issue. He noted the importance of the partnership with the oil companies and how fragile public confidence is. "We take seriously the public relations piece of it, the environmental piece of it, and, of course, ultimately your making money and us making money on the revenue side matters too. So we say thank you very much." The committee took an at-ease from 4:32:50 PM until 4:37:26 PM. CHAIR HUGGINS noted the presence of Willie Hensley. ^Corrosion overview-DEC JONNE SLEMONS, Acting Coordinator, Petroleum System Integrity Office, said there were five state agencies at the meeting. 4:39:13 PM LARRY DIETRICK, Director, Division of Spill Prevention and Response, Department of Environmental Conservation (DEC), said he will update the committee on the DEC activities since the spill. A number of things have been sorted out regarding jurisdictional issues. At the time of the spill incidents, those 16 miles of transit lines were not under any state or federal regulatory program for corrosion management. The single phase crude oil pipelines that transport the finished product from the production centers to the pump stations are normally regulated by the federal Pipeline and Hazardous Materials Safety Administration. The 16 miles of transit lines were exempted from that, so were not regulated. The state has a single requirement for those lines and that is for a leak detection system. 4:41:42 PM SENATOR WIELECHOWSKI asked if there are any other lines in Alaska that are not covered by state or federal jurisdiction. MR. DIETRICK said the flow lines were not covered, but they are now. "We believe now that the flow lines, facility lines, and the transit lines are all covered." If the lines were a tree, the trunk would be the TAPS, the major branches would be the feeder lines from the production centers, and the branches would be the well lines and the flow lines. Crude oil transit lines are regulated by the federal government, which includes all other similar lines on the North Slope. It is only the 16 miles that were the exception. Since August, Congress passed the Pipeline Inspection Protection Enforcement and Safety Act of 2006, which specifically provides that the lines be included under federal regulation. Under that act, the office of pipeline safety must issue low stress regulations by the end of this year and complete a leak detection technology study. So the 16 miles of lines are now consistent with all other lines and will be regulated into the future. 4:43:55 PM MR. DIETRICK showed a schematic of pump station one and the TAPS. The trunk lines are now all regulated by the federal office of pipeline safety. Upstream from the processing facility will be regulated by the state. The state completed adoption of the regulations with phased implementation dates, which will cover the lines that come from the processing facilities up to the well pads. The Alaska Oil and Gas Conservation Commission (AOGCC) has jurisdiction over the wellhead, and the well lines will also be covered by the new DEC regulations. 4:45:35 PM MR. DIETRICK said the flow lines tend to be more corrosive because it is prior to the separation of the water and gas. He said the Department of Law reviewed all the state's pipeline authorities. "We did look at these multiphase flow lines and the well lines upstream from the production facilities, and, as well, related, what we call facility piping." Those were all captured in DEC's regulatory package that is now in place. The state has one remaining requirement on the single phase pipeline, and that is a leak detection requirement, which is an overlap with the federal government. 4:47:21 PM MR. DIETRICK said the single phase lines must meet the state's leak detection performance standard, and BP is proposing a modified system for the new pipe. The leak detection system was in place and operational at the time of these events. 4:48:18 PM MR. DIETRICK said the state regulations will be in effect in 2009, and the operations and maintenance will kick in at the end of this year. The flow lines can be up to 30 inches, and he showed a picture of a Kuparuk pipeline that also had a failure this summer and was replaced. He showed a table of the three types of pipelines. The crude oil transmission pipelines are the single phase pipelines and are 6 to 48 inches inside, and there is a single state regulatory requirement on those pipelines for the leak detection system that must meet one percent of the daily throughput. The rest of the standards are all covered by the federal government. The flow lines of facility oil piping are not covered by the federal government. "The jurisdictional thing is actually hand in glove; it's a good fit. Basically the state covers upstream; the federal government covers downstream of the production facilities, and we both have a leak detection requirement, but they're consistent and not in conflict." CHAIR HUGGINS asked if state regulations have been developed. 4:50:39 PM MR. DIETRICK said the rules have been completed and adopted. A compliance inspection program is being developed to implement those rules. CHAIR HUGGINS asked if he is confident with the schedule. MR. DIETRICK said yes, the compliance schedule is set in the rule making. He showed a photo of the spill site. The DEC is establishing a job class for the state for a corrosion engineer for the flow line inspection program. It is developing review criteria, and there will be pipeline inspection training given by the industry. The legal review of the authorities has been completed. There were technology conferences on pigging, and there is a current National Association of Corrosion Engineers meeting with a pipeline integrity course going on in Anchorage. The DEC is participating in an investigation of the specific cause of the corrosion, and it is coordinating with other agencies through a state pipeline technical team. It is exploring additional training that focuses on education under the federal pipeline rules, and it is reviewing federal rules. 4:53:31 PM MR. DIETRICK said DEC will deal with design and construction standards, preventative maintenance, removal-from-service requirements, compliance recordkeeping, baseline assessment to establish initial pipe condition, corrosion and erosion monitoring inspection, internal and external measurements of pipe wall thickness, industry standards identified in the regulations, fitness for service standards, and rules for process monitoring for water cut, microbes, velocities, and corrosivity. There are about 200 miles of single phase transit lines on the North Slope, and there are over 1500 miles of flow lines and facility piping. He said DEC is collaborating with DNR in the enhanced state integrity oversight for oil and gas infrastructure, and it is participating in a detailed gap analysis of the structures on the North Slope. 4:55:17 PM MR. DIETRICK pointed out to a diagram of what is regulated in the pipeline system and if there are any gaps. CHAIR HUGGINS asked if anyone ever noted the lack of upstream state oversight. 4:56:31 PM CATHY FOERSTER, Commissioner, Alaska Oil and Gas Conservation Commission, said the type of lines that the state is talking about regulating now are not regulated in any of the other 49 states. This is inside the company-owned facilities or field infrastructure, and one would assume it is in the operators' interest "to maintain his own stuff, and you stay out of his business as far as maintenance." She said, "It's not that we had a gap, it just hasn't been done before. It would be kind of like somebody regulating how often you change the oil in your car." But the state of Alaska cares, and there is the need to step in. SENATOR WIELECHOWSKI said there are 800 miles of line and it seems odd that the only portion that fails is the portion that is not regulated. He noted unregulated areas in the DEC diagram and asked if the speakers feel comfortable that these do not need to be regulated. 4:58:25 PM MR. DIETRICK said the diagram is the specific DEC regulatory requirements. Other agencies will look at their jurisdictional authorities. This is the first step in identifying gaps. CHAIR HUGGINS said the presentation will continue on Monday and adjourned the meeting at 5:00:25 PM.